UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934(Mark One)
| 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 2007
OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
| ¨ | 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
001-32886
CONTINENTAL RESOURCES, INC.
(Exact
(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
| Oklahoma | 73-0767549 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
| 302 N. Independence, Suite 1500, Enid, Oklahoma | 73701 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (580) 233-8955
Securities registered pursuant tounder Section 12(b) of the Exchange Act: None
| Title of Class | Name of Exchange on Which Registered | |
| Common Stock, $0.01 par value | New York Stock Exchange |
Securities registered pursuant tounder Section 12(g) of the Exchange Act: None
Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d)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 [ ]x 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'sregistrant’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 a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.)Exchange Act). Yes [ ]¨ No [X]x
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked prices of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of March 28, 2004, there were 14,368,919June 30, 2007 aggregate market value was $713,522,464.
As of February 29, 2008, the registrant had 169,073,371 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
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant.
Documentdefinitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Stockholders to be held May 27, 2008, which will be filed with the Commission no later than April 29, 2008 are incorporated by reference: None
CONTINENTAL RESOURCES, INC.
Annual Reportreference into Part III of this Form 10-K.
Glossary of Oil and Natural Gas Terms
The terms defined in this section are used throughout this report:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Bcf.” One billion cubic feet of natural gas.
“Boe.” Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
“Basin.” A large natural depression 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 TOearth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development well.” 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 well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Enhanced recovery. 39
SIGNATURES ................................................................ 41
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain” The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the statementsnatural pressure.
“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in this Form 10-K are "forward-looking statements"a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
“Infill wells.” Wells drilled into the same pool as definedknown producing wells so that oil or natural gas does not have to travel as far through the formation.
“MBbl.” One thousand barrels of crude oil, condensate or natural gas liquids.
“Mcf.” One thousand cubic feet of natural gas.
“MBoe.” One thousand Boe.
i
“MMBoe.” One million Boe.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“NYMEX.” The New York Mercantile Exchange.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in Section 27A100 acres owns 50 net acres.
“PUD.” Proved undeveloped
“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities Act and Section 21ESEC. PV-10 is a non-GAAP financial measure.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the Securities
Exchange Actproduction exceed production expenses and taxes.
“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved reserves.” The estimated quantities of 1934, as amended (the "Exchange Act")oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
“Proved undeveloped reserves (PUD).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Standardized Measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Waterflood.” The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.
ii
“Wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Cautionary Statement Regarding Forward-Looking Statements
This report contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical factsfact included in this Form 10-K, including without
limitationreport, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Except as otherwise specifically indicated, these statements assume no significant changes will occur in the operating environment for oil and natural gas properties and the there will be no material acquisitions, divestitures or financings except as otherwise described.
Forward-looking statements may include statements about our:
business strategy;
reserves;
technology;
financial strategy;
oil and natural gas realized prices;
timing and amount of future production of oil and natural gas;
the amount, nature and timing of capital expenditures;
drilling of wells;
competition and government regulations;
marketing of oil and natural gas;
exploitation or property acquisitions;
costs of exploiting and developing our properties and conducting other operations;
general economic conditions;
uncertainty regarding our future operating results; and
plans, objectives, expectations and intentions contained in this report that are not historical.
All forward-looking statements speak only as of the date of this report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Item 1. Business," "Item 2. Properties"“Item 1A.—Risk Factors” and "Item“Item 7. Management's—Management’s Discussion and Analysis of Financial Condition and Results of Operations" regarding budgeted capital expenditures, increasesOperation” and elsewhere 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 suchthis report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
iii
You should read this entire report carefully, including “Risk Factors” and our historical consolidated financial statements and the notes to those historical consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “we,” us,” “our,” “ours” or “company” refer to Continental Resources, Inc.
| Item 1. | Business |
We 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 provedan independent 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, testingexploration 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, primarilycompany with operations in the Rocky Mountain, Mid-Continent and Mid-ContinentGulf Coast 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.States. We were originally formed in 1967 to explore, develop and produce oil and natural gas properties in Oklahoma.properties. 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%Approximately 82% of our estimated proved reserves as of December 31, 20032007 are now foundlocated in the Rocky Mountain region. Our growthWe completed an initial public offering of our common stock on May 14, 2007, and began trading on the New York Stock Exchange on May 15, 2007 under the ticker symbol “CLR”.
We focus our exploration activities in large new or developing plays that provide us the Gulf Coast region duringopportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the mid-1990's
was slowed duemeans to the rapid growtheconomically develop and produce oil and natural gas reserves from unconventional formations. As a result of the Rocky Mountain region. Since 1999,these efforts, we have increased our drilling activity ingrown substantially through the Gulf Coast regiondrillbit, adding 89.0 MMBoe of proved oil 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 andnatural gas reserves through the exploration, development,
exploitationextensions and acquisitiondiscoveries from January 1, 2003 through December 31, 2007 compared to 0.9 MMBoe added through proved reserve purchases during that same period.
As 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% ofDecember 31, 2007, 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 ourwere 134.6 MMBoe, with estimated proved developed 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,101.2 MMBoe, 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%75% 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%Crude oil comprised 77% of our total estimated proved reserves,
6%reserves. For the year ended December 31, 2007, we generated revenues of $582.2 million, and operating cash flows of $390.6 million. For the year and quarter ended December 31, 2007, daily production averaged 29,099 and 30,369 Boe per day, respectively. This represents growth of 18% and 15% as compared to the year and quarter ended December 31, 2006, when daily production averaged 24,706 and 26,503, respectively.
The following table summarizes our total estimated proved gas reserves, PV-10 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.
Substantial2007, average daily production for the three months ended December 31, 2007 and Diversified Drilling Inventory. Wethe reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 2007 are active in seven
different geologic basins in 11 statesbased primarily on a reserve report prepared by Ryder Scott Company, L.P., our independent reserve engineers. In preparing its report, Ryder Scott Company, L.P. evaluated properties representing approximately 85% of our PV-10. Our technical staff evaluated properties representing the remaining 15% of our PV-10.
| At December 31, 2007 | Average daily Production fourth quarter 2007 (Boe per day) | Percent of Total | Annualized reserve/ production index(2) | ||||||||||||||
| Proved reserves (MBoe) | Percent of total | PV-10(1) (in millions) | Net producing wells | ||||||||||||||
Rockies: | |||||||||||||||||
Red River units | 67,856 | 50 | % | $ | 1,991 | 233 | 14,374 | 47 | % | 12.9 | |||||||
Bakken field | |||||||||||||||||
Montana Bakken | 27,132 | 20 | % | 713 | 83 | 7,244 | 24 | % | 10.3 | ||||||||
North Dakota Bakken | 6,058 | 5 | % | 149 | 21 | 1,382 | 5 | % | 12.0 | ||||||||
Other | 8,920 | 7 | % | 208 | 224 | 1,600 | 5 | % | 15.3 | ||||||||
Mid-Continent: | |||||||||||||||||
Arkoma Woodford | 8,919 | 7 | % | 138 | 16 | 1,338 | 4 | % | 18.3 | ||||||||
Other | 15,452 | 11 | % | 319 | 712 | 3,767 | 13 | % | 11.2 | ||||||||
Gulf Coast | 278 | 0 | % | 10 | 17 | 664 | 2 | % | 1.1 | ||||||||
Total | 134,615 | 100 | % | $ | 3,528 | 1,306 | 30,369 | 100 | % | 12.1 | |||||||
| (1) | PV-10 is a non GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. The Standardized Measure at December 31, 2007 is $2.6 billion, a $0.9 billion difference from PV-10 because of the tax effect. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. |
| (2) | The Annualized Reserve/Production Index is the number of years proved reserves would last assuming current production continued at the same rate. This index is calculated by dividing annualized fourth quarter 2007 production into the proved reserve quantity at December 31, 2007. |
The following table provides additional information regarding our key development areas:
| Developed acres | Undeveloped acres | Gross wells planned for drilling in 2008 | Capital Expenditures (in millions)(1) | ||||||||||
| Gross | Net | Gross | Net | ||||||||||
Rockies: | |||||||||||||
Red River units | 144,487 | 129,168 | — | — | 40 | $ | 168 | ||||||
Bakken field | |||||||||||||
Montana Bakken | 78,003 | 60,074 | 86,488 | 64,536 | 17 | 55 | |||||||
North Dakota Bakken | 46,968 | 24,546 | 553,516 | 271,667 | 74 | 125 | |||||||
Other | 58,881 | 44,480 | 301,980 | 176,250 | 20 | 29 | |||||||
Mid-Continent: | |||||||||||||
Arkoma Woodford | 41,216 | 8,625 | 104,001 | 35,759 | 139 | 103 | |||||||
Other | 136,214 | 93,567 | 296,908 | 179,448 | 57 | 46 | |||||||
Gulf Coast | 41,010 | 11,869 | 16,205 | 5,472 | 9 | 21 | |||||||
Total | 546,779 | 372,329 | 1,359,098 | 733,132 | 356 | $ | 547 | ||||||
| (1) | Capital expenditures budgeted for 2008 but excludes budgeted amounts for land of $39 million, seismic of $17 million, and $13 million for vehicles, computers and other equipment. |
Our goal is to increase shareholder value by finding and have identified 206developing crude oil and natural gas reserves at costs that provide an attractive rate of return on our investment. The principal elements of our business strategy are:
Focus on Oil.During the late 1980’s we began to believe that the valuation potential drilling locations based on geologicalfor crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and geophysical evaluations.production profiles towards crude oil. As of December 31, 2003,2007, crude oil comprises 77% of our total proved reserves and 82% of our 2007 annual production. Although we held approximately 755,000 net leasehold acres,do pursue natural gas opportunities, we continue to believe that crude oil valuations will remain superior to natural gas valuations on a relative Btu basis.
Growth Through Low-Cost Drilling. Substantially all of which
approximately 63% were classified as undeveloped. Our management believes that
our current inventoryannual capital expenditures are invested in drilling projects and acreage holdings could support three to five years of
drilling activities depending uponand seismic acquisitions. From January 1, 2003 through December 31, 2007, proved oil and natural gas prices.
Long-Life Naturereserve additions through extensions and discoveries were 89.0 MMBoe compared to 0.9 MMBoe of Reserves.proved reserve purchases.
Internally Generate Prospects. Our producing reserves are primarily
characterized by relatively stable, mature production that is subject to gradual
decline rates. As a resulttechnical staff has internally generated substantially all of the long-lived natureopportunities for the investment of our properties,capital. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than those of later entrants into a developing play.
Focus on Unconventional Oil and Natural Gas Resource Plays. Our experience with horizontal drilling, advanced fracture stimulation and enhanced recovery technologies allows us to commercially develop unconventional oil and natural gas resource plays, such as the Red River B dolomite, Bakken Shale and Arkoma Woodford formations. Production rates in the Red River units also have relatively low reinvestment requirements to maintain reserve quantitiesbeen increased through the use of enhanced recovery technology. Our production from the Red River units, the Bakken field, and the Arkoma Woodford comprised approximately 8,310 MBoe, or 78% of our total oil and natural gas 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. Duringduring the five yearsyear ended December 31, 2003,2007.
Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 465,207 net undeveloped acres held in the Montana and North Dakota Bakken shale and Arkoma Woodford fields, we participatedheld 171,475 net undeveloped acres in 282 gross wellsother oil and natural gas shale plays as of which 83% were completedDecember 31, 2007. Our technical staff is focused on identifying and testing new unconventional oil and natural gas resource plays where significant reserves could be developed if commercial production rates can be achieved through advanced drilling, fracture stimulation and enhanced recovery techniques.
We have a number of strengths that we believe will help us successfully execute our strategies:
Large Acreage Inventory. We own 733,132 net undeveloped and 372,329 net developed acres 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
developmentDecember 31, 2007. Approximately 72% of the Cedar Hills field; $20.5 million drilling injectionundeveloped acres are found within unconventional shale resource plays including the Bakken shale in North Dakota and Montana and the Woodford shale in southeast Oklahoma. The balance of the locations and undeveloped acreage is found in other emerging unconventional resource plays including the Woodford and Atoka of western Oklahoma and the Red River of South Dakota as well as more conventional plays including 3D defined locations for the Trenton-Black River of Michigan, Red River of Montana, and Frio in South Texas.
Horizontal Drilling and Enhanced Recovery Experience. In 1992, we drilled our initial horizontal well, and we have drilled over 460 horizontal wells since that time. We also have substantial experience with enhanced recovery methods 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. Duringcurrently serve as the same period, we acquired 13.2 MMBoe at an average costoperator 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 that48 waterflood units. Additionally, 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 utilizeeight high pressure air injection enhanced recovery technology
on(“HPAI”) floods in the United States.
Control Operations Over a large scale. ThroughSubstantial Portion of Our Assets and Investments. As of December 31, 2007, we operated properties comprising 93% of our PV-10. By controlling operations, we are able to more effectively manage the usecost and timing of precision horizontal drilling we have
experienced a 400% to 700% increase in initial flow rates. Sinceexploration and development of our inception,
we have drilled approximately 250 horizontal wells in our Rocky Mountain and
Mid-Continent regions. Throughproperties, including 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.
fracture stimulation methods used.
Experienced and Committed Management.Management Team. Our senior management team has extensive expertise in the oil and gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our eightseven senior officers have an average of 2527 years of oil and gas industry experience. Additionally, our technical staff, which includes 1921 petroleum engineers, 16 geoscientists and 11
geoscientists,10 landmen, has an average of more than 2619 years experience in the industry.
DEVELOPMENT, EXPLORATION AND EXPLOITATION ACTIVITIES
Capital Expenditures.
Strong Financial Position. As of February 29, 2008, we had outstanding borrowings under our credit facility of approximately $222.0 million and available capacity under our selected commitment level of $178.0 million. We expecthave elected to set the commitment level at $400 million, which is below the established borrowing base of $600 million, in order to minimize commitment fees. We believe that our projected capital expenditures forplanned exploration and 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 spentfunded substantially from our operating cash flows and borrowings under our credit facility.
The following tables set forth our estimated proved oil and natural gas reserves, percent of total proved reserves that are proved developed, the PV-10 and standardized measure of discounted future net cash flows as of December 31, 2007 by reserve category and region. Ryder Scott Company, L.P., our subsidiaries on their projected capital
expenditures. Funding for these expenditures will come from a combinationindependent petroleum engineers, evaluated properties representing approximately 85% of cash flowour PV-10, and our credit facility.
Includedtechnical staff evaluated the remaining properties. The year-end weighted average oil and natural gas prices used in our expected capital expenditures in 2004 is $6.1 million for
completionthe computation of the Cedar Hills project, with an estimated project completion date
of April 30, 2004. This will bringfuture net cash flows at December 31, 2007 were $82.86 per barrel and $6.14 per Mcf, respectively.
| December 31, 2007 | |||||||||
| Oil (MBbls) | Gas (MMcf) | Total (MBoe) | PV-10(1) (in millions) | ||||||
Proved developed producing | 78,178 | 126,419 | 99,248 | $ | 2,629 | ||||
Proved developed non-producing | 1,578 | 2,412 | 1,980 | 36 | |||||
Proved undeveloped | 24,389 | 53,988 | 33,387 | 863 | |||||
Total proved reserves | 104,145 | 182,819 | 134,615 | $ | 3,528 | ||||
Standardized measure | $ | 2,582 | |||||||
| Oil (MBbls) | Gas (MMcf) | Total (MBoe) | % Proved developed | PV-10(1) (in millions) | ||||||||
Rockies: | ||||||||||||
Red River units | 62,383 | 32,838 | 67,856 | 81 | % | $ | 1,991 | |||||
Bakken field | ||||||||||||
Montana Bakken | 22,704 | 26,565 | 27,132 | 74 | % | 713 | ||||||
North Dakota Bakken | 5,218 | 5,040 | 6,058 | 59 | % | 149 | ||||||
Other | 7,966 | 5,726 | 8,920 | 73 | % | 208 | ||||||
Mid-Continent: | ||||||||||||
Arkoma Woodford | — | 53,513 | 8,919 | 15 | % | 138 | ||||||
Other | 5,753 | 58,196 | 15,452 | 85 | % | 319 | ||||||
Gulf Coast | 121 | 941 | 278 | 100 | % | 10 | ||||||
Total | 104,145 | 182,819 | 134,615 | 75 | % | $ | 3,528 | |||||
| (1) | PV-10 is a non GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. The Standardized Measure at December 31, 2007 is $2.6 billion, a $0.9 billion difference from PV-10 because of the tax effect. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. |
Developed and Undeveloped Acreage
The following table presents the total HPAI project cost to $119.9
million, including capital leases.
Expenditures on projects outsidegross and net developed and undeveloped acreage by region as 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. December 31, 2007:
| Developed acres | Undeveloped acres | Total | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
Rockies: | ||||||||||||
Red River units | 144,487 | 129,168 | — | — | 144,487 | 129,168 | ||||||
Bakken field | ||||||||||||
Montana Bakken | 78,003 | 60,074 | 86,488 | 64,536 | 164,491 | 124,610 | ||||||
North Dakota Bakken | 46,968 | 24,546 | 553,516 | 271,667 | 600,484 | 296,213 | ||||||
Other | 58,881 | 44,480 | 301,980 | 176,250 | 360,861 | 220,730 | ||||||
Mid-Continent: | ||||||||||||
Arkoma Woodford | 41,216 | 8,625 | 104,001 | 35,759 | 155,906 | 52,371 | ||||||
Other | 136,214 | 93,567 | 296,908 | 179,448 | 422,433 | 265,028 | ||||||
Gulf Coast | 41,010 | 11,869 | 16,205 | 5,472 | 57,215 | 17,341 | ||||||
Total | 546,779 | 372,329 | 1,359,098 | 733,132 | 1,905,877 | 1,105,461 | ||||||
The following table sets forth our development inventorythe number of gross and net undeveloped acres as of December 31, 2003:
2007 that will expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates:
| 2008 | 2009 | 2010 | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
Rockies: | ||||||||||||
Red River units | — | — | — | — | — | — | ||||||
Bakken field | ||||||||||||
Montana Bakken | 54,998 | 38,202 | 14,536 | 11,462 | 6,050 | 5,122 | ||||||
North Dakota Bakken | 122,881 | 54,211 | 228,444 | 115,665 | 110,246 | 49,361 | ||||||
Other | 88,140 | 46,418 | 39,969 | 18,317 | 19,536 | 14,205 | ||||||
Mid-Continent: | ||||||||||||
Arkoma Woodford | 22,170 | 7,379 | 49,064 | 18,069 | 25,112 | 8,767 | ||||||
Other | 53,819 | 25,629 | 22,320 | 16,846 | 181,952 | 111,231 | ||||||
Gulf Coast | 9,561 | 1,989 | 3,200 | 2,443 | 5 | 3 | ||||||
Total | 351,569 | 173,828 | 357,533 | 182,802 | 342,901 | 188,689 | ||||||
Drilling ROCKY MOUNTAIN REGION Locations
--------------Activity
During the three years ended December 31, 2007, we drilled exploratory and development wells as set forth in the table below:
| 2007 | 2006 | 2005 | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
Exploratory wells: | ||||||||||||
Oil | 33 | 15.6 | 17 | 8.4 | 13 | 5.9 | ||||||
Natural gas | 79 | 13.1 | 25 | 4.9 | 2 | 1.3 | ||||||
Dry | 4 | 2.5 | 17 | 9.4 | 11 | 6.9 | ||||||
Total exploratory wells | 116 | 31.2 | 59 | 22.7 | 26 | 14.1 | ||||||
Development wells: | ||||||||||||
Oil | 92 | 69.5 | 83 | 57.0 | 50 | 30.6 | ||||||
Natural gas | 49 | 10.3 | 34 | 14.5 | 15 | 7.6 | ||||||
Dry | 5 | 1.1 | 7 | 4.3 | 3 | 3.0 | ||||||
Total development wells | 146 | 80.9 | 124 | 75.8 | 68 | 41.2 | ||||||
Total wells | 262 | 112.1 | 183 | 98.5 | 94 | 55.3 | ||||||
As of December 31, 2007, there were 26 gross (12.7 net) development wells and 42 gross (19.9 net) exploratory wells in the process of drilling.
As of February 29, 2008, we operated 15 rigs on our properties and have plans to add additional rigs during the year. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. See “Risk Factors—The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.”
Summary of Oil and Natural Gas Properties and Projects
Rocky Mountain Region
Our properties in the Rocky Mountain region represented 87% of our PV-10 as of December 31, 2007. During the three months ended December 31, 2007, our average daily production from such properties was 22,365 net Bbls of oil and 13,409 net Mcf of natural gas. Our principal producing properties in this region are in the Red River units, the Bakken field and the Big Horn Basin.
Red River Units
Our Red River units represented 56% of our PV-10 in the Rocky Mountain region as of December 31, 2007 and 58% of our average daily Rocky Mountain region equivalent production for the three months ended December 31, 2007. The eight units comprising the Red River units are located along the Cedar Hills Anticline in North Dakota, South Dakota and Montana and produce oil and natural gas from the Red River “B” formation, a thin, continuous, dolomite formation at depths of 8,000 to 9,500 feet. Our Red River units comprise a portion of the Cedar Hills field, listed by the Energy Information Administration in 2006 as the 13th largest onshore, lower 48 field in the United States ranked by liquid proved reserves.
Cedar Hills Units. The Cedar Hills North unit (CHNU) is located in Bowman and Slope Counties, North Dakota. We drilled the initial horizontal well in the CHNU, the Ponderosa 1-15, in April 1995. As of December 31, 2007, we had drilled 185 horizontal wells within this 49,700-acre unit, with 113 producing wellbores and the remainder serving as injection wellbores. We operate and own a 98% working interest in the CHNU.
The Cedar Hills West unit (CHWU), in Fallon County, Montana, is contiguous to the northern portion of CHNU. As of December 31, 2007, this 7,800-acre unit contained ten horizontal producing wells and five horizontal injection wells. We operate and own a 100% working interest in the CHWU.
In January 2003, we commenced enhanced recovery in the two Cedar Hills units, with HPAI used throughout most of the area and water injected generally along the boundary of the CHNU. Under HPAI, compressed air injected into a reservoir oxidizes residual oil and produces flue gases (primarily carbon dioxide and nitrogen) that mobilize and sweep the crude oil into producing wellbores. In response to the HPAI, water injection and increased density drilling operations, production from the Cedar Hills units increased to 10,869 net Boe per day in December 2007 from 2,185 net Boe per day in November 2003. As of December 31, 2007, the average density in the Cedar Hill units was approximately one producing wellbore per 467 acres. We currently plan to drill 56 new horizontal wellbores and 5 horizontal extensions of existing wellbores in the Cedar Hills units during the next two years, increasing the density of both the producing and injection wellbores. The reduced distance between wells will allow part of the field to be converted from air injection to water injection. This conversion will begin in 2008 and is forecast to lower operating expenses, as water is less costly to inject than air. In 2008, we plan to invest approximately $113 million drilling in the Cedar Hills units.
On August 22, 2007 the Hiland Partners, LP (“Hiland”) Badlands gas plant became operational for the processing and treatment of gas produced from the CHNU and CHWU and Medicine Pole Hills Unit. Under the terms of the November 8, 2005 contract we agree to deliver low pressure gas to Hiland for compression, treatment and processing. Nitrogen and carbon dioxide must be removed from the gas production associated with oil production from the units for the gas production to be marketable. Under the terms of the contract, we pay $0.60 per Mcf in gathering and treating fees, and 50% of the electrical costs attributable to compression and plant operation and receive 50% of the proceeds from residue gas and plant product sales. After we deliver 36 Bcf of gas, the $0.60 per Mcf gathering and treating fee is eliminated. During December 2007, we sold 5,322 net Mcf of natural gas per day.
Medicine Pole Hills Units. The Medicine Pole Hills units (MPHU) are approximately five miles east of the southern portion of the CHNU. We acquired the Medicine Pole Hills unit in 1995. At that time, the 9,600- acre unit consisted of 18 vertical producing wellbores and four injection wellbores under HPAI producing 525 net Bbls of oil per day. We have since drilled 40 horizontal wellbores extending production to the west with the formation of the 15,000-acre Medicine Pole Hills West unit and to the south, with the 11,500-acre Medicine Pole Hills South unit. All three units are under HPAI. We operate and own an average 77% working interest in the three units. Production from the units averaged 1,234 net Bbls of oil and 409 net Mcf of natural gas per day during December 2007. We are currently operating one rig and plan to drill 12 new horizontal wellbores and four horizontal extensions of existing wellbores during the next 18 months, increasing the density of both producing and injection wellbores. We believe these operations will increase production and sweep efficiency. In 2008, we plan to invest approximately $29.0 million for drilling in MPHU.
Buffalo Red River Units. Three contiguous Buffalo Red River units (Buffalo, West Buffalo and South Buffalo) are located in Harding County, South Dakota, approximately 21 miles south of the MPHU. When we purchased the units in 1995, there were 73 vertical producing wellbores and 38 injection wellbores under HPAI producing approximately 1,906 net Bbls of oil per day. We operate and own an average working interest of 95% in the 32,900 acres comprising the three units. From 2005 to 2008, we re-entered 42 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency from the three units. Production for the month of December 2007 was 1,945 net Bbls of oil per day compared to an average of 1,162 net Bbls of oil per day for the first half of 2005. We currently plan to drill 5 horizontal extensions of existing wellbores and 25 new horizontal wellbores in the Buffalo Red River units over the next two years. We believe these operations will increase production and sweep efficiency. In 2008, we plan to invest $23 million for drilling in the Buffalo Red River units.
Bakken Field
Our properties within the Bakken field in Montana and North Dakota represented 28% of our PV-10 in the Rocky Mountain region as of December 31, 2007 and 35% of our average daily Rocky Mountain region equivalent production for the three months ended December 31, 2007. The Bakken formation or “ Bakken shale” as it is often called has become one of the most actively drilled unconventional oil resource plays in the United States with approximately 54 rigs drilling in the play as of February 29, 2008, including 48 in North Dakota and 6 in Montana. The Bakken formation is a Devonian-age shale found within the Williston Basin 29
Cedar Hillsunderlying portions of North Dakota and Montana that contains three lithologic members including the upper shale, middle member and lower shale that combined range up to 130 feet thick. The upper and lower shales are highly organic, thermally mature and over pressured and act as both a source and reservoir for the oil. The middle member, which varies in composition from a silty dolomite, to shalely limestone or sand, also serves as a reservoir and locally is thought to be a critical component for commercial production. Recently, the Three Forks-Sanish formation found immediately under the Lower Bakken Shale has emerged as another potential reservoir that could add significant incremental reserves to the play. These reservoir rocks have inherently low porosity and permeability and depend on natural fracturing and artificial fracture stimulation to produce economically. Horizontal drilling and advanced fracture stimulation technologies have enabled commercial production from this historically non-commercial reservoir. Generally, the Bakken formation is found at vertical depths of 9,000 to 10,500 feet and drilled horizontally on 640 or 1,280-acre spacing with single, dual or triple leg horizontal laterals extending 4,500 to 9,000 feet into the formation. These wells are fracture stimulated to maximize recovery and economic returns. The fracture stimulation techniques vary but are evolving to a more common practice of mechanically diverted stimulations using un-cemented liners and packers which appears to improve rates and recoveries.
Montana Bakken. The Montana Bakken field is listed by the Energy Information Administration as the 15th largest onshore, lower 48 field in the United States ranked by liquid proved reserves. Since drilling our first well in August 2003, we have completed a total of 134 gross (84 net) wells in the field as of December 31, 2007. Our daily average production from these wells was approximately 6,334 net Bbls of oil and 4,814 net Mcf of natural gas during the month of December 2007. The field has been developed exclusively with horizontal drilling and has been substantially drilled on 640-acre spacing. During 2007 we completed 35 gross (25.9 net) wells as we continued to develop and expand the field. Two of these wells successfully demonstrated that development of the field on 320-acre spacing is warranted. These 2 gross (1.3 net) wells were assigned average estimated recoverable reserves of 468 gross MBoe, which exceeded our economic model of 300 MBoe per well. We also successfully demonstrated that 640-acre tri-lateral drilling was an effective technique to expand the economic limits of the field with the completion of 8 gross (6.2 net) tri-lateral wells which were assigned average estimated reserves consistent with our economic model of 250 MBoe per well.
As of December 31, 2007, we held 86,488 gross (64,536 net) undeveloped acres in the Richland County, Montana portion of the Bakken field. We currently have three operated rigs drilling in the field and plan to invest $48.0 million in the drilling of 17 gross (13 net) horizontal Bakken wells in the field during 2008.
North Dakota Bakken.Since drilling our first well in October, 2004, we have completed a total of 54 gross (21 net) horizontal wells in the North Dakota Bakken field as of December 31, 2007. Our daily average production from these 54 wells was approximately 1,351 net Bbls of oil and 820 net Mcf of natural gas during the month of December 2007. Our drilling to date has been primarily exploratory and step-out in nature to evaluate and define areas of economic production for further development on our acreage. As of December 31, 2007, we owned approximately 296,000 net acres preferentially located along the prolific Nesson anticline where fracturing in the Bakken is expected to be enhanced. We accelerated our drilling activity in the field during 2007, completing 38 gross (14.7 net) wells during the year. Twenty seven of these completed wells were located in the central and northern portions of our acreage and were assigned average estimated recoverable reserves of 335 gross MBoe per well, which is in line with our economic model of 315 MBoe per well. During the year, we modified our horizontal drilling and completion design and now drill primarily 1,280-acre spaced, single leg laterals utilizing uncemented liners and packers to mechanically divert the fracture stimulation.
As of December 31, 2007, we held 553,516 gross (271,667 net) undeveloped acres in the North Dakota Bakken field. We currently have six drilling rigs in the field, three of which are operated by Conoco-Phillips through a joint venture. We plan to add three to five operated rigs to the play and invest approximately $105 million in the drilling of 74 gross (20 net) horizontal wells in the North Dakota Bakken field during 2008.
Haley Red River.
Our Haley Red River project is located approximately 12 miles northeast of our Buffalo Red River units located in Harding County, South Dakota. The producing reservoir is the same Red River B dolomite that produces in our Red River units. Here the dolomite occurs at a depth of approximately 9,000 feet and averages 4 to 6 feet thick. The dolomite is widely present and oil saturated and, as in our Red River units, must be drilled horizontally to produce at economic rates. Horizontal wells are typically drilled on 640-acre spacing as single leg laterals and completed open hole without stimulation. As of December 31, 2007 we have completed 4 gross (4 net) horizontal wells with initial rates of up to 419 Boe per well per day. Based on our economic model, we expect to recover approximately 250 MBoe per well. We owned approximately 58,000 net acres as of December 31, 2007 and continue to build acreage in the project. We plan to invest approximately $18 million drilling 9 gross (7.7 net) wells during 2008 in the Haley Red River project.
Big Horn Basin 36
--------------
Totaland Other Rockies
Our wells within the Big Horn Basin in northern Wyoming and other areas within the Rocky Mountain 69
MID-CONTINENT REGIONregion represented 4% of our PV-10 in the Rocky Mountain Region as of December 31, 2007 and 4% of our average daily Rocky Mountain Region equivalent production for the three months ended December 31, 2007. During the three months ended December 31, 2007, we produced an average of 767 net Bbls of oil and 1,060 net Mcf of natural gas per day from our wells in the Big Horn Basin and other areas within the Rocky Mountain region. Our principal property in the Big Horn Basin, the Worland field, produces primarily from the Phosphoria formation. We also have several other projects ongoing in the Rockies including conventional 3D defined Red River and Lodgepole structures in North Dakota and Montana, horizontal Winnipegosis and Fryburg opportunities in North Dakota and the Lewis Shale and Fort Union in Wyoming. We plan to invest $9 million drilling 11 gross (5.1 net) wells in 2008.
Mid-Continent and Gulf Coast Region
Our properties in the Mid-Continent region represented 13% of our PV-10 as of December 31, 2007. During the three months ended December 31, 2007, our average daily production from such properties was 1,613 net Bbls of oil and 20,949 net Mcf of natural gas. Our principal producing properties in this region are located in the Anadarko and Arkoma Basins of Oklahoma, the Michigan Basin and the Illinois Basin.
Anadarko Basin
Our properties within the Anadarko Basin 27
Black Warriorrepresent 40% of our PV-10 in the Mid-Continent Region as of December 31, 2007 and 52% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our wells within the Anadarko Basin 1produce from a variety of sands and carbonates in both stratigraphic and structural traps. In 2008, we plan to invest approximately $18 million in the drilling of 14 gross (10.5 net) wells in the Anadarko Basin.
Illinois Basin
Our properties within the Illinois Basin represent 30% of the PV-10 in the Mid-Continent Region as of December 31, 2007 and 21% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our wells within the Illinois Basin produce primarily crude oil from units comprised of shallow sand formations under water injection. In 2008, we plan to invest approximately $3 million in the drilling of 21 gross (20.6 net) wells in the Illinois Basin.
Arkoma Woodford
The Arkoma Woodford play in Atoka, Coal, Hughes and Pittsburg Counties, Oklahoma has emerged into one of the most active unconventional gas resource plays in the country with 34 rigs drilling in the play as of February 29, 2008. We owned approximately 145,000 gross (44,000 net) acres in the Woodford play as of December 31, 2007. Since drilling our first well in February, 2006, we have completed a total of 132 gross (16.1 net) horizontal Woodford wells as of December 31, 2007. The majority of this drilling occurred in 2007 with 110 gross (14.8 net) horizontal wells completed during the year. These Arkoma Woodford wells represent 30% of the PV10 in the Mid-Continent Region as of December 31, 2007 and 26% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our drilling has been primarily focused on exploration and step-out drilling to secure leases and delineate areas of economic production for development. This drilling has been conducted primarily on 640-acre spacing but is expected to be ultimately drilled more densely. Recent testing by other operators in the play indicated it may be economic to drill the Woodford on 80-acre and possibly 40-acre spacing.
We plan to invest approximately $93 million in the drilling of 139 gross (19.9 net) horizontal wells in the Arkoma Woodford during 2008. We currently have four operated rigs in the play and plan to add two more rigs by mid-year. Most of our operated drilling activity in 2008 will focus on development and step-out opportunities.
Michigan Trenton-Black River
Our Trenton-Black River project in and around Hillsdale County, Michigan continues to produce excellent results. Guided by innovative 3D seismic techniques, we have experienced 100% success completing 3 gross (2.5 net) operated wells in the project. Our initial discovery well, the McArthur 1-36 (83% WI) has been assigned gross proved reserves of 824,000 barrels of crude oil equivalent. Our second well, the Anspaugh 1-1 (83% WI) encountered similar type pay and was flow testing at a rate of approximately 200 Bopd on March 3, 2008. Our third well, the Wessel 1-6 (83% WI) was flow testing at a rate of approximately 200 Bopd on March 3, 2008. Testing will continue on the Anspaugh 1-1 and Wessel 1-6 to establish reservoir characteristics and estimated reserves. We have also participated in 2 gross (0.6 net) non-operated Trenton-Black River tests. The Clark 1-36 (21%WI) is testing very low volumes of oil. The Young 10-34 (42%WI) encountered encouraging shows while drilling and is currently waiting on completion. We own approximately 29,000 gross (23,000 net) acres in the play and have shot, processed and interpreted 11 square miles of 3D seismic on the acreage so far. We are currently permitting 5 --------------
Totaladditional wells and will begin acquisition of 20 square miles of new 3D data in March with plans to acquire additional data later this year.
Other Mid-Continent 33
GULF COAST REGION
Texas 22
Louisiana 1
During 2007 our geoscientists identified two new potential unconventional resource opportunities in the Mid-Continent region. Details of these opportunities have not been disclosed to minimize competition as we are in the process of acquiring leases. As of December 31, 2007 we had acquired 17,000 net acres. We plan to invest approximately $20 million drilling 19 gross (7.1 net) wells on these and other emerging opportunities in the Mid-Continent region in 2008.
Gulf of Mexico 0
--------------
TotalCoast
During the three months ended December 31, 2007, our average daily production from our Gulf Coast 23
TOTAL 125
Exploration Activities.properties was 330 net Bbls of oil and 2,004 net Mcf of natural gas. Our exploration projectsprincipal producing properties in this region are designedlocated in South Texas and Louisiana. In 2008, we plan to locate new
reservesinvest approximately $18.0 million in the drilling of 9 gross (5.4 net) wells in the Texas and fieldsLouisiana Gulf Coast.
The following table sets forth summary information concerning our production results, average sales prices and production costs for future growththe years ended December 31, 2007, 2006 and development. Our exploration projects
vary in risk and reward based on their depth, location and geology. We routinely
use the latest in technology, including 3-D seismic, horizontal drilling and new
completion technologies to enhance our exploration projects. We intend to
continue to build exploratory inventory throughout the year for future drilling.
2005:
| Year ended December 31, | |||||||||
| 2007 | 2006 | 2005 | |||||||
Net production volumes: | |||||||||
Oil (MBbls)(1) | 8,699 | 7,480 | 5,708 | ||||||
Natural gas (MMcf) | 11,534 | 9,225 | 9,006 | ||||||
Oil equivalents (MBoe) | 10,621 | 9,018 | 7,209 | ||||||
Average prices(1): | |||||||||
Oil ($/Bbl) | $ | 63.55 | $ | 55.30 | $ | 52.45 | |||
Natural gas ($/Mcf) | 5.87 | 6.08 | 6.93 | ||||||
Oil equivalents ($/Boe) | 58.32 | 52.09 | 50.19 | ||||||
Costs and expenses(1): | |||||||||
Production expense ($/Boe) | $ | 7.35 | $ | 6.99 | $ | 7.32 | |||
Production tax ($/Boe) | 3.13 | 2.48 | 2.22 | ||||||
General and administrative ($/Boe) | 3.15 | 3.45 | 4.34 | ||||||
DD&A expense ($/Boe) | 9.00 | 7.27 | 6.91 | ||||||
| (1) | Oil sales volumes are 221 MBbls and 21 MBbls less than oil production volumes for the years ended December 31, 2007 and 2006, respectively, due to temporary storage and pipeline line fill. Average prices and per unit costs have been calculated using sales volumes. |
The following table sets forth information pertaining toregarding our existing
exploration project inventory ataverage daily production during the fourth quarter of 2007:
| Fourth Quarter 2007 | ||||||
| Oil (Bbls) | Gas (Mcf) | Total (Boe) | ||||
Rockies: | ||||||
Red River units | 13,520 | 5,121 | 14,374 | |||
Bakken field | ||||||
Montana Bakken | 6,433 | 4,866 | 7,244 | |||
North Dakota Bakken | 1,263 | 715 | 1,382 | |||
Other | 1,149 | 2,707 | 1,600 | |||
Mid-Continent: | ||||||
Arkoma Woodford | — | 8,029 | 1,338 | |||
Other | 1,614 | 12,920 | 3,767 | |||
Gulf Coast | 330 | 2,004 | 664 | |||
Total | 24,309 | 36,362 | 30,369 | |||
The following table presents the total gross and net productive wells by region and by oil or gas completion as of 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
Gulf2007:
| Oil Wells | Natural Gas Wells | Total Wells | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
Rockies: | ||||||||||||
Red River units | 249 | 226.6 | 2 | 2.0 | 251 | 228.6 | ||||||
Bakken field | ||||||||||||
Montana Bakken | 130 | 81.2 | 3 | 2.0 | 133 | 83.2 | ||||||
North Dakota Bakken | 49 | 19.5 | 3 | 1.0 | 52 | 20.5 | ||||||
Other | 254 | 226.4 | 4 | 1.3 | 258 | 227.7 | ||||||
Mid-Continent: | ||||||||||||
Arkoma Woodford | 0 | 0.0 | 129 | 16.2 | 129 | 16.2 | ||||||
Other | 736 | 589.3 | 231 | 123.8 | 967 | 713.1 | ||||||
Gulf Coast | 4 | 3.0 | 28 | 13.7 | 32 | 16.7 | ||||||
Total | 1,422 | 1146.0 | 400 | 160.0 | 1,822 | 1,306.0 | ||||||
Gross wells are the number of Mexico 7 4
-------------- ------------
Total Gulf Coast 16 6
TOTAL 81 11
We will initiate, onwells in which 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%working interest is owned and net wells are the total of our total 2004 drilling
budget, with 35%fractional working interests owned in the Rocky Mountain region, 19%gross wells. As of December 31, 2007, we owned interests in the Mid-Continent region,
and 46%no wells containing multiple completions.
As is customary 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
Illinoisindustry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and Kentucky, respectively. On August 1, 2003, anotherperform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our wholly
owned subsidiaries acquiredproducing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the Carmen Gathering System located in western
Oklahoma for a net price after adjustmentsoil and gas industry. Prior to completing an acquisition 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
forproducing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may haveobtain a significant effect upon our revenues,
profitability and rate of growth. Any significant decline in the market prices
fortitle opinion or review previously obtained title opinions. Our oil and natural gas couldproperties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes and other burdens which we believe do not materially and adverselyinterfere with the use or affect our resultscarrying value of operationthe properties.
Marketing and financial condition.
Our revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices forMajor Customers
We principally sell our oil gas and natural gas liquids, which,production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is transported by truck to storage facilities. During the fourth quarter of 2007, we were unable to market some of our Rocky Mountain area crude at a price acceptable to us. This resulted in turn, are dependent upon numerous factors such as weather, economic, political
and regulatory developments and competition from other sourcesan increase in our crude oil inventory of energy.125 MBbls. The price we were offered was adversely affected by seasonal demand. We are
affected morehave temporarily shipped some of our Rocky Mountain crude by fluctuations in oil prices than natural gas prices, because arailcar to help alleviate this situation. We were able to sell the majority of our production is oil. The volatile naturethis oil in January and February 2008. Our marketing 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. Pricescan be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, see “Risk factors—Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.”
For the year ended December 31, 2007, oil sales to Tidal Energy Marketing (U.S.) L.L.C., Marathon Oil Company and Suncor Energy accounted for 20%, 14% and 10%, respectively, of our total revenue. No other purchasers accounted for more than 10% of our total oil and gas and natural gas liquids are subject to wide fluctuations in response to
relatively minor changes in circumstances, and it is possiblesales. We believe that future
prolonged decreases in such prices could occur. Allthe loss of any of these factors are beyond
our control. Any significant decline in the market prices for oil and, to a
lesser extent, natural gaspurchasers would not have a material adverse effect on our resultsoperations, as there are a number of operations and financial condition. Although we may enter into hedging and
other arrangements to manage the risk of volatility of market prices of ouralternative crude 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 successfulpurchasers in our efforts
to increase or replace our proved reserves. To the extent we are unsuccessfulproducing regions.
We operate 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 neta highly competitive environment for acquiring properties, marketing oil and natural gas revenues is
difficult to do with any certainty.and securing trained personnel. Our actual drilling results are likely to
differ from our estimates of proved reserves. We may experience production that
is less than is estimatedcompetitors vary within the regions 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 expectedoperate, 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 certainsome of our competitors may possess and employ financial, technical and personnel resources substantially greater than ours, which may place uscan be particularly important in a relative competitive disadvantage
and make us more vulnerable to changesthe areas 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 operate. Those companies may be forcedable 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 commerciallypay more for 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 intangiblesexploratory prospects and to be heldevaluate, bid for and used by us for impairment whenever eventspurchase a greater number of properties and prospects than our financial or changes in
circumstances indicate thatpersonnel resources permit. In addition, shortages or the carrying amounthigh cost 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 depresseddrilling rigs could delay 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 oilour development 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
ofexploration 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 propertiesprospects and to discoverfind and develop reserves in the future will depend uponon 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 controlAlso, there is substantial competition for capital available for investment 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 natural gas industry is under constant review for amendment or expansion. Numerous
departmentsindustry.
Regulation of the Oil 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.
RegulationsNatural Gas Industry
Regulation of Sales and Transportation of Natural Gas.Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorating provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale orfor resale of natural gas in interstate commerce pursuant tohave been regulated by agencies of the Natural Gas Act of
1938 andU.S. federal government, primarily the Natural Gas Policy Act of 1978.FERC. In the past, the federal government has regulated the prices at which oil andnatural 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. OurDeregulation of wellhead
natural gas sales began with the enactment of the Natural Gas Policy Act and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead 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 theeffective January 1, 1993.
FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to remove various barriers and practicescreate a regulatory framework that historically limited
non-pipelinewill put natural gas sellers including producers,into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas 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 governingsale of transportation and gathering services
providedstorage services. Beginning in 1992, the FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by intrastatea structure under which pipelines provide transportation and gatherers. Whilestorage service on an open access basis to others who buy and sell natural gas. Although the changes being
considered by these federal and state regulators would affect us only
indirectly,FERC’s orders do not directly regulate natural gas producers, they are intended to further enhancefoster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our 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.is sold. 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 noregulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently pursuedestablished by the FERC and Congress will continue. Oil Price Controls and Transportation Rates. Our sales of crude oil,
condensate and gas liquids areHowever, we do not currently regulated and are made at market
prices. The price we receivebelieve that any action taken will affect us in a way that materially differs from the saleway it affects other natural gas producers.
Gathering service, which occurs upstream of these products may be affectedjurisdictional transmission services, is regulated by the cost of transportingstates onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the productstendency 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,getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, abandoning oil andin some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural 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 bereceive greater regulatory scrutiny in the future.
Intrastate natural gas transportation is also subject to substantial civilregulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and criminal
penalties, claims for injurythe degree of regulatory oversight and scrutiny given to personsintrastate natural gas pipeline rates and damageservices varies from state to properties andstate. Insofar as such regulation within a particular state will generally affect all intrastate natural resources, and clean up and other remedial obligations. Althoughgas shippers within the state on a comparable basis, we believe that the operationregulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our properties generally complies with applicable environmental
laws and regulations,competitors. Like the riskregulation of incurring substantial costs and liabilities
are inherent ininterstate transportation rates, the operationregulation of oil andintrastate transportation rates affects the marketing of natural 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,that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Production
The production of oil and natural gas industry in general. The costis subject to regulation under a wide range of compliance with more stringent environmental lawslocal, state 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 lawsfederal statutes, rules, orders 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,Federal, state and local levels. Suchstatutes and regulations include requiringrequire permits andfor drilling operations, drilling bonds forand reports concerning operations. All of the drilling of wells, regulating the location of wells, the method of
drillingstates in which we own and casing wells, and the surface use and restoration ofoperate properties upon which wells are drilled. Many states also have statutes or regulations addressinggoverning conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, and the regulation of well spacing, and plugging and abandonment of such wells. Some state statutesThe effect of these regulations is to limit the rateamount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have
reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental, Health and Safety Regulation
General. Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:
require the acquisition of various permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered animal species; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas can beindustry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.
Some of the existing environmental, health and safety laws and regulations to which our business operations are subject include, among others, (i) regulations by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws which impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters; (vi) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (vii) the Safe Drinking Water Act and analogous state laws which impose requirements relating to our underground injection activities; (viii) the National Environmental Policy Act which requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment; (ix) the federal Occupational Safety and Health Act and comparable state statutes which requires that we organize and/or disclose information about hazardous materials stored, used or produced fromin our properties.
EMPLOYEES
operations and; (x) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures, however, are included within our overall capital and operating
budgets and are not separately itemized. Although we believe that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.
As of March 29, 2004,December 31, 2007, we employed 302332 people, including 112181 employees in drilling and production, 47 in financial and accounting, 33 in land, 21 in exploration, 11 in reservoir engineering, 28 in administrative personnel,and 11 geoscientists, 19 engineers and 160 field personnel.in information technology. 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
On May 14, 2007, the Company completed its initial public offering. In conjunction therewith, the Company affected an 11 for 1 stock split by means of a stock dividend. All prior period share and per share information contained in this report have been retroactively restated to give effect to the stock split. On May 14, 2007, the Company amended its certificate of incorporation to, among other things, increase the number of authorized preferred shares to 25 million and common shares to 500 million. Prior to completion of the public offering, the Company was a subchapter S corporation and income taxes were payable by its shareholders. In connection with the public offering, the Company converted to a subchapter C corporation and recorded a charge to earnings in the second quarter of $198.4 million to recognize deferred taxes at May 14, 2007. Thereafter, the Company has provided for income taxes on income. SeeNotes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Pro forma information (unaudited) and Income taxes and Note 11. Shareholders’ Equityfor a complete discussion of the accounting for the various transactions resulting from the initial public offering and of the pro forma information presented.
Our corporate internet web site iswww.contres.com. Through the investor relations section of our website, we make available our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after the report is filed or furnished with the Securities and Exchange Commission. Information contained at our website is not incorporated by reference into this report and you should not consider information contained at our website as part of this report.
We file periodic reports and proxy statements with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of this site is http://www.sec.gov.
Our principal executive offices are located at 302 N. Independence, Enid, Oklahoma 73701, and our telephone number at that address is (580) 233-8955.
| Item 1A. | Risk Factors |
You should carefully consider each of the risks described below, together with all of the other information contained in this report, before deciding to invest in shares of our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline and you may lose all or part of your investment.
Risks Relating to the Oil and Natural Gas Industry and Our Business
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
changes in global supply and demand for oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
the price and quantity of imports of foreign oil and natural gas;
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
the level of global oil and natural gas exploration and production;
the level of global oil and natural gas inventories;
localized supply and demand fundamentals and transportation availability;
weather conditions;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
Lower oil and natural gas prices will reduce our cash flows and borrowing ability. See “Our development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.” Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices would render uneconomic a significant portion of our exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
In addition, because our producing 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 locatedgeographically concentrated in the Rocky Mountain region, 14%we are vulnerable to fluctuations in the Mid-Continent region and 1%pricing in the Gulf Coast
region. At December 31, 2003, 87%that area. In particular, 81% of our net proved reserves were oil and 13%
were natural gas. Our oil reserves are confined primarily toproduction during the fourth quarter of 2007 was from the Rocky Mountain regionregion. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, transportation capacity constraints, curtailment of production or interruption of transportation of oil produced from the wells in these areas. Such factors can cause significant fluctuation in our realized oil and natural gas prices. For example, the company-wide difference between the average NYMEX oil price and our average realized oil price for the year
ended December 31, 2007 was $8.85 per Bbl, whereas the company-wide difference between the NYMEX oil price and our realized oil price for the year ended December 31, 2006 was $11.04 per Bbl.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” Our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
delays imposed by or resulting from compliance with regulatory requirements;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment and qualified personnel;
equipment failures or accidents;
adverse weather conditions, such as hurricanes and tropical storms;
reductions in oil and natural gas prices;
title problems; and
limitations in the market for oil and natural gas.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves are primarily from the Mid-Continentis complex. It requires interpretations of available technical data and Gulf Coast regions. Approximately $40.0 million,many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or 49%,assumptions could materially affect our estimated quantities and present value of our projected $81.9
million capital expendituresreserves. See “Item 1. Business—Proved Reserves” for 2004 are focused on expansioninformation about our estimated oil 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 inreserves and the Mid-ContinentPV-10 and Gulf Coast regions.
The following table provides information with respect to ourstandardized measure of discounted future net proved
reserves for our principal oil and gas propertiescash flows as of December 31, 2003:
In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are located primarilybeyond our control.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the Williston Basinpresent value estimate. If oil prices decline by $1.00 per Bbl, then our PV-10 as of December 31, 2007 would decrease approximately $50 million. If natural gas prices decline by $0.10 per Mcf, then our PV-10 as of December 31, 2007 would decrease approximately $9 million.
Our use of enhanced recovery methods creates uncertainties that could adversely affect our results of operations and financial condition.
One of our business strategies is to commercially develop unconventional oil and natural gas resource plays using enhanced recovery technologies. For example, we inject water and high-pressure air into formations on some of our properties to increase the production of oil and natural gas. The additional production and reserves attributable to the use of these enhanced recovery methods are inherently difficult to predict. If our enhanced recovery programs do not allow for the extraction of oil and natural gas in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.
Our development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flow used in investing activities was $486.4 million related to capital and exploration expenditures in 2007. Our budgeted capital expenditures for 2008 are expected to increase to approximately $616.0 million. To date, these capital expenditures have been financed with cash generated by operations and through borrowings from banks and, prior to our initial public offering, from our principal shareholder. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional debt may require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of your common stock.
Our cash flow from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the level of oil and natural gas we are able to produce from existing wells;
the prices at which our oil and natural gas are sold; and
our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our credit facility decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and results of operations.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations; we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
fires, explosions and ruptures of pipelines in connection with our high-pressure air injection operations;
personal injuries and death; and
natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Prospects that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our result of operations and financial condition. In this report, we describe some of our current prospects and our plans to explore those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. The North Dakota Bakken Shale and Arkoma Woodford projects comprise the majority of these drilling locations. Due to limited production history on the relatively few number of wells drilled in these projects, we are unable to predict with certainty the quantity of future production from wells to be drilled in these projects. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2007, we had 173,828, 182,802 and 188,689 net acres expiring in 2008, 2009 and 2010, respectively. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil
and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipeline or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
We have been an early entrant into new or emerging plays; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
We are subject to complex federal, state, local, provincial and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and provincial governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.
Our business is subject to federal, state, local and provincial laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations. See “Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from our operations.
New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our
competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
Terrorist attacks aimed at our energy operations could adversely affect our business.
The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other energy companies, could have a material adverse effect on our business.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas, including parts of Montana, North Dakota, South Dakota, Utah and MontanaWyoming, drilling and other oil and natural gas activities can only be conducted during the spring and summer months. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the Big Horn Basinresulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Our credit facility contains 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 includes certain covenants that, among other things, restrict:
our investments, loans and advances and the paying of Wyoming.
Estimated proved reserves for dividends and other restricted payments;
our Rocky Mountain properties at December 31,
2003, totaled 72.0 MMBoeincurrence of additional indebtedness;
the granting of liens, other than liens created pursuant to the credit facility and represented 75%certain permitted liens;
mergers, consolidations and sales of all or substantial part of our PV-10. Approximately 48%business or properties;
the hedging, forward sale or swap 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 crude oil and 4,022 Mcf ofor natural gas or 7,964
Boe per day. other commodities;
the sale of assets; and
our capital expenditures.
Our leasehold interests include 172,000 net developedcredit facility requires us to maintain certain financial ratios, such as 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 397,000
net undeveloped acres, which represent 23% and 53%other provisions of our total leasehold,
respectively. This leasehold is expectedcredit facility may be impacted by changes in economic or business conditions, results of operations or 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 there under or their successors or assignees, such lenders could elect to declare all amounts borrowed under our credit facility, together with accrued interest, to be developed utilizing 3-D seismic,
precision horizontal drillingdue and secondary recovery technologies, where
applicable. As of December 31, 2003,payable. If we were unable to repay such borrowings or interest, 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 discoveredlenders 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 November 1994.
During the twelve months ended December 31, 2003, the Cedar Hills Field
properties produced 3,092 net Boe per day tofull such indebtedness.
Increases in interest rates could adversely affect 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. business.
We are proficient using either technologyexposed to changes in interest rates as a result of borrowings outstanding under our credit facility. At February 29, 2008, our outstanding borrowings were $222.0 million and arethe impact of a 1% increase in the processinterest rates on this amount of implementing both as partdebt would result in increased interest expense of approximately $2.2 million and a $1.4 million decrease in our net income.
The inability 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. significant customers to meet their obligations to us may adversely affect our financial results.
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 needsubject to be invested during 2004credit risk due 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%concentration of our estimated
proved reservesoil and $401.9 million, or 49%, of the PV-10natural gas receivables with several significant customers. The two largest purchasers of our proved reserves
at December 31, 2003.
Medicine Pole Hills, Medicine Pole Hills West, Medicine Pole Hills South,
Buffalo, West Buffalooil 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, whichnatural gas during the twelve months ended December 31, 2003, produced
367 Bbls per day, net2007 accounted for 20% and 14% of our total oil and natural gas sales revenues. We do not require our customers to post collateral. The inability of our interests. Wells in both the Lustre and Midfork
Fields produce from the Charles "C" dolomite, at depths of 5,500significant customers 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 frommeet their obligations to us may adversely affect 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,financial results.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations 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 quantitiesprices of oil and gas.
Although this isnatural gas, we on occasion, enter into derivative instruments for a new venture for us, the activity in this area has been
emerging over the last two years through the effortsportion of other operators. We
delayed entryour oil and/or natural gas production, including collars and price-fix swaps. In July 2007, we entered 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 1500fixed price swaps covering 10,000 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 inAugust 2007 through 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 sold2008 at a price based on NYMEX less a differential ranging from $4.00 -
$6.00of $72.90 per barrel. Gas producedWe have not designated any of our derivative instruments as hedges for accounting purposes and will record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counter-party to the derivative instrument defaults on its contract obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, these types of derivative arrangements limit the benefit we would receive from increases in the Worland Fieldprices for oil and natural gas.
We may be subject to risks in connection with acquisitions.
The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is also sour,
resultinginherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a sale price that is less per Mcf than non-sour natural gas.timely or cost effective manner.
As a new public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange (NYSE) with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will increase our costs and expenses. We believe that secondarywill need to:
institute a more comprehensive compliance function;
design, establish, document, evaluate and tertiary recovery projects have significant
potential formaintain a system of internal controls over financial reporting in compliance with the additionrequirements of reservesSection 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
comply with rules promulgated by the NYSE;
prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;
involve and retain to a greater degree outside counsel and accountants in the Worland Field area fields. Weabove activities; and
establish an investor relations function.
In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers. As a result, compliance with the requirements of the Sarbanes-Oxley Act could have a material adverse effect on our business.
Our Chairman and Chief Executive Officer own approximately 72.8% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our company.
As of February 29, 2008, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owns 123,140,608 shares of our outstanding common representing approximately 72.8% of our outstanding common stock. As a result, Mr. Hamm will continue to seekbe our controlling shareholder and will continue to be able to
control the best method for increasing recovery fromelection of our directors, determine our corporate and management policies and determine, without 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
processconsent of our other shareholders, 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 MMBoeoutcome of certain corporate transactions or other matters submitted to our proved reserves.shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As evidencedcontrolling shareholder, Mr. Hamm could cause, delay or prevent a change of control of our company. The interests of Mr. Hamm may not coincide with the interests of other holders of our common stock.
Several affiliated companies controlled by past infill drillingMr. Hamm provide oilfield, gathering and acid
fracturing stimulations, reserve growth can be significant.
MID-CONTINENT REGION
Our Mid-Continent properties are located primarilyprocessing, marketing and other services to us. We expect these transactions will continue in the Anadarko Basinfuture and may result in conflicts of western Oklahomainterest between Mr. Hamm’s affiliated companies and the Texas Panhandle. During 2001, we expandedus. We can provide no assurance that any such conflicts will be resolved in our operations in the Mid-Continent through the acquisition of Farrar Oil Company's
assets in the Anadarkofavor.
| Item 1B. | Unresolved Staff Comments |
There were no unresolved Securities 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,Exchange Commission staff comments 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. 2007.
| Item 2. | Properties |
The Anadarko Basin propertiesinformation required by Item 2 is 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, Item 1. Business—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:
| Item 3. | Legal Proceedings |
We are not
involved in any legal proceedings nor are we a party to any material pending or
threatened claimslegal proceedings, other than ordinary course litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that could reasonably be expected tothe resolution of any proceeding will not 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
| Item 4. | Submission of Matters to a Vote of Security Holders |
There were no matters submitted to a vote of security holders during the fourth quarter of 2007.
Part II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There
| Item 5. | Market for Registrant’s Common Equity and Related Shareholder Matters |
Our common stock is no established trading marketlisted on the New York Stock Exchange and trades under the symbol “CLR.” The following table sets forth quarterly high and low sales prices since May 14, 2007, when we became a publicly traded company, and cash dividends declared for each quarter of the previous two years.
| 2007 | 2006 | |||||||||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||||||
High | $ | — | $ | 16.40 | $ | 18.97 | $ | 27.62 | $ | — | $ | — | $ | — | $ | — | ||||||||
Low | — | 14.00 | 14.11 | 18.05 | — | — | — | — | ||||||||||||||||
Cash Dividend | 0.12 | 0.21 | — | — | 0.38 | — | 0.17 | — | ||||||||||||||||
We declared cash dividends to our shareholders of record for tax purposes and, subject to forfeiture, to holders of unvested restricted stock during such time as we were a subchapter S corporation. In connection with the completion of our offering on May 14, 2007, we converted from a subchapter S corporation to a subchapter C corporation, and we do not anticipate paying any additional cash dividends on our common stock.stock in the foreseeable future. As of MarchFebruary 29, 2004, there were three2008, the number of record holders of our common stock. We issued no
equity securities during 2003. During 2000, we established astock was 35. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 12,500. On February 29, 2008, the last reported sales price of our Common 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
as reported on the NYSE, was $28.08 per share.
The following table sets forthsummarizes our purchases of our common stock during the fourth quarter of 2007:
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs | |||||
October | 65,309 | $ | 20.96 | — | — | ||||
November | 48,816 | $ | 22.44 | — | — | ||||
December | 51,928 | $ | 24.55 | — | — | ||||
Total | 166,053 | $ | 22.52 | — | — | ||||
All shares purchased above represent shares issued pursuant to stock option exercises or restricted stock grants that were surrendered to cover taxes required to be withheld. The Company paid the amounts above to the Internal Revenue Service for the required withholding. SeeNotes to Consolidated Financial Statements—Note 12. Stock Compensation.
Performance Graph
The performance graph shown below is being furnished pursuant to applicable rules of the SEC. As required by these rules, the performance graph was prepared based upon the following assumptions:
$100 was invested in our common stock at its initial public offering price of $15 per share and invested in the S&P 500 Index and our “peer group” on May 14, 2007 at the closing price on such date;
investment in our peer group was weighted based on the stock price of each individual company within the peer group at the beginning of the period; and
dividends were reinvested on the relevant payment dates.
Our peer group is comprised of Bill Barrett Corporation, Denbury Resources, Inc., Encore Acquisition Company, Quicksilver Resources, Inc., Range Resources Corp., Southwestern Energy Company and St. Mary Land and Exploration Company. We selected these companies because they are publicly traded exploration and production companies similar in size and operations to us.
| Item 6. | Selected Financial Data |
This section presents our selected historical and pro forma consolidated financial data. The selected historical consolidated financial data for the periods ended andpresented below is not intended to replace our historical consolidated financial statements.
The following historical consolidated financial data, as it relates to each of the dates indicated. The statements of
operations and other financial data for thefiscal 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, havethrough 2007, has been derived from and should be reviewed in
conjunction with, our audited historical consolidated financial statements andfor such periods. You should read the notes thereto.
Ernst & Young LLP audited ourfollowing selected historical consolidated 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 elsewheredata in this annual report on Form
10-K. The data should be read in conjunctionconnection with "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operation” and theour historical consolidated financial statements and the related notes thereto included elsewhere in this report. Certain amounts applicableThe selected historical consolidated results are not necessarily indicative of results to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
be expected in future periods.
| YEAR ENDED DECEMBER 31, | ||||||||||||||||||||
(Dollars in thousands, except per share data) | 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||||||
Statement of Income: | ||||||||||||||||||||
Oil and natural gas sales(1) | $ | 606,514 | $ | 468,602 | $ | 361,833 | $ | 181,435 | $ | 138,948 | ||||||||||
Derivative losses(1) | (44,869 | ) | — | — | — | — | ||||||||||||||
Total revenues | 582,215 | 483,652 | 375,764 | 418,910 | 317,609 | |||||||||||||||
Income (loss) from continuing operations | 28,580 | 253,088 | 194,307 | 26,816 | (768 | ) | ||||||||||||||
Net Income | 28,580 | 253,088 | 194,307 | 27,864 | 2,340 | |||||||||||||||
Basic earnings per share: | ||||||||||||||||||||
From continuing operations | $ | 0.17 | $ | 1.60 | $ | 1.23 | $ | 0.18 | $ | — | ||||||||||
Net income per share | $ | 0.17 | $ | 1.60 | $ | 1.23 | $ | 0.18 | $ | 0.01 | ||||||||||
Shares used in basic earnings per share | 164,059 | 158,114 | 158,059 | 158,059 | 158,059 | |||||||||||||||
Diluted earnings per share: | ||||||||||||||||||||
From continuing operations | $ | 0.17 | $ | 1.59 | $ | 1.22 | $ | 0.18 | $ | — | ||||||||||
Net income per share | $ | 0.17 | $ | 1.59 | $ | 1.22 | $ | 0.18 | $ | 0.01 | ||||||||||
Shares used in diluted earnings per share | 165,422 | 159,665 | 159,307 | 159,236 | 158,059 | |||||||||||||||
Pro forma C-corporation(2) | ||||||||||||||||||||
Pro forma income (loss) from continuing operations | $ | 184,002 | $ | 156,833 | $ | 121,177 | $ | 16,626 | $ | (476 | ) | |||||||||
Pro forma net income | 184,002 | 156,833 | 121,177 | 17,276 | 1,451 | |||||||||||||||
Pro forma basic earnings per share | 1.12 | 0.97 | 0.77 | 0.11 | 0.01 | |||||||||||||||
Pro forma diluted earnings per share | 1.11 | 0.96 | 0.76 | 0.11 | 0.01 | |||||||||||||||
Production(3) | ||||||||||||||||||||
Oil (MBbl) | 8,699 | 7,480 | 5,708 | 3,688 | 3,463 | |||||||||||||||
Gas (MMcf) | 11,534 | 9,225 | 9,006 | 8,794 | 10,751 | |||||||||||||||
Oil equivalent (MBoe) | 10,621 | 9,018 | 7,209 | 5,154 | 5,255 | |||||||||||||||
Average sales prices(4) | ||||||||||||||||||||
Oil ($/Bbl) | $ | 63.55 | $ | 55.30 | $ | 52.45 | $ | 37.12 | $ | 25.98 | ||||||||||
Gas ($/Mcf) | 5.87 | 6.08 | 6.93 | 5.06 | 4.55 | |||||||||||||||
Oil equivalent ($/Boe) | 58.32 | 52.09 | 50.19 | 35.20 | 26.44 | |||||||||||||||
Average costs per Boe(5) | ||||||||||||||||||||
Production expense | $ | 7.35 | $ | 6.99 | $ | 7.32 | $ | 8.49 | $ | 7.16 | ||||||||||
Production tax | 3.13 | 2.48 | 2.22 | 2.39 | 1.95 | |||||||||||||||
Depreciation, depletion, amortization and accretion | 9.00 | 7.27 | 6.91 | 7.49 | 8.28 | |||||||||||||||
General and administrative | 3.15 | 3.45 | 4.34 | 2.41 | 2.13 | |||||||||||||||
Proved reserves | ||||||||||||||||||||
Oil (MBbl) | 104,145 | 98,038 | 98,645 | 80,602 | 73,000 | |||||||||||||||
Gas (MMcf) | 182,819 | 121,865 | 108,118 | 60,620 | 67,096 | |||||||||||||||
Oil equivalent (MBoe) | 134,615 | 118,349 | 116,665 | 90,705 | 84,182 | |||||||||||||||
Other financial data: | ||||||||||||||||||||
Cash dividends per share | $ | 0.33 | $ | 0.55 | $ | 0.01 | $ | 0.09 | $ | — | ||||||||||
EBITDAX(6) | 469,885 | 372,115 | 285,344 | 116,498 | 88,750 | |||||||||||||||
Net cash provided by operations | 390,648 | 417,041 | 265,265 | 93,854 | 65,246 | |||||||||||||||
Net cash used in investing | (483,498 | ) | (324,523 | ) | (133,716 | ) | (72,992 | ) | (108,791 | ) | ||||||||||
Net cash provided by (used in) financing | 94,568 | (91,451 | ) | (141,467 | ) | (7,245 | ) | 43,302 | ||||||||||||
Capital expenditures | 525,677 | 326,579 | 144,800 | 94,307 | 114,145 | |||||||||||||||
Balance sheet data at December 31: | ||||||||||||||||||||
Total assets | $ | 1,365,173 | $ | 858,929 | $ | 600,234 | $ | 504,951 | $ | 484,988 | ||||||||||
Long-term debt, including current maturities | 165,000 | 140,000 | 143,000 | 290,522 | 290,920 | |||||||||||||||
Shareholders’ equity | 623,132 | 490,461 | 324,730 | 130,385 | 116,932 | |||||||||||||||
| (1) | Oil and |
| (2) | Pro forma adjustments are reflected to provide for income taxes in |
| (3) | For the years 2007 and 2006, oil sales volumes were 221 MBbls and 21 MBbls less than oil production volumes, respectively. |
| (4) | Average sales prices for the years 2004 and 2003 are net of hedges. The price without hedges for 2004 was $38.85 per barrel of oil and $36.45 per barrel of oil equivalent and the price without hedges for 2003 was $28.88 per barrel of oil and $28.35 per barrel of oil equivalent. |
| (5) | Average costs per Boe have been computed using sales volumes. |
| (6) | EBITDAX represents earnings before |
| Year ended December 31, | ||||||||||||||||
| 2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||
| (in thousands) | ||||||||||||||||
Net Income | $ | 28,580 | $ | 253,088 | $ | 194,307 | $ | 27,864 | $ | 2,340 | ||||||
Unrealized derivative loss | 26,703 | — | — | — | — | |||||||||||
Interest expense | 12,939 | 11,310 | 14,220 | 23,617 | 19,761 | |||||||||||
Provision (benefit) for income taxes | 268,197 | (132 | ) | 1,139 | — | — | ||||||||||
Depreciation, depletion, amortization and accretion | 93,632 | 65,428 | 49,802 | 38,627 | 40,256 | |||||||||||
Property impairments | 17,879 | 11,751 | 6,930 | 11,747 | 8,975 | |||||||||||
Exploration expense | 9,163 | 19,738 | 5,231 | 12,633 | 17,221 | |||||||||||
Equity compensation | 12,792 | 10,932 | 13,715 | 2,010 | 197 | |||||||||||
EBITDAX | $ | 469,885 | $ | 372,115 | $ | 285,344 | $ | 116,498 | $ | 88,750 | ||||||
The following discussion should be read in conjunction with our historical consolidated financial statements and notes, thereto andas well as the selected historical consolidated financial data included elsewhere herein.
OVERVIEW
Significant Events of 2003
Cedar Hills Units 2003 Summary
In 2003 CRI continued in its development of the secondary recovery projects
for the North Cedar Hills Unitthis report.
Overview
We are engaged in North Dakota. This huge secondary oil recovery
project continues to be on-schedule, both from an expense/cost standpoint and a
production standpoint,natural gas exploration and 96% complete. High-pressure air injection was
initiated on January 14, 2003. A total of 24 in-fill horizontal injection wells
were drilled during 2003 at an approximate cost of $29 million. There were 48
wells converted to injection during 2003 for a cost of $10.5 million. Air
injection started in mid-January into four wells and by December injection
averaged 40 MMcfd into 47 wells. By December, nine wells were beginning to
respond to injection. The actual response time corresponds favorably with the
computer simulation and analog models.
Middle Bakken Field, Richland County, Montana
During 2003 we entered a new play that is proving to be another significant
discovery/development of oilexploitation activities in the Rocky Mountain, Region. The potential sizeMid-Continent and Gulf Coast regions of the discovery could rival thatUnited States. Crude oil comprised 77% of Cedar Hillsour 134.6 MMBoe of estimated proved reserves as of December 31, 2007 and be82% of similar proportion to
Continental's interest. The producing Bakken reservoir is widespread, Devonian
age shale deposited within the central portionsour 10,621 MBoe of the Williston Basin. The
Bakken is considered to be one of the primary source rocksproduction for the basin. This
play has been emerging overyear then ended. We seek to operate wells in which we own an interest, and we operated wells that accounted for 93% of our PV-10 and 79% of our 1,822 gross wells as of December 31, 2007. By controlling operations, we are able to more effectively manage the last two years throughcost and timing of exploration and development of our properties, including the efforts of various
operators in the basin. The play is being developed using a combination of
horizontal drilling and frac technology. During 2003 we assembled approximately
65,000 net acresfracture stimulation methods used.
Our business strategy has focused on reserve and successfully drilled and completed four producers. These
producers were completed flowing 400 to 1200 BOPD and gross PDP reserves average
500 MBO per well. We are planning to move a second rig and its horizontal
drilling experienced crews from the Cedar Hills project to the Middle Bakken
Field to develop acreage in the field recently acquired by CRI. We also have
plans to add a third rig later in the year in this field. Scheduled development
of this prolific field is expected to take three years.
Continental Gas, Inc.
CGI entered into a formal Purchase and Sale Agreement with Great Plains
Pipeline Company to acquire the Carmen Gathering System, effective August 1,
2003. The system is located in Woods, Alfalfa and Major Counties and is
comprised of 290 miles of pipeline connected to approximately 200 wells. The
system currently provides wellhead gathering for natural gas, crude oil and
saltwater.
Due to higher than normal commodity prices, many exploration companies have
increased their drilling programs. Acquisition of the system places CGI squarely
in the middle of an active exploration program being conducted by multiple
producers. Ownership of the system will allow CGI to compete for additional
supplies of natural gas to process through our Eagle Chief Plant.
Since the gas gathered by this system is currently processed by CGI at our
Eagle Chief Plant, the acquisition of this system is consistent with CGI's
strategy to expand and grow our assets in our core operating areas. CGI
currently owns and operates natural gas pipelines and processing plants in 6
states.
Growth has been the key driver to Continental Gas in 2003 with throughput
up by 50% over 2002. The increased volumes resulted from growth on the Company's
existing systems and the acquisition of the Carmen Gas Gathering System from
Great Plains Pipeline Company in mid-2003. Continental Gas, Inc. ("CGI") remains
a strong subsidiary of Continental Resources, contributing $5 million in
earnings in 2003 with good capital and natural gas throughput growth.
Continental Resources of Illinois, Inc.
Continental Resources of Illinois, Inc. ("CRII"), with Richard Straeter as
President, continues to develop its projects through teamwork and coordination
within all their departments. PV10 growth from $28.2 million in 2002 to $31.9
million in 2003 is a direct result of this teamwork. Their production has
recently been bolstered from their successful McCollum and Gannon waterfloods.
CRII's focus for 2003 is on continued reserve development, growth through exploration and secondary recovery.
RESULTS OF OPERATIONSdevelopment. For the three-year period ended December 31, 2007, we added 66,087 MBoe of proved reserves through extensions and discoveries, compared to 561 MBoe added through purchases. During this period, our production increased from 7,209 MBoe in 2005 to 10,621 MBoe in 2007. An aspect of our business strategy has been to acquire large undeveloped acreage positions in new or developing resource plays. As of December 31, 2007, we held approximately 1,359,098 gross (733,132 net) undeveloped acres, including 336,000 net acres in the Bakken field in Montana and North Dakota and 70,554 net acres in the Arkoma Woodford and Lewis Shale projects. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than those of later entrants into a developing play.
In the year ended December 31, 2007, our oil and gas production increased to 10,621 MBoe (29,099 Boe per day), up 18% from the year ended December 31, 2006. The increase in 2007 production primarily resulted from an increase in production from our Red River units, Bakken field and Arkoma Woodford. Oil and natural gas revenues for the year 2007 increased by 29% to $606.5 million due to increases in volumes and price. Our realized price per Boe increased $6.22 to $58.31 for the year 2007 compared to the year 2006. While we experienced increases in production expense and production tax of a combined total of $23.9 million, or 28%, our increase in combined per unit cost was only 11%, or $1.01 per Boe, due to the increase in sales volumes of 1,405 MBoe, or 16%. Oil sales volumes were 221 MBbls less than oil production for the year ended December 31, 2007 and 21 MBbls less for the same period in 2006, due to an increase in crude oil inventory for pipeline line fill and temporarily stored barrels. Our cash flow from operating activities for the year ended December 31, 2007, was $390.6 million, a decrease of $26.4 million from $417.0 million provided by our operating activities during the comparable 2006 period. The decrease in operating cash flows was mainly due to changes in working capital items including an increase in accounts receivables and an increase in crude oil inventory. During the year ended December 31, 2007, we invested $525.7 million (inclusive of non-cash accruals of $36.4 million) in our capital program primarily in the Red River units, the Bakken field and the Arkoma Woodford play.
How We Evaluate Our Operations
We use a variety of financial and operational measures to assess our performance. Among these measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) EBITDAX. The following tables set forthtable contains financial and operational highlights for each of the three years ended December 31, 2007.
| Year Ended December 31, | |||||||||
| 2007 | 2006 | 2005 | |||||||
Average daily production: | |||||||||
Oil (Bopd) | 23,832 | 20,494 | 15,639 | ||||||
Natural gas (Mcfpd) | 31,599 | 25,274 | 24,675 | ||||||
Oil equivalents (Boepd) | 29,099 | 24,706 | 19,752 | ||||||
Average prices:(1) | |||||||||
Oil ($/Bbl) | $ | 63.55 | $ | 55.30 | $ | 52.45 | |||
Natural gas ($/Mcf) | 5.87 | 6.08 | 6.93 | ||||||
Oil equivalents ($/Boe) | 58.31 | 52.09 | 50.19 | ||||||
Production expense ($/Boe)(1) | 7.35 | 6.99 | 7.32 | ||||||
General and administrative expense ($/Boe)(1) | 3.15 | 3.45 | 4.34 | ||||||
EBITDAX (in thousands)(2) | 469,885 | 372,115 | 285,344 | ||||||
Net income (in thousands)(3) | 28,580 | 253,088 | 194,307 | ||||||
Pro forma net income (in thousands)(4) | 184,002 | 156,833 | 121,177 | ||||||
Diluted net income per share | 0.17 | 1.59 | 1.22 | ||||||
Pro forma diluted net income per share(4) | 1.11 | 0.96 | 0.76 | ||||||
| (1) | Oil sales volumes were 221 MBbls less than oil production for the year ended December 31, 2007 and 21 MBbls less than oil production for the year ended December 31, 2006 due to temporary storage and pipeline line fill. Average prices and per unit expenses have been calculated using sales volumes and excluding any effect of derivative transactions. |
| (2) | EBITDAX represents earnings before interest expense, income taxes (when applicable), depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains and losses and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). A reconciliation of net income to EBITDAX is provided in Item 6. Selected Financial Data. |
| (3) | Prior to the public offering, we were a subchapter S corporation and income taxes were payable by our shareholders and as a result, there was a minimal provision for income taxes for the periods ended December 31, 2005 and 2006. SeeNotes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Income taxes. In connection with the public offering, we converted to a subchapter C corporation and recorded a charge to earnings in the second quarter of 2007 of $198.4 million to recognize deferred taxes relating to the temporary differences that existed at May 14, 2007, the date we converted to a subchapter C corporation. |
| (4) | Pro forma adjustments are reflected to provide for income taxes in accordance with SFAS No. 109 as if we had been a subchapter C corporation for all periods presented. A statutory Federal tax rate of 35% and effective state tax rate of 3% (net of Federal income tax effects) were used for the pro forma enacted tax rate for all periods. |
Results of Operation
The following table presents selected financial and operating information for each of the three years ended December 31, 2007:
| December 31, | |||||||||||
(in thousands, except volume price data) | 2007 | 2006 | 2005 | ||||||||
Oil and natural gas sales | $ | 606,514 | $ | 468,602 | $ | 361,833 | |||||
Derivatives | (44,869 | ) | — | — | |||||||
Total revenues | 582,215 | 483,652 | 375,764 | ||||||||
Operating costs and expenses | 274,248 | 221,128 | 166,965 | ||||||||
Other expense | 11,190 | 9,568 | 13,353 | ||||||||
Net income, before income taxes | 296,777 | 252,956 | 195,446 | ||||||||
Provision (benefit) for income taxes | 268,197 | (132 | ) | 1,139 | |||||||
Net income | $ | 28,580 | $ | 253,088 | $ | 194,307 | |||||
Production Volumes: | |||||||||||
Oil (MBbl) | 8,699 | 7,480 | 5,708 | ||||||||
Natural gas (MMcf) | 11,534 | 9,225 | 9,006 | ||||||||
Oil equivalents (MBoe) | 10,621 | 9,018 | 7,209 | ||||||||
Sales Volumes: | |||||||||||
Oil (MBbl) | 8,478 | 7,459 | 5,708 | ||||||||
Natural gas (MMcf) | 11,534 | 9,225 | 9,006 | ||||||||
Oil equivalents (MBoe) | 10,400 | 8,997 | 7,209 | ||||||||
Average Prices:(1) | |||||||||||
Oil ($/Bbl) | $ | 63.55 | $ | 55.30 | $ | 52.45 | |||||
Natural gas ($/Mcf) | $ | 5.87 | $ | 6.08 | $ | 6.93 | |||||
Oil equivalents ($/Boe) | $ | 58.32 | $ | 52.09 | $ | 50.19 | |||||
| (1) | Oil sales volumes are 221 MBbls and 21 MBbls less than oil production volumes for the years ended 2007 and 2006, respectively, due to temporary storage and pipeline linefill. |
Year ended December 31, 2007 compared to the year ended December 31, 2006
Production
The following tables reflect our production by product and region for the periods presented.
| Year Ended December 31, | ||||||||||||||||
| 2007 | 2006 | Volume increase | Percent increase | |||||||||||||
| Volume | Percent | Volume | Percent | |||||||||||||
Oil (MBbl)(1) | 8,699 | 82 | % | 7,480 | 83 | % | 1,219 | 16 | % | |||||||
Natural Gas (MMcf) | 11,534 | 18 | % | 9,225 | 17 | % | 2,309 | 25 | % | |||||||
Total (MBoe) | 10,621 | 100 | % | 9,018 | 100 | % | 1,603 | 18 | % | |||||||
| Year Ended December 31, | Volume increase (decrease) | Percent increase (decrease) | ||||||||||||||
| 2007 | 2006 | |||||||||||||||
| MBoe | Percent | MBoe | Percent | |||||||||||||
Rocky Mountain(1) | 8,619 | 81 | % | 7,159 | 79 | % | 1,460 | 20 | % | |||||||
Mid-Continent | 1,794 | 17 | % | 1,497 | 17 | % | 297 | 20 | % | |||||||
Gulf Coast | 208 | 2 | % | 362 | 4 | % | (154 | ) | (43 | )% | ||||||
Total (MBoe) | 10,621 | 100 | % | 9,018 | 100 | % | 1,603 | 18 | % | |||||||
| (1) | Oil sales volumes are 221 MBbls and 21 MBbls less than oil production volumes for the years ended 2007 and 2006, respectively, due to temporary storage and pipeline linefill. |
Oil production volumes increased 16% during the year ended December 31, 2007 in comparison to the year ended December 31, 2006. Production increases in the periods indicated:
Revenues
Oil and Natural Gas Sales.Oil and natural gas sales for the year ended December 31, 2007 were $606.5 million, a 29% increase from sales of $468.6 million for 2006. Our sales volumes increased 1,403 MBoe or 16% over the 2006 volumes due to the classifications currently followed. Such reclassifications do not
affect earnings.
REVENUES
OIL AND GAS SALES
During 2003,continuing success of our enhanced oil recovery and gas sales increased to $138.9 million versus
$108.8 million in 2002 and $112.2 million in 2001. In 2003, we produced 5,255
MBoe at an averagedrilling programs. Our realized price of $28.35 per Boe increased $6.22 to $58.32 for the year ended December 31, 2007 from $52.09 for the year ended December 31, 2006. During 2007, the differential between NYMEX calendar month average crude oil prices and our realized crude oil prices narrowed. The differential per barrel for the year ended December 31, 2007 was $8.85 compared to 5,352 MBoe at an average$11.04 for 2006. Factors contributing to the higher differentials in 2006 included Canadian oil imports, increases in production in the Rocky Mountain region, coupled with downstream transportation capacity constraints, refinery downtime in the Rocky Mountain region, and reduced seasonal demand for gasoline. Crude oil differentials were better during 2007 due to additional transportation capacity and efforts by us to move crude oil to more favorable markets.
During the fourth quarter of 2007, we elected not to sell some of our Rocky Mountain area crude oil as price of $21.36 per Boe for 2002,differentials were unacceptable to us and 4,893 MBoe at an average price of $22.82
per Boewe expected the differentials to improve in 2001.
In 2003, we realized an average price per barrel of oil of $28.88,
excluding hedges, compared to $24.05 in 2002, and $23.79 in 2001. Our hedging
activities resulted in a decrease in oil sales of $10.1 million or $1.91 per
barrel in 2003 and a decrease of $5.6 million or $1.49 per barrel in 2002. In
2001, our hedging activitiesearly 2008. This resulted in an increase in our crude oil salesinventory of $293,000 or
$0.10 per barrel. Natural gas prices per MCF125,000 barrels. The price we were $4.55 for 2003, $2.46 for
2002, and $3.41 for 2001.
Oil production made up 66%offered was adversely affected by seasonal demand. In the fourth quarter of 2007, we shipped some of our total produced volume for 2003, compared
to 71% in 2002 and 71% in 2001. The decrease in oil production from 2002 to 2003
was the result of converting producing wells into injectors in the Cedar Hills
Field in the Rocky Mountain region along with the natural decline in production
in this region. This was partially offset by the increase in gas production in
the Gulf region.
The following table shows our production by region for 2001, 2002, and
2003:
Derivatives.In July 2007, we entered into fixed-price swap contracts covering 10,000 barrels at Cushing, Oklahomaof oil per day for the period from August 2007 through April 2008. During each month of the contract, we will receive a fixed-price of $72.90 per barrel and will pay to take advantagethe counterparties the average of better pricing and to reduce our credit exposure from sales to
our first purchaser. We present sales and purchases of our production from the Rocky Mountain area asprompt NYMEX crude oil marketing incomefutures contract settlement prices for such month. SFAS No. 133, “Accounting for Derivative Instruments and crude oil marketing
expense, respectively. ForHedging Activities” requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We elected not to designate our derivatives as cash flow hedges under the provisions of SFAS No. 133. As a result, we mark our derivative instruments to fair value in accordance with the provisions of SFAS No. 133 and recognize the realized and unrealized change in fair value as a gain (loss) on derivative instruments in the statements of income. During the year ended December 31, 2003,2007, we recognized
revenuehad realized losses on derivatives of $168.1$18.2 million and expensesunrealized losses on derivatives of $166.7 million on$26.7 million.
Oil and Natural Gas Service Operations.Our oil and natural gas service operations consist primarily of sales of high-pressure air and the treatment and sale of lower quality crude oil, marketing
activities. In 2002 we recognized revenueor reclaimed oil. We sold high-pressure air from our Red River units to a third party and recorded revenues of $153.5$3.1 million for revenuesthe years ended December 31, 2007 and $152.7 million in expenses, which included revenues of $85.8 million, and
expenses of $85.1 million related to crude2006. Prices for reclaimed oil trading activities discontinued
in May 2002. In 2001 we recognized revenue of $245.9 million and $245.0 millionsold from our central treating unit were higher for expenses, which included revenues of $98.4 million, and expenses of $97.8
million related to crude oil trading activities that were discontinued.
CHANGE IN DERIVATIVE FAIR VALUE
We recognized $1.5 million of derivative fair value income in 2003,
compared to a loss of $1.5 million in 2002, and no income or loss in 2001. The
2003 balance of $1.5 millionthe year ended December 31, 2007 than the comparable 2006 period, and the 2002 lossnumber of $1.5barrels sold increased
approximately 68,000 barrels which increased reclaimed oil income by $5.5 million are the changescontributing to an overall increase in a fair value derivative not designated as a cash flow hedge. This derivative
contract terminated on December 31, 2003.
GAS GATHERING, MARKETING AND PROCESSING
Our 2003 gathering, marketing and processing revenues increased to $74.5
million, compared to $33.7 million in 2002, and $45.0 million in 2001. The
increase from 2002 to 2003 of $40.8 million was due to higher natural gas prices
and increased throughput volumes. The increased volumes resulted from growth on
our existing systems and the acquisition of the Carmen Gas Gathering System from
Great Plains Pipeline Company. In 2003, $8.2 million of additional revenues were
attributable to the Carmen Gas Gathering System acquisition.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenue was $9.1of $5.5 million in 2003,
comparedfor the year ended December 31, 2007. Associated oil and natural gas service operations expenses increased $4.5 million to $5.7$12.7 million in 2002, and $6.0during the year ended December 31, 2007 from $8.2 million in 2001. The increase in 2003
wasduring the year ended December 31, 2006 due primarilymainly to an increase in reclaimedadditional barrels treated in 2007 and to an increase of $5.71 per barrel in the costs of purchasing and treating oil incomefor resale compared to the same period in 2006.
Operating Costs and Expenses
Production Expense and Tax. Production expense increased $13.6 million, or 22% during the year ended December 31, 2007 to $76.5 million from $62.9 million during the year ended December 31, 2006. The increase in production expense is commensurate with our increase in production of $2.618% which is a direct result of new wells being drilled. Additionally, we have experienced a slight increase in service and energy costs. During the year ended December 31, 2007, we participated in the completion of 262 gross (112.1 net) wells. Production expense per Boe increased to $7.35 per Boe for the year ended December 31, 2007 from $6.99 per Boe for the year ended December 31, 2006.
Production taxes increased $10.2 million, or 46% during the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily as a result of higher revenues resulting from increased sales volumes and prices. The majority of the production tax increase was in the Rocky Mountain region due to an increase of 1,261 MBoe sold in the year ended December 31, 2007 compared to the year ended December 31, 2006. Production tax as a percentage of oil and natural gas sales was 5.4% for the year ended December 31, 2007 compared to 4.8% for the year ended December 31, 2006. Production taxes are based on the wellhead values of production and vary by state. Additionally, some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of oil or gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana, new horizontal wells qualify for a tax incentive and are taxed at 0.76% during the first 18 months of production. After the 18 month incentive period expires, the tax rate increases to 9.26%. During the year ended December 31, 2007, 32 wells had reached the end of the 18 month incentive period and the tax rate increased from 0.76% to 9.26%. Our overall rate is expected to increase as production tax incentives received for horizontal wells in Montana reach the end of the 18 month incentive period. We are also receiving a 6% tax incentive on horizontal wells drilled in the Arkoma Woodford play in Oklahoma that continues for up to four years or until the revenue from such well exceeds the cost to drill and complete. In North Dakota, we are receiving a 4.5% tax credit on horizontal Bakken wells spud after July 1, 2007 and completed before June 30, 2008. The incentive expires on the earliest to occur of 75,000 barrels of production or eighteen months.
On a unit of sales basis, production expense and production taxes were as follows:
| Year Ended December 31, | Percent Increase | ||||||||
| 2007 | 2006 | ||||||||
Production expense ($/Boe) | $ | 7.35 | $ | 6.99 | 5 | % | |||
Production tax ($/Boe) | 3.13 | 2.48 | 26 | % | |||||
Production expense and tax ($/Boe) | $ | 10.48 | $ | 9.47 | 11 | % | |||
Exploration Expense. Exploration expense consists primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses decreased $10.6 million in the year ended December 31, 2007 to $9.2 million due primarily to a decrease in dry hole expense of $9.8 million and a decrease in seismic expense of $0.9 million. The majority of the dry hole costs were in the Mid-Continent region in the 2006 period and in the Mid-Continent and Rocky Mountain regions in the same period in 2007. Dry hole costs were down in 2007 even though exploratory capital expenditures increased by approximately 144% as a result of more successful exploration activities.
Depreciation, Depletion, Amortization and Accretion (DD&A.) Total DD&A increased $28.2 million in 2007 primarily due to an increase in oil and gas DD&A of $27.9 million as a result of increased production and additional properties being added through our drilling program. The DD&A rate for the year ended December 31, 2007 was $9.00 per Boe, including $8.63 per Boe on oil and gas properties and $0.37 per Boe for other equipment and asset retirement obligation accretion, compared to $7.27 per Boe, including $6.91 per Boe for oil and gas properties and $0.36 per Boe for other equipment and asset retirement obligation accretion, for the same period in 2006. The increase in the oil and gas DD&A rate reflects the additional costs incurred to develop proved undeveloped reserves and the higher costs of drilling and completing wells.
Property Impairments.Property impairments increased in the year ended December 31, 2007 by $6.1 million to $17.9 million compared to $11.8 million during the year ended December 31, 2006 reflecting higher amortization of lease costs in our existing fields resulting from further defining likely drilling locations and amortization of new fields. Impairment of non-producing properties increased $7.7 million during the year ended December 31, 2007 to $13.1 million compared to $5.4 million for 2006. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other non-producing properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period.
Impairment provisions for developed oil and gas properties were approximately $4.7 million for the year ended December 31, 2007 compared to approximately $6.3 million for the year ended December 31, 2006.
General and Administrative Expense.General and administrative expense increased $1.7 million to $32.8 million during the year ended December 31, 2007 from $31.1 million during the comparable period of 2006. General and administrative expense includes non-cash charges for stock-based compensation of $12.8 million and $10.9 million for the years ended December 31, 2007 and 2006, respectively. The increase was due to new grants under the Continental Resources, Inc. 2005 Long-Term Incentive Plan (2005 Plan) during the year ended December 31, 2007. On a volumetric basis, general and administrative expense was $3.15 per Boe for the year ended December 31, 2007 compared to $3.45 per Boe for the year ended December 31, 2006. We have granted stock options and restricted stock to our employees and directors. While we were a private company, the terms of the grants required us to purchase vested options and restricted stock at each employee’s request. The obligation to purchase the options was eliminated when we became a reporting company under Section 12 of the Exchange Act on May 14, 2007.
Gain on Sale of Assets.Gains on miscellaneous asset sales for the year ended December 31, 2007 were approximately $1.0 million compared to $0.3 million for the year ended December 31, 2006.
Interest Expense.Interest expense increased 14%, or $1.6 million for the year ended December 31, 2007 compared to the year ended December 31, 2006, due to a higher average outstanding debt balance on our credit facility. Our average debt balance was $182.2 million for the year ended December 31, 2007 compared to $156.6 million for the year ended December 31, 2006. The weighted average interest rate on our credit facility was slightly higher at 6.47% for the year ended December 31, 2007 compared to 6.36% for the same period in 2006. At December 31, 2007 our outstanding debt balance was $165.0 million.
Income Taxes.Income taxes for the year ended December 31, 2007 were $268.2 million and included $198.4 million recorded to recognize deferred taxes upon the conversion from a subchapter S corporation to a subchapter C corporation on May 14, 2007 for temporary differences that existed at that date primarily as a result of deducting intangible drilling costs for tax purposes. We provide taxes at a combined federal and state tax rate of approximately 38% after taking into account permanent taxable differences. See Footnote 7 of Notes to Consolidated Financial Statements for more information.
Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005
Production
The following tables reflect our production by product and region for the periods presented.
| Year ended December 31, | Percent Increase | ||||||||||||
| 2006 | 2005 | ||||||||||||
| Volume | Percent | Volume | Percent | ||||||||||
Oil (MBbl)(1) | 7,480 | 83 | % | 5,708 | 79 | % | 31 | % | |||||
Natural Gas (MMcf) | 9,225 | 17 | % | 9,006 | 21 | % | 2 | % | |||||
Total (MBoe) | 9,018 | 100 | % | 7,209 | 100 | % | 25 | % | |||||
| Year ended December 31, | Percent increase (decrease) | ||||||||||||
| 2006 | 2005 | ||||||||||||
| MBoe | Percent | MBoe | Percent | ||||||||||
Rocky Mountain | 7,159 | 79 | % | 5,410 | 75 | % | 32 | % | |||||
Mid-Continent | 1,497 | 17 | % | 1,361 | 19 | % | 10 | % | |||||
Gulf Coast | 362 | 4 | % | 438 | 6 | % | (17 | )% | |||||
Total MBoe | 9,018 | 100 | % | 7,209 | 100 | % | 25 | % | |||||
| (1) | Oil sales volumes are 21 MBbls less than oil production volumes for the year ended December 31, 2006. |
Oil production volumes increased 31% during the year ended December 31, 2006 in comparison to the year ended December 31, 2005. Production increases in the Bakken field contributed incremental volumes in excess of 2005 levels of 815 MBbls, and the Red River units contributed 865 MBbls of incremental production. Initial production commenced in the Bakken field in August 2003 and has increased thereafter, as we have continued exploration and development activities within the field. Favorable results from the enhanced recovery program and additional field development have been the primary contributors to production growth in the Red River units.
Revenue
Oil and natural gas sales. Oil and natural gas sales for the year ended December 31, 2006 were $468.6 million, a 30% increase over sales of $361.8 million for the comparable period of 2005. Increased sales resulted from additional sales volumes, which increased 25%, and an increase of $1.90 in our realized price per Boe from $50.19 to $52.09. During 2006, we experienced an increase in the differential between NYMEX prices and approximately 40,000 more barrelsour realized crude oil prices. The differential per barrel for the twelve months ended December 31, 2006 was $11.04 as compared to $5.24 for the comparable period of 2005. We realized a crude oil differential in December 2006 of $13.32 per Bbl compared to a high of $14.25 per Bbl in March 2006. Among the factors contributing to the higher differentials were higher Canadian oil imports, increases in production in the Rocky Mountain region, refinery downtime in the Rocky Mountain region, downstream transportation capacity constraints, and reduced seasonal demand for gasoline. We are unable to predict when, or if, the differential will revert back to pre-2006 levels.
Oil and Natural Gas Service Operations. Our oil and natural gas service operations consist primarily of sales of high-pressure air and the treatment and sale of lower quality crude oil, or reclaimed oil. We initiated the sale of high-pressure air from our Red River units to a third party in 2004 and recorded revenues of $3.1 million during 2006 and $3.0 million during 2005. Higher prices for reclaimed oil sold from our central treating unit in 2003. The decrease in 2002 from 2001 was due to
lower prices in 2002 and fewer volumes of reclaimed oil sold from our central
treating unit in 2002.
COSTS AND EXPENSES
PRODUCTION EXPENSES
Our production expenses were $37.6 million in 2003, compared to $28.4
million in 2002 and in 2001. The increase of $9.2 million in 2003 was mainly the
result of2006 increased energy costs of $5.5 million, or a 69% increase due to HPAI
costs in the Cedar Hills unit, which began in 2003, and additional HPAI in MPHU
started in 2003. The increased number of field employees in 2003 contributed to
a $1.2 million, or 25% increase in labor costs in 2003. On a unit of production
basis, production expenses were as follows:
On a Boe Basis 2001 2002 2003
---------- ---------- -----------
Production expenses, without taxes $ 5.81 $ 5.30 $ 7.16
Production expenses and taxes $ 7.52 $ 6.75 $ 9.11
PRODUCTION TAXES
Our production taxes were $10.3 million in 2003 compared to $7.7 million in
2002 and $8.4 million in 2001. The increase of $2.6 million, or 33% was the
result of higher oil and gas prices in 2003 compared to 2002. The decrease of
$0.7 million in 2002 was primarily the result of lower gas prices in 2002
compared to 2001.
EXPLORATION EXPENSE
In 2003, our exploration expenses were $17.2 million compared to $10.2
million in 2002 and $15.9 million in 2001. Exploration expenses in 2003
increased $7.0 million compared to 2002 from an increase in 2003 dry hole costs
of $2.7 million primarily in the South Texas area of the Gulf Coast region, $2.5
in the Rocky Mountain region, and $1.2 million in the Mid-Continent region and
seismic expenses. The decrease from 2001 to 2002 was mainly due to a decrease in
dry hole expense of $6.9 million, offset by an increase of $1.3 million in
seismic and geological and geophysical expenses along with a $0.9 million
increase in other expenses. Exploration expenses in 2003 increased $7.0 million
compared to 2002 from an increase in dry hole and seismic expenses.
CRUDE OIL MARKETING EXPENSE
We discontinued our crude oil trading activities effective May 2002. Prior
to May 2002, we entered into third party contracts to purchase and resell crude
oil. Although we no longer enter into third party contracts, we will continue to
repurchase our physical production from our Rocky Mountain region and resell
equivalent barrels at Cushing, Oklahoma, to take advantage of better pricing and
to reduce our credit exposure from sales to our first purchaser. We present
sales and purchases of our production from our Rocky Mountain region as crude
oil marketing income and crude oil marketing expense, respectively. We
recognized crude oil marketing expenses of $166.7 million for 2003, compared to
$152.7 million for 2002, and $245.0 million for 2001.
GAS GATHERING, MARKETING AND PROCESSING
Our 2003 gathering, marketing and processing expenses increased to $69.0
million, compared to $29.8 million and $36.4 million in 2002 and 2001,
respectively. The $39.2 million, or 132% increase from 2002 to 2003 was due to
higher natural gas pricesservice operations revenues by $0.8 million to $9.4 million at year end 2006. Associated oil and increased throughput volumes. The increased
volumes resulted from growth on our existing systems and the acquisition of the
Carmen Gas Gathering System from Great Plains Pipeline Company. In 2003, $7.1
million of additional expenses were attributable to the Carmen Gas Gathering
System acquisition.
OIL AND GAS SERVICE OPERATIONS
During 2003, oil andnatural gas service operations expenses increased $0.2 million to $8.2 million during the year ended December 31, 2006 from $8.0 million comparedduring 2005 due mainly to $6.5 million in 2002 and $5.3 million in 2001. The volumes
treated at our central treating unit increased 30,000 barrels in 2003, which
contributed to the $1.2 millionan increase in the costcosts of purchasing and treating oil for resale. In addition, labor related expenses
Operating Costs and Expenses
Production Expense and Tax. Production expense increased $0.4 million
making up the $1.6$10.1 million or 23% increase from 2002 to 2003. The increase from
2001 to 2002 was due to an increase in the cost of purchasing and treating
reclaimed oil for resale by $0.4 million, salaries increased $0.3 million and
general repairs and maintenance made up most of the remaining difference.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES
For19% during the year ended December 31, 2003, depreciation, depletion2006 to $62.9 million from $52.8 million during the year ended December 31, 2005. The increase in 2006 was due to increases of $3.8 million in workovers, $1.4 million in energy and amortizationchemical costs, $1.5 million in repairs, $1.1 million in overhead, $0.6 million in outside operated well costs, $0.5 million in saltwater disposal expenses, $0.4 million in contract labor costs, and as a result of new wells drilled.
Production taxes increased $6.3 million during the year ended December 31, 2006 to $22.3 million from $16.0 million during 2005. The majority of the production tax increase was $5.9 million in the Rocky Mountain region. Production tax as a percentage of oil and natural gas propertiessales was $37.3 million,4.4% for the year ended December 31, 2005 compared to $26.94.8% for the year ended December 31, 2006. Production taxes are based on the wellhead values of production and vary by state. Additionally, some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of oil or gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana, new horizontal wells qualify for a tax incentive and are taxed at 0.76% during the first 18 months of production. After the 18 month incentive period expires, the tax rate increases to 9.26%. During the year ended December 31, 2006, 21 wells reached the end of their exemption period and their tax rate increased from 0.76% to 9.26%. Also in the Rocky Mountain region, 8 wells were added in North Dakota at a rate of 11.5%. As production tax incentives we currently receive for horizontal wells in Montana continue to reach the end of the 18 month incentive period, our overall rate is expected to increase.
On a unit of sales basis, production expense and production taxes were as follows:
| Year ended December 31, | Percent increase (decrease) | ||||||||
| 2006 | 2005 | ||||||||
Production expense ($/Boe) | $ | 6.99 | $ | 7.32 | (5 | )% | |||
Production tax ($/Boe) | 2.48 | 2.22 | 12 | % | |||||
Production expense and tax ($/Boe) | $ | 9.47 | $ | 9.54 | (1 | )% | |||
Exploration Expense. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses increased $14.5 million for 2002 and $23.6in 2006 to $19.7 million for 2001. The average depreciation, depletion
and amortization rate per Boe was $7.10 for 2003, $5.04 for 2002, and $4.90 for
2001. Thedue primarily to an increase in DD&A rates for 2003 compared to 2002dry hole expense of $11.9 million and an increase in seismic expenses of $2.0 million. The Rocky Mountain region contributed 54% of the dry hole costs, 24% was caused by higher
production decline ratesin the Mid-Continent region and the remaining 22% was in the Gulf Coast region. DEPRECIATION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
Depreciation and amortizationThe increase in dry hole expense was due to a higher level of other property and equipment was $5.0drilling during 2006. Exploration capital expenditures were $68.7 million in 20032006 compared to $9.3 million in 2005.
Depreciation, Depletion, Amortization and Accretion (DD&A.) DD&A on oil and gas properties increased $15.3 million in 2006 due to increased production and additional properties being added through our drilling program. The DD&A rate on oil and gas properties for 2005 was $6.50 per Boe compared to $6.91 per Boe for 2006. Accretion expense increased $0.1 million to $1.7 million during 2006 from $1.6 million during 2005.
Property Impairments. Property impairments increased during 2006 by $4.9 million to $11.8 million compared to $6.9 million for 2005. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other non-producing properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period. Impairment of non-producing properties increased $1.0 million during 2006 to $5.4 million compared to $4.4 million in 2002 and $4.1 million in 2001. The
increase in 2003 was primarily due to higher depreciation cost on fixed assets
related to the acquisition of the Carmen Gathering System on August 1, 2003.
PROPERTY IMPAIRMENTS
During 2003, we recorded property impairments of $9.0 million, compared to
$25.7 million in 2002 and $10.1 million in 2001. This includes impairment of our
nonproducing leaseholds as well as FASB 144 impairments. In 2003, leasehold
impairment was $4.8 million compared to $23.4 million in 2002. The majority of
the 2002 impairment was related to our acquisition of leasehold properties in
the Worland Field. Our acquisition included 466 proved undeveloped, or PUD,
locations with a PV-10 value of $145.5 million. We allocated $26.7 million to
these potential locations as part of the acquisition price. We have notfor 2005.
Impairment provisions for developed any of the identified PUD locations during the past 5 1/2 years due to
capital constraints imposed by our development of the Cedar Hills Field. A
review of the PUD valuation by our reservoir-engineering department of the
original Ryder Scott report indicates that Ryder Scott's analysis of reserve
potential was accurate for the up-dip portion of the field, but potentially not
applicable to all identified PUD locations. As a result, an impairment change of
$13.5 million was recorded in 2002 on these PUD locations. We initiated a
detailed review of the remaining PUD locations by a consulting firm and the
results were completed on January 2004. This review involved geostatistical
analysis of all available data and development of a neural network correlation
to predict well performance. After economic analysis of specific locations the
recommendation is to begin drilling these locations in 2006. Leasehold
impairment was $5.2 million in 2001, representing a more normalized expense.
We may be required to write-down the carrying value of our oil and gas properties when oilwere approximately $2.5 million for the year ended December 31, 2005 and gas prices are depressed or unusually volatile or as$6.3 million for the year ended December 31, 2006. The increase in 2006
impairment expense resulted primarily from developmental well dry holes and properties where the associated field level reserves were not sufficient to recover capitalized drilling and completion costs.
General and Administrative Expense. General and administrative expense decreased primarily due to a result$2.8 million decrease in equity compensation expense net of reserve revisions, which would result in a charge of $1.5 million associated with our President’s non-equity compensation plan as described under “Management—Summary Compensation Table,” associated with restricted stock grants and stock options under our long-term incentive plans. The decrease in equity compensation was attributable to earnings. Once
incurred, a write-downreduction in the number of equity grants in 2006. On a volumetric basis, general and administrative expense was $3.45 per Boe for 2006 compared to $4.34 per Boe for 2005. We have granted stock options and restricted stock to our employees. The terms of the grants require that, while we are a private company, we are required to purchase vested options and restricted stock at each employee’s request at a per share amount derived from our shareholders’ equity value adjusted quarterly for our PV-10. The obligation to purchase the options is eliminated in the event we become a reporting company under Section 12 of the Exchange Act.
Gain on Sale of Assets. During 2005, we realized a gain of $6.1 million on the sale of oil and gas properties is not reversible atwells and a later
date. We recorded a $3.8loss of $3.1 million FASB 144 write-downson the termination of compressor capital leases. Gains in 2003 compared2006 amounted to approximately $0.3 million on miscellaneous asset sales.
Interest Expense. Interest expense decreased 20% for 2006 due to a $2.3
million FASB 144 write-down in 2002 and a $5.3 million FASB 144 write-down in
2001.
GENERAL AND ADMINISTRATIVE EXPENSE
Our general and administrative expense for 2003 was $11.2 million compared
to $10.7 million for 2002 and $8.8 million for 2001. The majority of the $0.5
million increase in 2003 is the result of increased salaries and employment
expenses due to an increased number of employees in 2003. The $1.9 million
increase in 2002 was primarily attributable to an increased number of employees
in 2002 compared to 2001.
INTEREST EXPENSE
Our interest expense for 2003 was $20.3 million compared to interest
expense in 2002 of $18.4 million and $15.7 million in 2001. The increase in
interest expense in 2002 and 2003 was the result of additional interest paidlower average outstanding debt balance on our credit facility due to higher average debt balances outstanding.
NET INCOME
Our net profit for 2003 was $2.3of $156.6 million compared to a $20.0$184.0 million lossfor 2005 even though the weighted average interest rate on our credit facility was 6.36% for the year ended December 31, 2006 compared to 5.10% for the year ended December 31, 2005. Additionally, in 2002 and a profit of $11.72005, we had an outstanding balance due to our principal shareholder for $48.0 million which was paid in full during December 2005. We paid $2.9 million in 2001. The 2003 increaseinterest on this note during 2005 at a rate of $22.3
million reflects the higher oil6%.
Liquidity and gas prices in 2003, which created an
increase in oil and gas sales of $30.2 million, the increase in production costs
and expenses of $11.7 million, the reduction of property impairments of $16.7
million, the increase in DD&A expense of $11.0 million, and the cumulative
effect of change in accounting principal adjustment of $2.2 million for the
adoption of SFAS No. 143 on January 1, 2003. The 2002 decrease of $31.7 million
reflects, among other items, the lower gas prices in 2002, which created a
decrease in gas revenues of $8.0 million, an increase in DD&A expense and
property impairments of $18.6 million, a $4.5 million decrease in gathering,
marketing and processing margins, an increase in interest expense of $2.1
million, and a decrease in other income of $2.6 million.
FINANCIAL CONDITION
CASH FLOWS
Capital Resources
Our primary sources of liquidity have been cash flowflows generated from operating activities and financing provided by our bank credit facility and byprincipal shareholder. On May 14, 2007, we completed an initial public offering in which we generated net proceeds of $124.5 million. We believe that funds from operating cash flows and the bank credit facility should be sufficient to meet our principal
stockholder, and a private debt offering. Our cash requirements other thaninclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments and contingencies for operations, are for acquisition, exploration, exploitationthe next 12 months. We intend to fund our longer term cash requirements beyond 12 months through operating cash flows, commercial bank borrowings and development ofaccess to equity and debt capital markets. Although our longer term needs may be impacted by factors discussed in the section entitled “Risk Factors,” such as declines in oil and natural gas propertiesprices, drilling results, ability to obtain needed capital on satisfactory terms, and debt service payments.
CASH FLOW FROM OPERATING ACTIVITIES
other risks which could negatively impact production and our results of operations, we currently anticipate that we will be able to generate or obtain funds sufficient to meet our long-term cash requirements. On January 10, 2007, we declared a cash dividend of approximately $18.8 million to our shareholders for tax purposes and, subject to forfeiture, to holders of unvested restricted stock. On January 31, 2007, we paid $18.7 million of the dividend declared. On March 6, 2007, we declared a cash dividend of approximately $33.3 million payable in April 2007 to our shareholders of record as of March 15, 2007, for tax purposes and, subject to forfeiture, to holders of unvested restricted stock. In connection with the completion of our offering on May 14, 2007, we converted from a subchapter S corporation to a subchapter C corporation, and we do not anticipate paying any additional cash dividends on our common stock in the foreseeable future. At December 31, 2007 and 2006, we had cash and cash equivalents of $8.8 million and $7.0 million, respectively, and available borrowing capacity on our credit facility of $135.0 million and $160.0 million, respectively. At February 29, 2008, we had available borrowing capacity on our credit facility of $178.0 million.
Cash Flow from Operating Activities
Our net cash provided by operating activities was $ 65.2$390.6 million, $417.0 million and $265.3 million for 2003
compared to $47.0 million for 2002the years ended December 31, 2007, 2006 and $63.42005, respectively. The decrease in operating cash flows from $417.0 million in 2001. At December 31,
2003, we had a working capital deficit2006 to $390.6 million in 2007 is the result of $15.3 million, cashincreases in oil and cash
equivalents of $2.3 milliongas sales volumes and available capital on our credit facility of
$12.0 million. The working capital deficit isprices not indicative of our inability to
pay our liabilities but ratherbeing fully realized as a result of increases in accounts receivable, inventory, prepaid expenses and accounts payable.
Cash Flow from Investing Activities
During the years ended December 31, 2007, 2006 and 2005 we had cash management.flows used in investing activities (excluding asset sales) of $486.4 million, $326.6 million and $144.8 million, respectively, in our capital program, inclusive of dry hole and seismic costs. The increaseincreases in 2003
was mostlyour capital program in 2007 and 2006 were due to the increaseimplementation of enhanced recovery and increased density drilling in net incomeour Red River units and additional exploration and development drilling.
Cash Flow from operations, whichFinancing Activities
Net cash provided by (used) in financing activities was attributable to higher oil$94.6 million for 2007, ($91.5) million for 2006 and gas prices($141.5) million for 2005. In 2005, cash used in 2003. The decrease in 2002 was
primarily due to the decrease in net income from operations, whichfinancing activities was primarily attributable to the decreased gas prices and crude oil hedging losses.
INVESTING ACTIVITIES
We spent $114.1 millionrepayment of long-term debt. During 2006, cash used in 2003 compared to $113.4 million in 2002 and
$111.0 million in 2001 on acquisitions, exploration, exploitation and
development of oil and gas properties. Our total estimated proved reserves
increased from 68.4 MMBoe in 2001 to 74.9 MMBoe in 2002 and 84.2 MMBoe in 2003.
Our estimated total proved oil reserves increased from 59.7 MMBbls at year-end
2001 to 63.3 MMBbls at year-end 2002 and 73.0 MMBbls at year-end 2003 and
natural gas increased from 52.3 Bcf at year-end 2001 to 69.9 Bcf at year-end
2002 and decreased slightly to 67.1 Bcf at year-end 2003. In 2002, we sold
approximately 12 MBbls of reserves and in 2003 we sold 318 MBbls and 2033 MMcf
of reserves.
FINANCING ACTIVITIES
Our long-term debt, including current portion, was $290.9 million at
December 31, 2003 compared to $247.1 million at December 31, 2002, and $183.4
million at December 31, 2001. The $43.8 million, or 18% increase in 2003 was
primarily due to the increase in our bank debt of $24.9 million for development
of Cedar Hills, a $17.0 million increase in bank debt of Continental Gas, Inc.,
or CGI, for the Carmen Gathering System, and additional capital leases of $1.9
million. The $63.7 million, or 35%, increase in 2002financing activities was primarily attributable to a $51.8 million increasethe payment of cash dividends and during 2007, cash used in our bank debt along withfinancing activities was primarily attributable to financing capital leasesexpenditures and the payment of $12.0
million. We used the majoritycash dividends. Cash provided by financing activities in 2007 included net of the proceeds of $124.5 million from our 2003 and 2002 borrowings
for development of the Cedar Hills Field and the purchase of the Carmen
Gathering System.
LIQUIDITY AND CAPITAL REQUIREMENTS
CREDIT FACILITY
initial public offering.
Credit Facility
We had $132.9$165.0 million and $140.0 million outstanding debt balance under our primarybank credit facility at December 31, 2003. Our secured2007 and 2006, respectively. As of February 29, 2008, the amount outstanding under our credit facility has increased by $57.0 million to $222.0 million. The increase was largely due to borrowings to finance the purchase of producing properties from Chesapeake Energy for $55.2 million in January 2008.
The credit facility matures on March 28,
2005. BorrowingsApril 12, 2011, and borrowings under our credit facility bear interest, based onpayable quarterly, at (a) a rate per annum equal to the rate at which eurodollar depositsLondon Interbank Offered Rate for one, two, three or six months areas offered by the lead bank plus an applicable margin ranging from 150100 to 250175 basis points, depending on the percentage of our borrowing base utilized or (b) the lead bank'sbank’s reference rate plus an applicable margin
ranging from 25 to 50 basis points.rate. The effective rate of interest under our credit facility was 3.75% at December 31, 2003 and 4.37% at December 31, 2002.
At December 31, 2003, thehas a note amount of $750.0 million, a borrowing base of our credit facility was $145.0$600.0 million, subject to semi-annual redetermination, and a commitment level of $400.0 million. The borrowing base is re-determined semi-annually. Borrowings under ourthe credit facility are secured by liens on substantially all of our assets.
Between December 31, 2003 and March 29, 2004, we have drawn $7.5 million
under our credit facility and currently $140.4 million is outstanding under this
facility. On October 22, 2003, our subsidiary, Continental Gas, Inc., or CGI,
established a new $35.0 million secured credit facility consisting of a senior
secured term loan facility of up to $25.0 million and a senior revolving credit
facility of up to $10.0 million. The initial advance under the term loan
facility was $17.0 million, which was paid to us to reduce the outstanding
balance on our credit facility. No funds were initially advanced under the
revolving loan facility. Advances under either facility can be made, at the
borrower's election, as reference rate loans or LIBOR loans and, with respect to
LIBOR loans, for interest periods of one, two, three, or six months. Interest is
payable on reference rate loans monthly and on LIBOR loans at the end of the
applicable interest period. The principal amount of the term loan facility is to
be amortized on a quarterly basis through June 30, 2006, the final payment being
due September 30, 2006. The amount available under the revolving loan facility
may be borrowed, repaid and reborrowed until maturity on September 30, 2006.
Interest on reference rate loans is calculated with reference to a rate equal to
the higher of the reference rate of Union Bank of California, N.A. or the
federal funds rate plus 0.5%. Interest on LIBOR loans is calculated with
reference to the London interbank offered interest rate. Interest accrues at the
reference rate or the LIBOR rate, as applicable, plus the applicable margin. The
margin is based on the then current senior debt to EBITDA ratio. The credit
agreement contains certain covenants and requires certain quarterly mandatory
prepayments of 75% of excess cash flow. The credit facility is secured by a
pledge of all of the assets of CGI.
On October 22, 2003, CGI ceased to be a guarantor of our obligations under
our credit agreement. At that time, the borrowing base under the amended credit
agreement was revised to $145.0 million and our outstanding balance was reduced
by the $17.0 million funded to CGI.
SENIOR SUBORDINATED NOTES
On July 24, 1998, we issued $150.0 million of our 10 1/4% Senior
Subordinated Notes due August 1, 2008, in a private placement. Interest on the
senior subordinated notes is payable semi annually on each February 1 and August
1. In connection with the issuance of the senior subordinated notes, we incurred
debt issuance costs of approximately $4.7 million, which we have capitalized as
other assets and amortize on a straight-line basis over the life of the senior
subordinated notes.
During 2001, we repurchased $3.0 million principal amount of our senior
subordinated notes at a cost of $2.7 million. We wrote off $0.1 million of the
issuance costs associated with the repurchased senior subordinated notes.
FUTURE CAPITAL EXPENDITURES AND COMMITMENTS
We had capital expenditures of $114.1 million during the year ended
December 31, 2003. We will initiate, on a priority basis, as many projects as
cash flow allows. We anticipate that we will initiate approximately 88 projects
in 2004 for projected capital expenditures of $81.9 million. However, the amount
and timing of capital expenditures may vary depending on the rate at which we
expand and develop our oil and gas properties and whetherassociated assets of the Company. Our next semi-annual redetermination is during April 2008. The terms of the credit facility allow us to determine the commitment level up to the borrowing base.
The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. The facility also requires us to maintain certain ratios as defined and further described in our credit facility: a Current Ratio of not less than 1.0 to 1.0 (adjusted for available borrowing capacity), a Total Funded Debt to EBITDAX, as defined, of no greater than 3.75 to 1.0. As of December 31, 2007, we consummate
additional debtwere in compliance with all covenants.
Capital Expenditures and Commitments
We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at its final maturities
various times. We seek acquisitions that utilize our technical expertise or offer opportunities to expand our existing core areas such as the purchase of producing properties in the Williston Basin for $55.2 million in January 2008. Acquisition expenditures are not budgeted.
We invested approximately $525.7 million (inclusive of non-cash accruals of $36.4 million) for capital and exploration expenditures in 2007 as follows (in millions):
| Amount | |||
Exploration and development drilling | $ | 440.7 | |
Purchase of properties | 4.2 | ||
Dry holes | 3.5 | ||
Capital facilities, workovers and re-completions | 39.1 | ||
Land costs | 30.8 | ||
Seismic | 2.9 | ||
Vehicles, computers and other equipment | 4.5 | ||
| $ | 525.7 | ||
Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We have budgeted approximately $616.0 million for capital and exploration expenditures in 2008 as follows (in millions):
| Amount | |||
Exploration and development drilling | $ | 490.0 | |
Capital facilities, workovers and re-completions | 57.0 | ||
Land costs | 39.0 | ||
Seismic | 17.0 | ||
Vehicles, computers & other equipment | 13.0 | ||
| $ | 616.0 | ||
Our budgeted capital expenditures are expected to increase approximately 17% over the $525.7 million invested during 2007. We plan to invest approximately $272.0 million in development drilling. In the Red River units, we plan to invest approximately $146.0 million to drill infill wells and extend horizontal laterals on existing wells to increase production and sweep efficiency of the enhanced recovery projects. Most of the remaining development drilling budget is expected to be invested in the drilling of development wells in the Montana Bakken field. We have budgeted approximately $218.0 million for exploratory drilling with approximately $65.0 million and $51.0 million allocated to drilling exploratory wells in the North Dakota Bakken field and the Arkoma Woodford project, respectively.
Although we cannot provide any assurance, assuming successful implementation of our strategy, including the future development of our proved reserves and realization of our cash flows as anticipated, we believe that our remaining cash balance, cash flows from operations and borrowings available to us under our credit facilities, the remaining balance of
our unrestricted cash and cash flows from operationsfacility will be sufficient to satisfy our current expected2008 capital expenditures, working capital and debt
service obligations for the foreseeable future.budget. The actual amount and timing of our future capital requirementsexpenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the market pricesavailability of oildrilling rigs and natural gas,other services and equipment, and regulatory, technological and competitive developments. Sources
Shareholder Distribution
On January 10, 2007, we declared a cash dividend of additional
financing may include commercial bank borrowings, vendor financing and the sale
of equity or debt securities. We cannot assure you that any such financing will
be available on acceptable terms or at all.
STOCKHOLDER DISTRIBUTION
During 2003, we paid no dividends to our stockholders. The terms of the
indenture and our credit facility restrict our ability to pay dividends.
However, because we are an "S Corporation" for federal income tax purposes, we
pay dividendsapproximately $18.8 million to our shareholders in an amount sufficientand, subject to pay the taxes on
our taxable income passed throughforfeiture, to the shareholders.
HEDGING
From time to time,holders of unvested restricted stock. On January 31, 2007, we utilize energy derivative contracts to hedge the
price or basis risk associated with the specifically identified purchase or
sales contracts, oil and gas production or operational needs. Prior to January
1, 2001, we accounted for changes in the market value of derivative instruments
used for hedging as a deferred gain or loss until the production monthpaid $18.7 million of the hedged transaction, atdividend declared, of which time the gain or loss on the derivative instruments$16.9 million was recognized in earnings. Effective January 1, 2001,paid to our principal shareholder. On March 6, 2007, we account for derivative
instruments in accordance with SFAS No. 133 "Accounting for Derivative
Instrumentsdeclared a cash dividend of approximately $33.3 million to our shareholders of record and, Hedging Activities." The specific accounting treatment for
changes in the market valuesubject to forfeiture, to holders of unvested restricted stock. On April 12, 2007, we paid $33.1 million of the derivative instruments used in hedging
activities is determined based on the designationdividend declared, of the derivative instruments
as a cash flow, fair value, or foreign currency exposure hedge, and
effectiveness of the derivative instruments.
Additionally, in the normal course of business, we will enter into fixed
price forward sales contracts relatedwhich $30.0 million was paid to our oil and gas productionprincipal shareholder. We converted from a subchapter S corporation to reduce
our sensitivity to oil and gas price volatility. We deem forward sales contracts
that will result in physical delivery of our production to be in the normal
course of our businessa subchapter C corporation on May 14, 2007 when we became a publicly traded company, and we do not account for them as derivatives. Revenues
from fixed price sales contractsanticipate paying any additional cash dividends on our common stock in the normal course of business are recognized
as production occurs. As of December 31, 2003, we had no fixed price swaps or
forward contracts in place.
Our amended credit agreement requires us to have 50% of our oil production
hedged on a rolling six-month term. Beginning in October 2003, we established
costless collars to satisfy this requirementforeseeable future.
Obligations and at December 2003 we had the
following costless collars in place. These contracts are being accounted for as
cash flow hedges.
In order to mitigate price risk exposure on production, CGI has forward
sales contracts in place that will result in the physical delivery of production
and qualify as being in the normal course of business sales and are not
accounted for as derivatives. As of December 31, 2003, CGI has 50,000 MMBTU per
month hedged from January 2004 thru December 2007 at an average price of $4.579
per MMBTU. These hedges account for 9% of the total delivery point volumes and
4% of overall company throughput.
The following table summarizes our hedged contracts in place at December
31, 2003:
2004 2005 2006 2007
---- ---- ---- ----
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 600,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Collars:
Contract Volumes (Bbls)
Floor 1,115,000 - - -
Ceiling 1,115,000 - - -
Weighted-average Fixed Price per Bbl
Floor $ 22.00 $ - $ - $ -
Ceiling $ 35.24 $ - $ - $ -
OBLIGATIONS AND COMMITMENTS
Commitments
We have the following contractual obligations and commitments as of December 31, 2003:
2007:
| Payments due by period | |||||||||||||||
| Total | Less than 1 year | 1 - 3 years | 3 - 5 years | More than 5 years | |||||||||||
| (in thousands) | |||||||||||||||
Bank credit facility(1) | $ | 165,000 | $ | — | $ | — | $ | 165,000 | $ | — | |||||
Operating leases | 5,956 | 5,290 | 644 | 22 | — | ||||||||||
Asset retirement obligations(2) | 42,092 | 3,939 | 4,435 | 758 | 32,960 | ||||||||||
Total contractual cash obligations | $ | 213,048 | $ | 9,229 | $ | 5,079 | $ | 165,780 | $ | 32,960 | |||||
| (1) | Payments |
| (2) | Amounts represent expected asset retirements by |
Critical Accounting Policies and Practices
Our historical consolidated financial statements and notes to our historical consolidated financial statements contain information that is pertinent to the following
Management's Discussionour management’s discussion and Analysis.analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Generally, accounting rules do not involve a selection among
alternatives, but involve a selection of the appropriate policies for applying
the basic principles. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.
In management'smanagement’s opinion, the more significant reporting areas impacted by management'smanagement’s judgments and estimates are cruderevenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, derivatives and impairment of assets, and derivative
instruments. Management'sassets. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
Revenue Recognition
We derive substantially all of our revenues from the sale of oil and natural gas. Oil and gas revenues are recorded in the month the product is delivered to the purchaser and title transfers. We generally receive payment from one to three months after the sale has occurred. Each month we estimate the volumes sold and the price at which they were sold to record revenue. Variances between estimated revenue and actual amounts are recorded in the month payment is received.
Successful Efforts Method of Accounting
We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized on an individual property, field or unit basis using the unit-of-production method as oil and natural gas is produced. TheThis accounting method may yield significantly different operating results than the full cost method.
method of accounting.
Depreciation, depletion and amortization, or DD&A, of capitalized exploratory drilling and development costs of producing oil and natural gas properties are generally computed using the unitsunit of production method on an individual property, field or unit basis based on total estimated proved developed oil and natural gas reserves. Amortization of producing leasehold is based on the unit-of-production method using total estimated proved reserves. In arriving
at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers. Gas
gathering systemsengineers and gas processing plants are depreciated using the
straight-line method over an estimated useful life of 14 years.independent engineers. Service properties, equipment and other assets are depreciated using the straight-line method over estimated useful lives of 5 to 40 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
As stated above, DD&A
Non-producing properties consist of capitalized exploratory drillingundeveloped leasehold costs and development
costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing oil and gasproperties. Individually significant non-producing properties are generally computed using the unitsperiodically assessed for impairment of production method on total estimated proved developed oilvalue.
Equity Compensation
We account for employee and gas reserves.
However, successful efforts of accounting provides thatdirector stock option grants and restricted stock grants in instances in which a
significant amount of development costs relate to both proved developed and
proved undeveloped reserves, a distortion in the DD&A rate would occur if such
development costs were amortized over only proved developed reserves. At
December 31, 2003, we have capitalized drilling and development costs of
approximately $168.6 million related to the high-pressure air injection project
currently in process in the Cedar Hills Field. Proved reserves associatedaccordance with this field are approximately 42.2 MBoe of which 28.5 MBoe or 67% are proved
undeveloped. At December 31, 2003, we have excluded approximately $112.9 million
or 67%SFAS 123(R). The terms of the development costsrestricted stock grants and stock option grants stipulated that, until we became a reporting company under Section 12 of the Exchange Act in May 2007, we were required to purchase the vested restricted stock and stock acquired from its costs basestock option exercises at each employee’s request based upon the purchase price as determined by a formula specified in each award agreement. Additionally, we had the right to purchase vested restricted stock and stock acquired from stock option exercises at the same price upon termination of employment for any reason and for a period of two years subsequent to leaving our employment. Therefore, the awards were accounted for as liability awards in accordance with SFAS 123(R). We measure compensation cost for the awards based upon fair value. Restricted stock and stock option values represent intrinsic value prior to 2006 and fair value after March 7, 2006, the date on which we first filed the registration statement and as a result became a “public entity” for purposes of computing
DD&A. InSFAS 123(R). Fair value of stock options is determined using the Black-Scholes option valuation model. SeeNotes to Consolidated Financial Statements—Note 12. Stock Compensation included elsewhere in this report.
The right to sell and requirement to purchase lapsed when we become a reporting company under Section 12 of the Exchange Act. Therefore, the liability for equity compensation was reclassified to additional paid in capital upon becoming a public reporting company.
The value of granted stock options and restricted stock until March 7, 2006 was based on each grant’s intrinsic value. Since March 7, 2006, we have recognized stock-based compensation expense at fair value. We did not prepare or obtain contemporaneous valuations by an unrelated valuation specialist during 2006 because we did not consider it necessary to value our stock options and restricted stock. We utilized the probability-weighted expected return method to estimate the value of our stock option and restricted stock grants. Fair value under this method is estimated based upon an analysis of future periods,values for the proved undeveloped reserves will be transferred to
proved developed as such reserves meetgrants based upon the definitionprobability of proved reserves under
SEC guidelines. Costs associatedvarious outcomes and the rights of each share class. We considered numerous future outcomes and determined that the outcomes with the Cedar Hills Field will be addedhighest probability were completion of the initial public offering within one year discounted back to the cost baseapplicable valuation dates and termination of the initial public offering and continuing as a privately held entity. These alternatives were deemed to be equally likely.
Determining the fair value of our stock based compensation requires making complex and subjective judgments, which are inherently uncertain. The assumptions underlying our estimates are consistent with our understanding and evaluation of different alternatives during 2006 and our discussion of these alternatives with our board of directors, investment bankers and other interested parties. Valuations would have been different had different estimates been utilized.
In calculating the value of stock option grants, we utilized the Black-Scholes option-pricing method. This method requires that we make estimates of the volatility of our equity securities and assess the timing of future events, as previously described. As there was no readily available market for our stock prior to our initial public offering, we based our volatility assumptions on available information on the ratiovolatility of proved developed reservesthe publicly traded stocks of other exploration and production companies considered to proved undeveloped
reserves. be similar in size and operations to us. Had we used different assumptions for volatility, estimated amounts would be different.
Oil and Natural Gas Reserves and Standardized Measure of Future Cash Flows
Our future DD&A rate on this field could be significantly impacted by
upward or downward revisions in the oil and gas reserve estimates associated
with this field.
OIL AND GAS RESERVES AND STANDARDIZED MEASURE OF FUTURE CASH FLOWS
Our geologists andindependent engineers and independent engineers,technical staff prepare the estimates of our oil and natural gas reserves and associated future net cash flows. Current accounting guidance allows only proved oil and natural gas reserves to be included in our financial statement disclosures. The SEC has defined proved reserves as the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Even though our geologists andindependent engineers and independent
engineerstechnical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each field. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, and cost changes, technological advances, new geological or geophysical data, or other economic factors. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter future DD&A and /or result in impairment of assets that may be material.
ASSET RETIREMENT OBLIGATIONS
Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/orand the normal operation of a long-lived asset. The primary impact of this standard on us relates to oil and natural gas wells on which we have a legal obligation to plug and abandon. SFAS No. 143 requires us to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The determination of the fair value of the liability requires us to make numerous judgments and estimates, including judgments and estimates related to the future salvage value of well equipment, future costs to plug and abandon wells, future inflation rates and estimated lives of the related assets.
IMPAIRMENT OF ASSETS
Derivatives
The Company accounts for its derivative activities under the guidance provided by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, and recognizes all of its derivative instruments as assets or liabilities in the balance sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. In July 2007, the Company entered into fixed-price swap contracts covering 10,000 barrels of oil per day for the period from August 2007 through April 2008. The Company has elected not to designate its derivatives as cash flow hedges under the provisions of SFAS No. 133. As a result, the Company marks its derivative instruments to fair value in accordance with the provisions of SFAS No. 133 and recognizes the realized and unrealized change in fair value on derivative instruments in the statements of income. The fair value of derivative liabilities is determined based on the quoted market value of the underlying NYMEX commodity contracts. SeeNotes to Consolidated Financial Statement—Note 5. Derivative Contracts for more information. The Company had no open hedges at December 31, 2006 or 2005.
Impairment of Assets
All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of thean asset may be greater than its future net cash flows, including cash flows from risk adjusted provableproved reserves. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and
regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or unfavorable adjustmentsdownward revisions to oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.
DERIVATIVE ACTIVITY
We attempt to reduce our exposure to unfavorable oil and natural gas prices
by utilizing fixed-price physical delivery contracts and zero-cost collar
contracts. We account
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
Recent Accounting Pronouncements
In June 2006, the FASB issued Interpretation No. 48, Accounting for these derivative contracts underUncertainty in Income Taxes (“FIN 48”). The interpretation clarifies the guidance
prescribed byaccounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 133,109, Accounting for Derivative InstrumentsIncome Taxes. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on the Company’s consolidated financial position or results of operations. The Company’s policy is to recognize penalties and Hedging Activities (SFAS No. 133). Except for
certain fixed price contracts qualifying forinterest, if any, in income tax expense.
In September 2006, the normal sales exception under
SFAS No. 133, all derivative contracts are recorded as assets and liabilities in
the consolidated balance sheet at fair value, determined based on quoted market
prices. The counter parties to these contractual arrangements are limited to
creditworthy institutions.
The above description of our critical accounting policies is not intended
to be an all-inclusive discussion of the uncertainties considered and estimates
made by management in applying accounting principles and policies. Results may
vary significantly if different policies were used or required and if new or
different information becomes known to management.
Newly Issued Accounting PronouncementsFASB issued Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations
(FAS 141),157,Fair Value Measurementswhich will become effective in 2008. This Statement defines fair value, establishes a framework for measuring fair value, and Statement of Financial Accounting Standards No. 142, Goodwill and
Other Intangible Assets (FAS 142), were issued in June 2001 and became effective
for the Company on July 1, 2001 and January 1, 2002, respectively. We understand
the majority of the oil and gas industry didexpands disclosures about fair value measurements; however, it does not change accounting and
disclosures for mineral interest use rights upon the implementation of FAS 141
and 142. However, an interpretation of FAS 141 and 142 is being considered as to
whether mineral interest use rights in oil and gas properties are intangible
assets. Under this interpretation, mineral interest use rights for both
undeveloped and developed leaseholds would be classified as intangible assets,
separate from oil and gas properties. This interpretation would not affect our
results of operations or cash flows.require any new fair value measurements. In November 2002,February 2008, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guaranteesgranted a one-year deferral of Indebtedness of Others-an Interpretation of FASB
Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34. For
certain guarantees, FIN 45 requires recognition at the inception of a guarantee
of a liability for the fair value of the obligation assumed in issuing the
guarantee. FIN 45 also requires expanded disclosures for outstanding guarantees,
even if the likelihood of the guarantor having to make any payments under the
guarantee is considered remote. The recognition provisions of FIN 45 were
effective for guarantees issued or modified after December 31, 2002. We have not
issued or modified any material guarantees within the scope of FIN 45 during
2003; therefore, implementation of this new standard has not impacted our
consolidated financial condition or results of operations.
In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities - an Interpretation of ARB No. 51. This interpretation
clarifies the application of ARB 51, Consolidated Financial Statements to
certain entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. Because application of the majority voting interest
requirement in ARB 51 may not identify the party with a controlling financial
interest in situations where controlling financial interest is achieved through
arrangements not involving voting interests, this interpretation introduces the
concept of variable interests and requires consolidation by an enterprise having
variable interests in previously unconsolidated entity if the enterprise is
considered the primary beneficiary, meaning the enterprise will absorb a
majority of the variable interest entity's expected losses or residual returns.
For variable interest entities in existence as of February 1, 2003, FIN 46, as
originally issued, required consolidation by the primary beneficiary in the
third quarter of 2003. In October 2003, the FASB deferred the effective date of FIN 46this statement as it applies to nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (e.g. those measured at fair value in a business combination and goodwill impairment). The provisions of SFAS No. 157 will be applied prospectively to fair value measurements and disclosures in our Consolidated Financial Statements beginning in the fourth quarter. We have reviewedfirst quarter of 2008. The impact from adoption relating to financial assets and liabilities is not expected to be significant; however the effectsimpact, if any, from the adoption relating to non-financial assets and liabilities will depend on the Company’s assets and liabilities at the time they are required to be measured at fair value.
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FIN 46 relativeFASB Statement No. 115.This Statement provides entities with an option to its relationshipschoose to measure eligible items at fair value at specified election dates. If elected, an entity must report unrealized gains and losses on the item in earnings at each subsequent reporting date. The fair value option: may be applied instrument by instrument, with possible variable interest entitiesa few exceptions, such as investments otherwise accounted for by the equity method; is irrevocable (unless a new election date occurs); and have determinedis applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. Management does not believe that the adoptionimplementation of such standard had noSFAS No. 159 will have a material impact on usour consolidated financial position or results of operation.
In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations(SFAS 141(R)) and SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51(SFAS 160). SFAS 141(R) will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 141(R) and SFAS 160 are effective for both public and private companies for fiscal years beginning on or after December 15, 2008 (fiscal 2009 for the Company). SFAS 141(R) will be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 will be applied prospectively. Early adoption is prohibited for both standards. The adoption of SFAS 141(R) and SFAS 160 is not expected to have a material impact on our consolidated financial position or results of operation.
Inflation
Historically, general inflationary trends have not had a material effect on our operating results. However, we have no
interestsexperienced inflationary pressure on technical staff compensation and the cost of oilfield services and equipment due to the increase in any material variable interest entities.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
drilling activity and competitive pressures resulting from higher oil and natural gas prices in recent years.
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
We are exposed to a variety of market risks including credit risks,risk, commodity price risk and interest rate risk. We address these risks through a controlled program of risk management includingwhich may include the use of derivative instruments.
COMMODITY PRICE EXPOSURE
Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates. SeeNotes to Consolidated Financial Statements.—Note 1. Organization and Summary of Significant Accounting Policies.We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. Although we have not generally required our counterparties to provide collateral to support trade receivables owed to us, we routinely require prepayment of working interest holders’ proportionate share of drilling costs. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk.
Commodity Price Risk.We are exposed to market risk as the prices of crude oil natural gas, and natural gas liquids are subject to fluctuations resulting from changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we may hedge (throughhave hedged in the past, through the utilization of derivatives, including zero-cost collars and fixed price contracts)contracts. We had no hedging contracts in place during 2006 or through June 30, 2007. In July 2007, we entered into fixed-price swap contracts covering 10,000 barrels of oil per day for the period from August 2007 through April 2008. During each month of the contract, we will receive a portionfixed-price of our production$72.90 per barrel and sale
contracts. A sensitivity analysis has been prepared to estimate the price
exposurewill pay to the market riskcounterparties the average of ourthe prompt NYMEX crude oil natural gasfutures contract settlement prices for such month. SFAS No. 133, “Accounting for Derivative Instruments and natural gas
liquids commodity positions. Our daily net commodity position consistsHedging Activities” requires recognition of crude
inventories, commodity sales contracts andall derivative commodity instruments. Theinstruments on the balance sheet as either assets or liabilities measured at fair value. We elected not to designate our derivatives as cash flow hedges under the provisions of SFAS No. 133. As a result, we mark our derivative instruments to fair value in accordance with the provisions of such position is a summation ofSFAS No. 133 and recognize the fair values calculated for
each commodity by valuing each net position at quoted futures prices. Market
risk is estimated as the potential lossrealized and unrealized change in fair value resulting fromas a hypothetical 10 percent adverse changegain (loss) on derivative instruments in such pricesthe statements of income. As of December 31, 2007 we recorded a liability for unrealized losses on derivatives of $26.7 million. During the year ended December 31, 2007, we had realized losses on derivatives of $18.2 million. As of December 31, 2007, a one dollar increase or decrease in the NYMEX crude futures price would result in approximately $1.2 million loss or gain over the next 12 months.
Basedremaining life of our derivatives. At February 29, 2008 the fair market value of unrealized derivatives losses was $17.3 million. In addition, we had realized losses on this analysis, we have no significant market risk related to our
hedging portfolio. See "Hedging" paragraph in Item 7 abovederivatives for discussionJanuary and February 2008 of derivative and hedging contracts outstanding at December 31, 2003.
INTEREST RATE RISK$12.7 million.
Interest Rate Risk. Our exposure to changes in interest rates relates primarily to long-term debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We mightmay utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility. We had total indebtedness of $222.0 million outstanding under our credit facility at February 29, 2008. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $2.2 million and a $1.4 million decrease in net income. Our weighted average interest rate at December 31, 2007 was 6.26%. Since year end we have experienced a reduction in interest rates as our credit facility tranches mature
and are renewed. Our weighted average interest rate at February 29, 2008 was 5.62%. The fair value of long-term debt is estimated based on quoted market prices and management'smanagement’s estimate of current rates available for similar issues. The following table itemizes our long-term debt maturities and the weighted-average interest rates by maturity date.
date:
| 2008 | 2009 | 2010 | 2011 | 2012 | Total | |||||||||||||||
| (in thousands) | ||||||||||||||||||||
Variable rate debt: | ||||||||||||||||||||
Credit facility: | ||||||||||||||||||||
Principal amount | $ | — | $ | — | $ | — | $ | 165.0 | $ | — | $ | 165.0 | ||||||||
Weighted-average interest rate | 6.26 | % | 6.26 | % | ||||||||||||||||
Index to Consolidated Financial Statement Schedules, and Reports on Form
8-K
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Arthur Andersen LLP audited our financial statements for 2000 and 2001. As
a result of Andersen's liquidation, we changed our auditors to Ernst & Young LLP
on July 12, 2002. This change was reported in a current report on Form 8-K dated
July 16, 2002.
ITEM 9A. CONTROLS AND PROCEDURES
Our Chief Executive Officer and our Chief Financial Officer evaluated the
effectiveness of the design and operation of our disclosure controls and
proceduresStatements
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Continental Resources, Inc. and Subsidiary Consolidated Financial Statements: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Consolidated Balance Sheets as of | 50 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Consolidated Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005 Report of Independent Board of Directors Continental Resources, Inc. We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. and We conducted our audits in accordance with In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Continental Resources, Inc. and /s/ GRANT THORNTON LLP Oklahoma City, Oklahoma March 13, 2008 Continental Resources, Inc. and Subsidiary Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements. Continental Resources, Inc. and Subsidiary Consolidated Statements of Income
See Note 1 relating to pro forma information. The accompanying notes are an integral part of these consolidated financial statements. Continental Resources, Inc. and Subsidiary Consolidated Statements of Shareholders’ Equity
The accompanying notes are an integral part of these consolidated financial statements. Continental Resources, Inc. and Subsidiary Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements. Continental Resources, Inc. Notes to 1. Organization and Summary of Significant Accounting Policies Description of Company Continental Resources, Inc. On May 14, 2007, the Company completed its initial public offering. In conjunction therewith, the Company affected an 11 for 1 Basis of Continental All significant inter-company accounts and transactions have been eliminated in the consolidated financial statements. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Of the estimates and assumptions that affect reported results, the estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment on producing oil and gas properties, is the most significant. Pro forma information (unaudited) Pro forma adjustments are reflected on the consolidated statements of income to provide for income taxes in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109 “Accounting for Income Taxes” as if the Company had been a subchapter C corporation for all periods presented. For unaudited pro forma income tax calculations, deferred tax assets and liabilities were recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 35% and effective state tax rate of 3% (net of Federal income tax effects) were used for the pro forma enacted tax rate for all periods. The pro forma tax effects are based upon Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) currently available information. Management believes that these assumptions provide a reasonable basis for representing the pro forma tax effects. The pro forma information should be read in conjunction with the related historical information and is not necessarily indicative of the results that would have been Revenue recognition Oil and natural gas sales result from interests owned by the Company in oil and natural gas properties. Sales of oil and natural gas produced from oil and natural gas operations are recognized when the product is delivered to the Cash and cash equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk. Accounts receivable The Company operates exclusively in oil and natural gas exploration and production related activities. Oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s loss history, and the customer or working interest owner’s ability to pay. The Company writes off specific accounts when they become uncollectible and any payments subsequently received on these receivables are credited to the allowance for doubtful accounts. The following table presents the allowance for doubtful accounts at December 31, 2005, 2006 and 2007 and changes in the allowance for these years:
Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant customers. The largest purchasers of the Company’s oil and gas production accounted for 44% (three purchasers), 33% (two purchasers) and 60% (three purchasers) of total oil and natural gas sales revenues for 2007, 2006 and 2005, respectively. These purchasers constituted all purchasers with oil Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) and natural gas sales in excess of 10% of total oil and natural gas sales. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as oil and natural gas are fungible products with well-established markets and numerous purchasers. Inventories Inventories are stated at the lower of cost or market. Inventory consists primarily of tubular goods and production equipment, which totaled approximately $4.7 million and $4.2 million at December 31, 2007 and 2006, respectively, and crude oil line fill and temporary storage of approximately $14.4 million, representing 384,000 barrels of crude oil, and $3.6 million, representing 95,000 barrels of crude oil, at December 31, 2007 and 2006, respectively. Property and equipment Property and equipment are capitalized and stated at cost, while maintenance and repairs are expensed as incurred. Depreciation and amortization are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. Estimated useful lives are as follows:
Oil and gas properties The Company uses the successful efforts method of accounting for oil and gas properties whereby costs to acquire mineral interests in oil and gas properties, drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Geological and geophysical costs, seismic costs, lease rentals and costs associated with unsuccessful exploratory wells are expensed as incurred. Maintenance and repairs are expensed as incurred, except that the cost of replacements or renewals that expand capacity or improve production are capitalized. The Company reports capitalized exploratory drilling costs on the balance sheet according to SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”. On a monthly basis, the Company capitalizes the costs of drilling exploratory wells pending determination of whether the well has found proved reserves. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, associated capitalized costs become part of well equipment and facilities; however, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Total capitalized exploratory drilling costs, as of December 31, 2007 and 2006, pending the determination of proved reserves were $32.9 million and $10.0 million, respectively. As of December 31, 2007, exploratory drilling costs of $3.1 million representing five wells were suspended beyond one year Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) Production expenses are those costs incurred by the Company to operate and maintain its oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, and materials and supplies utilized in the Company’s operations. The Company accounts for its asset retirement obligations pursuant to SFAS No. 143, The
As of December 31, 2007 and Depreciation, depletion, amortization, accretion and Depreciation, depletion, and amortization (DD&A) of capitalized drilling and development costs, including related support equipment and facilities, of producing oil and gas properties are Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of In accordance with the provisions of Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) risk-adjusted probable reserves are not sufficient to recover the Debt issuance costs Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt. The Company had capitalized costs of $1.7 million and $2.2 million (net of accumulated amortization of $5.0 million and $4.5 million) relating to the issuance of its long-term debt at December 31, 2007 and 2006, respectively. During the years ended December 31, 2007, 2006 and 2005, the Company Derivatives The Fair value of The The fair value of long-term debt Income taxes On May 14, 2007, the Company completed its initial public offering. Prior to completion of the public offering, the Company was Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. Equity compensation The Company accounts for employee stock option grants and restricted stock grants in accordance with SFAS 123(R). The terms of the restricted stock and stock option grants stipulate that, prior to its initial public offering, the Company was required to purchase vested restricted stock and stock acquired from stock option exercises at each employee’s request based upon the purchase price as determined by a formula specified in each award agreement. Additionally, the Company had the right to purchase vested restricted stock and stock acquired from stock option exercises at the same price upon termination of employment for any reason and for a period of two years subsequent to leaving the employment of the Company. Therefore, the awards were accounted for as liability awards in accordance with SFAS 123(R). The Company measures compensation cost for the awards based upon fair value. Restricted stock and stock option values represent intrinsic value prior to 2006 and fair value after March 6, 2006, when the Company became a public entity under SFAS 123(R). Fair value of stock options is determined using the Black-Scholes option valuation model. The right to sell and requirement to purchase lapsed when the Company became a reporting company under Section 12 of the Exchange Act. Therefore, the liability for equity compensation was reclassified to additional paid in capital in May 2007. Earnings per common share Basic earnings per common share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution of non-vested restricted stock awards and dilutive stock options, which are calculated using the treasury stock method as if these options were exercised. The following is the calculation of basic and diluted weighted average shares outstanding and earning per share computations for the years ended December 31, 2007, 2006 and 2005:
Comprehensive income The Company classifies other comprehensive income (loss) items by their nature in the consolidated financial statements and displays the accumulated balance of other comprehensive income (loss) separately in the Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) shareholders’ equity section of the balance sheet. Accumulated other comprehensive income (loss) at December 31, 2006 consisted of foreign currency translation related to its Canadian assets and operations. In 2007, the Company sold its Canadian properties. Recent accounting pronouncements In June 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes(“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in In September 2006, the In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115”. This Statement provides entities with an option to choose to measure eligible items at fair value at specified election dates. If elected, an entity must report unrealized gains and losses on the item in earnings at each subsequent reporting date. The fair value option may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; is irrevocable (unless a new election date occurs); and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. Management does not believe that the implementation of SFAS No. 159 will have a material impact on the Company’s consolidated financial position or results of operations. In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations”(SFAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”(SFAS 160). SFAS 141(R) will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 141(R) and SFAS 160 are effective for the Company for fiscal years beginning on or after December 15, 2008. SFAS 141(R) will be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 will be applied prospectively. Early adoption is prohibited for both standards. The adoption of SFAS 141(R) and SFAS 160 is not expected to have a material impact on the Company’s consolidated financial Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) 2. Cash Flow Information Net cash provided by operating activities reflects cash payments as follows (in thousands):
Noncash investing and financing activities are as follows (in thousands):
3. Property, Plant, and Equipment Property, plant and equipment includes the
4. Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2007 and 2006 (in thousands):
5. Derivative Contracts In July 2007, the Company entered into fixed-price swap contracts covering 10,000 barrels of Continental Resources, Inc. and Subsidiary Notes to instruments on 6. Long-term Debt The Company had $165.0 million and $140.0 million in long-term debt outstanding at December 31, The Company The Company’s weighted average interest rate was 6.26% at December 31, 2007. At December 31, 7. Income Taxes The
Continental Resources, Inc. Notes to Consolidated Financial Statements—(continued) The following table reconciles the
Significant components of the
Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) As of December 31, 2007, the Company had a net operating loss carryforward of $12.1 million which will expire beginning in 2027. In addition, the Company has an alternative minimum tax credit carryforward of $6.5 million and a statutory depletion carryforward, which will be recognized when realized, of $1.5 million, neither of which expire. 8. Lease Commitments The Company leases office space under operating leases from the principal shareholder (See Note 10). The Company had a capital lease arrangement to lease compressors from a related party. In 2005, the capital lease contract was cancelled and the Company executed an operating lease effective January 28, 2005. The Company recorded a loss of $3.1 million on the termination of the capital lease. The Company pays approximately $400,000 per month under the Lease expense associated with the Company’s operating leases for the
9. Commitments and Contingencies During the three years ended December 31, 2007, the Company maintains a defined contribution retirement plan for its employees Health and The Company is involved in various legal proceedings in the normal course of business, none of which, in the opinion of management, will have a material adverse effect on the financial position or results of operations of the Company. As of December 31, 2007 and 2006, the Company has provided a reserve of $1.0 million and $0.7 million, respectively, for various matters none of which are believed to be individually significant. Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) Due to the nature of the oil and gas business, the Company is exposed to possible environmental risks. The Company 10. Related Party Transactions The Company Certain officers of the Company The Company leases office space under an operating On November 22, 2004, the Company Under a contract for gas sales to 11. Shareholders’ Equity On May 14, 2007, the Company completed its initial public offering of 29,500,000 shares of its common stock at $15.00 per share. The shares are listed on the New York Stock Exchange under the symbol CLR. The Company sold �� 64 Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) On May 14, 2007, the Company affected an 11 for 1 stock split by means of On May 14, 2007 the Company converted from a The Company accounts for stock option grants and On January 10, 2007 and March 6, 2007, the Company declared cash dividends of approximately $18.8 million and $33.3 million to its shareholders for tax purposes and, subject to forfeiture, to holders of unvested restricted stock. During 2007, the Company paid cash dividends of $52.0 million. During 2006, the Company declared cash dividends totaling $87.6 million to existing shareholders and, subject to forfeiture, to holders of unvested restricted stock. During 2006, the Company paid cash dividends of $87.4 million. 12. Stock Compensation Stock Options Effective October 1, 2000, the Company adopted the Continental Resources, Inc. 2000 Stock Option Plan (2000 Plan) and granted options to eligible employees. These options were either incentive stock options, nonqualified stock options or a combination of both. The granted stock options vest ratably over either a three or five-year period commencing on the first anniversary of the grant date and expire ten years from date of grant. On November 10, 2005, the 2000 Plan was terminated. As of December 31,
The total intrinsic value of options exercised during the years ended December 31, Effective January 1, 2006, the Company Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) The following table summarizes information about stock options outstanding at December 31, 2007:
Restricted Stock On October 3, 2005, the Company adopted the Continental Resources, Inc. 2005 Long-Term Incentive Plan (2005 Plan) and reserved a maximum of 5,500,000 shares of common stock that may be issued pursuant to the 2005 Plan. As of December 31, 2007, the Company had 3,934,151 shares of restricted stock available to grant to directors, officers and key employees under the 2005 Plan. All grants were made on or Pursuant to the The Company issued 990,517 shares of restricted stock during 2005. A summary of changes in the non-vested restricted shares for the period of December 31, 2005 to December 31, 2007, is presented below:
Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) The fair value of the restricted shares that vested during 2007 at their vesting date was $4.3 million. As of December 31, 2007, there was $14.6 million of unrecognized compensation expense related to non-vested restricted shares. The expense is expected to be recognized over a weighted average period of 1.8 years. 13. Oil and Gas Property Information The following table sets forth the Company’s results of operations from Prior to the
Costs incurred in Costs incurred, both capitalized and
Exploration costs above include asset retirement costs of Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) Aggregate Aggregate capitalized costs relating to the
Under the successful efforts method of At the end of each quarter, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period. The following table presents the amount of capitalized exploratory drilling costs
14. Supplemental Oil and Gas The following table shows estimates of proved reserves prepared by the Company’s technical staff and independent external reserve Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) reserve Proved reserves are estimated quantities of crude oil There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that Gas imbalance receivables and liabilities for each of the three years ended December 31, Proved
The increases in oil and natural gas reserve volumes attributable to extensions, discoveries and other additions are a result of the Company’s exploration and development activity. Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) The following reserve information
Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that require incremental capital expenditures to recover. Natural gas is converted to barrels of oil equivalent using a conversion factor of six thousand cubic feet per barrel. Standardized The standardized measure of discounted future net cash flows presented in the following Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) Prior to the completion of the Company’s initial public offering on May 14, 2007, the Company was a subchapter S corporation where taxes were paid by its shareholders. In connection with the completion of its initial public offering, the Company converted to a subchapter C corporation, a taxable entity. As such we are showing taxes in our standardized measure as of December 31,
The year-end weighted average oil price utilized in the computation of future cash inflows was Continental Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements—(continued) The changes in the aggregate standardized measure of discounted future net cash flows attributable to the
15. Quarterly Financial Data (Unaudited) Our quarterly financial data for 2007 and 2006 is summarized below.
There have been no changes in accountants or any disagreements with accountants.
Disclosure Controls and Procedures Our Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of Changes in Internal Control over Financial Reporting As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Management’s Report on Internal Control Over Financial Reporting This annual report does not include a report of management’s assessment regarding internal control over financial reporting or a report of our independent registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.
None.
Information as to Item 10 will be set forth in the Proxy Statement for the Annual Meeting of Shareholders to be held May 27, 2008, (Annual Meeting) and is incorporated herein by reference.
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
The information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
The information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Signatures Pursuant to the requirements Section 13 on 15 (d) of
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report Statement on Form S-1 has been signed by the following persons on behalf of Continental Resources, Inc.
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