Item 1. Business
General
We are an independent crude oil and natural gas exploration and production company with operations in the North, South and East regions of the United States. We were originally formed in 1967 to explore, develop and produce crude oil and natural gas properties. Through 1993, our activities and growth remained focused primarily in Oklahoma. In 1993, we expanded our activity into the North region. Approximately 76% of our estimated proved reserves as of December 31, 2009 are located in the North region. We completed an initial public offering of our common stock on May 14, 2007, and our common stock 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 opportunity 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 means to economically develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit, adding 224.2 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1, 2005 through December 31, 2009 compared to 2.8 MMBoe added through proved reserve purchases during that same period.
As of December 31, 2009, our estimated proved reserves were 257.3 MMBoe, with estimated proved developed reserves of 113.6 MMBoe, or 44% of our total estimated proved reserves. Crude oil comprised 67% of our total estimated proved reserves. For the year ended December 31, 2009, we generated revenues of $626.2 million and operating cash flows of $375.9 million. For the year and quarter ended December 31, 2009, daily production averaged 37,324 and 37,747 Boe per day, respectively. This represents growth of 14% and 5% as compared to the year and quarter ended December 31, 2008, when daily production averaged 32,803 Boe and 36,018 Boe, respectively.
The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2009, average daily production for the three months ended December 31, 2009 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 2009 are based primarily on a reserve report prepared by our independent reserve engineers, Ryder Scott Company, L.P (“Ryder Scott”). In preparing its report, Ryder Scott evaluated properties representing approximately 90% of our PV-10. Our technical staff evaluated properties representing the remaining 10% of our PV-10. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2009 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $61.18 per Bbl for oil and oil equivalents and $3.87 per Mcf for gas ($52.76 per Bbl for oil and $3.67 per Mcf for gas net of location differentials).
(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, 2009 is $1.8 billion, a $0.4 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 crude oil and natural 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 2009 production into the proved reserve quantity at December 31, 2009.
The following table provides additional information regarding our key development areas as of December 31, 2009 and budgeted for 2010:
(1) Capital expenditures budgeted for 2010 include amounts for drilling, capital workovers and facilities and exclude amounts for land of $92 million, seismic of $9 million, and $11 million for vehicles, computers and other equipment. While the above capital expenditures budget reflects our current intentions, we expect our cash flows from operations and the availability under our revolving credit facility will be sufficient to meet our capital expenditure needs. A decline in crude oil and natural gas prices could cause us to curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures.
Our Business Strategy
Our goal is to increase shareholder value by finding and developing 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 Crude oil. During the late 1980’s we began to believe that the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles towards crude oil. As of December 31, 2009, crude oil comprises 67% of our total proved reserves and 74% of our 2009 annual production. Although we do pursue natural gas opportunities, we continue to believe that crude oil valuations will be superior to natural gas valuations on a relative Btu basis.
Growth Through Low-Cost Drilling. Substantially all of our annual capital expenditures are invested in drilling projects and acreage and seismic acquisitions. From January 1, 2005 through December 31, 2009, proved crude oil and natural gas reserve additions through extensions and discoveries were 224.2 MMBoe compared to 2.8 MMBoe of proved reserve purchases.
Internally Generate Prospects. Although we evaluate strategic acquisitions periodically, our technical staff has internally generated substantially all of the opportunities for the investment of our capital. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than later entrants into a developing play.
Focus on Unconventional Crude Oil and Natural Gas Resource Plays. Our experience with horizontal drilling, advanced fracture stimulation and enhanced recovery technologies allows us to commercially develop unconventional crude oil and natural gas resource reservoirs, such as the Red River B dolomite, Bakken shale and Oklahoma Woodford shale formations. Production rates in the Red River units also have been increased through the use of enhanced recovery technology. Our production from the Red River units, the Bakken field, and the Oklahoma Woodford shale comprised approximately 11,259 MBoe, or 83% of our total crude oil and natural gas production during the year ended December 31, 2009.
Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 635,100 net undeveloped acres held in the Montana and North Dakota Bakken shale and Oklahoma Woodford shale fields, we held 223,000 net undeveloped acres in other crude oil and natural gas shale plays as of December 31, 2009. Our technical staff is focused on identifying and testing new unconventional crude 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.
Our Business Strengths
We have a number of strengths that we believe will help us successfully execute our strategies:
Large Acreage Inventory. We own 1,094,300 net undeveloped and 466,300 net developed acres as of December 31, 2009. Approximately 78% of the undeveloped acres are located within unconventional shale resource plays including the Bakken shale in North Dakota and Montana, the Woodford shale in Oklahoma, the Haynesville shale in Louisiana, the Lewis shale in Wyoming, the Barnett and Woodford shales in the Marfa Basin, the New Albany shale in Indiana and Kentucky and the Lower Huron, Rhinestreet and Marcellus shales in West Virginia, Pennsylvania, New York and Ohio. The balance of the undeveloped acreage is located primarily in conventional plays including 3D defined locations for the Trenton-Black River of Michigan, Red River of Montana and North Dakota, Lodgepole of North Dakota, Morrow-Springer of western Oklahoma and Frio in South Texas.
Horizontal Drilling and Enhanced Recovery Experience. In 1992, we drilled our initial horizontal well, and we have drilled over 700 horizontal wells since that time. We also have substantial experience with enhanced recovery methods and currently serve as the operator of 48 waterflood units. Additionally, we operate 8 high pressure air injection (“HPAI”) floods.
Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2009, we operated properties comprising 93% of our PV-10. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used.
Experienced Management Team. Our senior management team has extensive expertise in the crude oil and natural gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the crude oil and natural gas industry in 1967. Our 8 senior officers have an average of 29 years of crude oil and natural gas industry experience. Additionally, our technical staff, which includes 34 petroleum engineers, 20 geoscientists and 11 landmen, has an average of 17 years experience in the industry.
Strong Financial Position. As of February 19, 2010, we had outstanding borrowings under our revolving credit facility of approximately $198.0 million and available borrowing capacity of $551.2 million under our selected commitment level. We have elected to set the commitment level at $750.0 million, which is equal to the revolving credit facility note amount of $750.0 million and the established borrowing base is $1.0 billion. We believe that our planned exploration and development activities will be funded substantially from our operating cash flows and borrowings under our revolving credit facility. Our 2010 capital expenditures budget has been established based on our current expectation of available cash flows from operations and availability under our
revolving credit facility. Should expected available cash flows from operations materially vary from expectations, we believe our credit facility has sufficient availability to fund any deficit or that we can further reduce our capital expenditures to be in line with cash flows from operations. We anticipate that we will negotiate a new revolving credit facility during the second quarter of 2010 as our current revolving credit facility matures in April 2011.
Crude Oil and Natural Gas Operations
In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and natural gas companies that became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules expand the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than the year-end price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate reserves used in computing depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.
The initial application of new rules related to modernizing reserve calculation and disclosure requirements resulted in a upward adjustment to our total proved reserves as of December 31, 2009 primarily as a result of the amendments to the definition of oil and gas reserves and higher oil prices. See Notes to Consolidated Financial Statements-Note 15. Supplemental Crude Oil and Natural Gas Information (Unaudited).
Proved Reserves
The following tables set forth our estimated proved crude oil and natural gas reserves, percent of total proved reserves that are proved developed and the PV-10 as of December 31, 2009 by reserve category and region. The total standardized measure of discounted cash flows as of December 31, 2009 is also presented. Ryder Scott, our independent petroleum engineers, evaluated properties representing approximately 90% of our PV-10, and our technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K. Our estimated proved reserves and related future net revenues and PV-10 at December 31, 2009 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $61.18 per Bbl for crude oil and oil equivalents and $3.87 per Mcf for natural gas ($52.76 per Bbl for crude oil and $3.67 per Mcf for natural gas net of location differentials).
(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, 2009 is $1.8 billion, a $0.4 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 crude oil and natural 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.
We have historically added reserves through our exploration program and development activities. See Items 1. Business and Item 2. Properties. Changes in proved reserves were as follows:
Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. December 31, 2008 revisions were primarily due to lower commodity prices at the end of 2008.
Reserves at December 31, 2009 were computed using the 12-month unweighted average of the first-day-of-the-month prices as required by the new SEC rules. However, had we been able to use December 31, 2009 prices as in previous years, our revisions for 2009 would have increased by an additional 4,070 MBoe.
Extensions, discoveries and other additions. These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions at December 31, 2009 include increases in
proved undeveloped locations as a result of the change in the SEC’s rules to allow producers in continuous accumulation plays to report additional undrilled locations beyond one offset on each side of a horizontal producing well.
We expect that a significant portion of future reserve additions will come from our major development projects including North Dakota Bakken, Arkoma Woodford and Anadarko Woodford. We may also purchase proved properties in strategic acquisitions.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. Ryder Scott, our independent petroleum consultant estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 90% of our proved reserve information as of December 31, 2009 included in this Annual Report on Form 10-K. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. In the fourth quarter, our technical team meets regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the Ryder Scott reserve report is reviewed by our audit committee with representatives of Ryder Scott and our internal technical staff before dissemination of the information. Additionally, our senior management reviews and approves the Ryder Scott reserve report and any internally estimated significant changes to our proved reserves on a quarterly basis.
Our Senior Vice President-Resource Development is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Senior Vice President - Resource Development has a Bachelor of Science degree in Mechanical Engineering and 35 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Senior Vice President-Resource Development reports directly to our President and Chief Operating Officer. These reserves estimates are reviewed and approved by senior engineering staff with final approval by the Chief Operating Officer and certain members of senior management.
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, Ryder Scott employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data and well test data.
Proved Undeveloped Reserves. Our proved undeveloped reserves at December 31, 2009 were 143,726 MBoe, consisting of 88,010 MBbls of crude oil and 334,298 MMcf of natural gas. In 2009, we developed approximately 9% of our total proved undeveloped reserves booked as of December 31, 2008 through the drilling of 64 gross (16.1 net) development wells at an aggregate capital cost of approximately $91.9 million. Estimated future development costs relating to the development of PUDs are projected to be approximately $360 million in 2010, $570 million in 2011, and $540 million in 2012.
Developed and Undeveloped Acreage
The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2009:
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2009 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:
Drilling Activity
During the three years ended December 31, 2009, we drilled exploratory and development wells as set forth in the table below:
As of December 31, 2009, there were 70 gross (23.1 net) wells in the process of drilling, completing or waiting on completion.
As of February 19, 2010, we operated 14 rigs on our properties. Our rig activity during 2010 will be dependent on crude oil and natural gas prices and, accordingly, our rig count may increase or decrease from current levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. See Item 1A.
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 Crude Oil and Natural Gas Industry and Our Business
A substantial or extended decline in crude 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 crude oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude 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 crude 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:
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worldwide and regional economic conditions impacting the global supply and demand for crude oil and natural gas;
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the actions of the Organization of Petroleum Exporting Countries, or OPEC;
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the price and quantity of imports of foreign crude oil and natural gas;
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political conditions in or affecting other crude oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
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the level of global crude oil and natural gas exploration and production;
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the level of global crude oil and natural gas inventories;
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localized supply and demand fundamentals and transportation availability;
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weather conditions;
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technological advances affecting energy consumption; and
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the price and availability of alternative fuels.
The slowdown in economic activity caused by the worldwide economic recession has reduced worldwide demand for energy and resulted in lower crude oil and natural gas prices. Crude oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $45 per Bbl in February 2009 before rebounding to over $70 per Bbl in February 2010. Natural gas prices declined from over $13 per Mcf in mid-2008 to approximately $4 per Mcf in February 2009 before returning to over $5 per Mcf in February 2010.
Lower crude oil and natural gas prices will reduce our cash flows and borrowing ability. See Item 1A. Risk Factors-Our exploration, 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 crude oil and natural gas reserves. Lower crude oil and natural gas prices may also reduce the amount of crude oil and natural gas that we can produce economically. Substantial decreases in crude oil and natural gas prices would render uneconomic a significant portion of our exploration, development and 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 crude 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 geographically concentrated in the North region, we are vulnerable to fluctuations in pricing in that area. In particular, 77% of our production during the fourth quarter of 2009 was from the North region. 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 crude oil produced from the wells in these areas. Such factors can cause significant fluctuation in our realized crude oil and natural gas prices. For example, the difference between the average NYMEX crude oil price and our average realized crude oil price for the year ended December 31, 2009 was $8.29 per Bbl, whereas the difference between the NYMEX crude oil price and our realized crude oil price for the year ended December 31, 2008 was $9.50 per Bbl.
Our estimates of proved reserves have been prepared under new SEC rules that went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.
This report presents estimates of our proved reserves as of December 31, 2009, which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on twelve-month unweighted first-day-of the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of the-year pricing. The pricing that was used for estimates of our reserves as of December 31, 2009 was based on an unweighted average twelve month NYMEX posted price of $61.18 per Bbl for oil ($52.76 per Bbl net of location differentials) and a NYMEX price of $3.87 per MMBtu for natural gas ($3.67 per Mcf net of location differentials), as compared to $44.60 per Bbl for oil ($39.69 per Bbl net of location differentials) and $5.62 per MMBtu for natural gas ($4.90 per Mcf net of location differentials) as of December 31, 2008. As a result of these changes, direct comparisons to our previously reported reserves amounts may be more difficult.
Another impact of the new SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program, particularly as we develop our significant acreage in the North Dakota Bakken. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those reserves within the required five-year timeframe.
The SEC has not reviewed our or any reporting company’s reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of our proved reserves at December 31, 2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.
Our exploration, 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 crude oil and natural gas reserves.
The crude 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 crude oil and natural gas reserves. Our cash flows used in investing activities was $507.0 million related to capital and exploration expenditures in 2009. Our budgeted capital expenditures for 2010 are expected to be approximately $850.0 million with $738.0 million allocated for drilling and completion operations. To date, these capital expenditures have been financed with cash generated by operations and through borrowings under our revolving credit facility. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of
drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We expect our capital expenditures during 2010 to be significantly higher than our 2009 capital expenditures due to the acceleration of our drilling operations in 2010. We expect our cash flows from operations and the availability under our revolving credit facility will be sufficient to meet our capital expenditure needs. Continued improvement in commodity prices may result in an increase in our actual capital expenditures. Conversely, a significant decline in product prices could result in a decrease in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows 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 or the sale of assets. The issuance of additional debt may require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows 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 flows from operations and access to capital are subject to a number of variables, including:
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our proved reserves;
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the level of crude oil and natural gas we are able to produce from existing wells;
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the prices at which our crude oil and natural gas are sold;
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our ability to acquire, locate and produce new reserves; and
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the ability of our banks to lend.
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower crude 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 crude oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.
Drilling for and producing crude 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 crude 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 crude 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 Item 1A. Risk Factors-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:
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delays imposed by or resulting from compliance with regulatory requirements;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel;
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equipment failures or accidents;
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adverse weather conditions, such as blizzards and ice storms;
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reductions in crude oil and natural gas prices;
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limited availability of financing at acceptable rates;
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title problems; and
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limitations in the market for crude 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 crude oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. See Item 1. Business-Crude Oil and Natural Gas Operations, Proved Reserves for information about our estimated crude oil and natural gas reserves and the PV-10 and standardized measure of discounted future net cash flows as of December 31, 2009.
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, based on historical data but projected into the future, about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude 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 crude oil and natural gas prices and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
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. For the years prior to 2009, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate. In accordance with new SEC requirements, we currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
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actual prices we receive for crude oil and natural gas;
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actual cost of development and production expenditures;
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the amount and timing of actual production; and
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changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from
proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Actual future prices and costs may differ materially from those used in the present value estimate. If oil prices decline by $10.00 per Bbl, then our PV-10 as of December 31, 2009 would decrease approximately $622 million. If natural gas prices decline by $1.00 per Mcf, then our PV-10 as of December 31, 2009 would decrease approximately $181 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 crude 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 crude 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 crude 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.
If crude oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our crude oil and natural gas properties.
Accounting rules require that we periodically review the carrying value of our crude 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 crude 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 crude 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 crude oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows 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 crude oil and natural gas operations. Additionally 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 crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
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fires, explosions and ruptures of pipelines in connection with our high-pressure air injection operations;
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personal injuries and death; and
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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:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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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 crude oil or natural gas in commercially viable quantities.
Prospects that we decide to drill that do not yield crude oil or natural gas in commercially viable quantities will adversely affect our results 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 crude 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 crude oil or natural gas will be present or, if present, whether crude 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 crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. The North Dakota Bakken shale and Oklahoma 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 crude 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, 2009, we had leases representing 185,400 net acres expiring in 2010, 351,100 net acres expiring in 2011, and 238,300 net acres expiring in 2012. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Our business depends on crude oil and natural gas transportation facilities, most of which are owned by third parties.
The marketability of our crude oil and natural gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. We generally do not purchase firm transportation on third party facilities and therefore, our production transportation can be interrupted by those having firm arrangements. Federal and state regulation of crude oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport crude oil and natural gas.
The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flows, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.
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 crude 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, crude 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 Crude 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.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject Continental to civil penalty liability.
Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude 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 crude oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude 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 crude 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.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Crude oil and natural gas operations in the North region 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, and Wyoming, drilling and other crude 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 resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Our revolving credit facility and 8 1/4% Senior Notes due 2019 contain certain covenants, or restrictions 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 revolving credit facility includes certain covenants that, among other things, restrict:
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our investments, loans and advances and the paying of dividends and other restricted payments;
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our incurrence of additional indebtedness;
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the granting of liens, other than liens created pursuant to the revolving credit facility and certain permitted liens;
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mergers, consolidations and sales of all or substantial part of our business or properties;
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the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;
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the sale of assets.
Our revolving credit 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 other provisions of our revolving credit 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 revolving 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 revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and
place us at a competitive disadvantage. For example, as of February 19, 2010, outstanding borrowings under our revolving credit facility were $198.0 million and the impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $2.0 million and a $1.2 million decrease in our net income. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Unrest in the financial markets may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.
The current turmoil in the global financial systems have had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions remain unsettled. Historically, we have used our cash flows from operations and borrowings under our revolving credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. A continuation of the economic uncertainty could further reduce the demand for crude oil and natural gas and put downward pressure on the prices for crude oil and natural gas, which have declined significantly since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows.
We have an existing revolving credit facility with lender commitments totaling $750.0 million. In the future, we may not be able to access adequate funding under our bank credit facilities as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, which is solely at the discretion of our lenders, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.
As a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to existing debt or at all, and reduced and, in some cases, ceased to provide any new funding.
Financial market turmoil has impacted the level of activity in the crude oil and natural gas property sales market. The lack of available credit and access to capital has limited and will likely continue to limit the parties interested in any proposed asset transactions and will likely reduce the values we could realize in those transactions.
Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
Our principal exposures to credit risk are through joint interest receivables ($59.8 million at December 31, 2009) and the sale of our crude oil and natural gas production ($125.8 million in receivables at December 31, 2009), which we market to energy marketing companies, refineries and affiliates. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells
primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with several significant customers. The largest purchaser of our crude oil and natural gas, during the twelve months ended December 31, 2009, accounted for 56% of our total revenues. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our 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 prices of crude oil and natural gas, we on occasion, enter into derivative instruments for a portion of our crude oil and/or natural gas production, including collars and price-fix swaps. In the second half of 2009 and January 2010, we entered into several commodity derivative transactions. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Oil and Gas Hedging and Notes to Consolidated Financial Statements - Note 5. Derivative Instruments for a summary of our crude oil and natural gas commodity derivative positions. We did not designate any of our derivative instruments as hedges for accounting purposes and we record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are 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:
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production is less than the volume covered by the derivative instruments;
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the counter-party to the derivative instrument defaults on its contract obligations; or
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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 prices for crude 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:
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recoverable reserves;
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future crude oil and natural gas prices and their appropriate differentials;
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operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently 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.
Our Chairman and Chief Executive Officer owns 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 19, 2010, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owns 123,651,708 shares of our outstanding common stock representing approximately 72.8% of our outstanding common shares. As a result, Mr. Hamm will continue to be our controlling shareholder and will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As controlling 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 Mr. Hamm provide oilfield, gathering and processing, marketing and other services to us. We expect these transactions will continue in the future and may result in conflicts of interest between Mr. Hamm’s affiliated companies and us. We can provide no assurance that any such conflicts will be resolved in our favor.
Proposed legislation under consideration by Congress could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
Our operations are subject to extensive federal, state and local laws and regulations. Changes to existing laws or regulations or new laws or regulations may unfavorably impact us and could result in increased taxes and operating costs and have a material adverse effect on our financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its current proposed form, would subject companies involved in crude oil and natural gas exploration and production activities to substantial additional taxes and regulation. If such legislation is adopted, it could result in, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to crude oil and natural gas exploration and production companies, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential laws and regulations could increase our taxes and operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil, natural gas and NGLs that we produce.
Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.
Even if such legislation is not adopted at the national level, more than one-third of the states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce emissions of greenhouse gases, as have a number of local governments. Although most of the regional and state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as coal-fired electric power plants, smaller sources of emissions could become subject to greenhouse gas emission limitations, allowance purchase requirements or other restrictions or costs. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.
Congress currently is considering broad financial regulatory reform legislation that among other things would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace and could affect the use of derivatives in hedging transactions. The financial regulatory reform bill adopted by the House of Representatives on December 11, 2009, would subject swap dealers and “major swap participants” to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants. For these purposes, a major swap participant generally would be someone other than a dealer who maintains a “substantial” net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. The House-passed bill also would provide the Commodity Futures Trading Commission (CFTC) with express authority to impose position limits for OTC derivatives related to energy commodities. Separately, in late January, 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certain bona fide hedging of commercial risks. Although it is not possible at this time to predict whether or when Congress will act on derivatives legislation or the CFTC will finalize its proposed regulations, any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.
Item 1B.
Item 1B. Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2009.
Item 2.
Item 2. Properties
The information required by Item 2 is contained in Item 1. Business-Crude Oil and Natural Gas Operations.
Item 3.
Item 3. Legal Proceedings
We are not a party to any material pending legal 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 the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
Item 4.
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 2009.
Part II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Shareholder Matters
Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” The following table sets forth quarterly high and low sales prices and cash dividends declared for each quarter of the previous two years.
Our 8 1/4% Senior Notes Due 2019 may restrict payment of dividends and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of February 16, 2010, the number of record holders of our common stock was 67. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 22,000. On February 19, 2010, the last reported sales price of our Common Stock, as reported on the NYSE, was $40.96 per share. The following table summarizes our purchases of our common stock during the fourth quarter of 2009:
(1) In connection with stock option exercises or restricted stock grants under the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”), we adopted a policy that enables employees to surrender shares to cover their tax liability. See Notes to Consolidated Financial Statements-Note 13. Stock Compensation. The 2000 Plan was adopted in October 2000 and was terminated in November 2005. The 2005 Plan was adopted in October 2005 and expires in October 2015. All shares purchased above represent shares surrendered to cover tax liabilities. We paid the associated taxes to the Internal Revenue Service.
(2) The price paid per share was the closing price of our common stock on the date of exercise or the date the restrictions lapsed on such shares, as applicable.
(3) We are unable to determine at this time the total amount of securities or approximate dollar value of those securities that could potentially be surrendered to us pursuant to our policy that enables employees to surrender shares to cover their tax liability associated with the exercise of options or vesting of restrictions on shares under the 2000 Plan and 2005 Plan.
Performance Graph
The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended. As required by these rules, the performance graph was prepared based upon the following assumptions:
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$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, our initial public offering date, at the closing price on such date;
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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
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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.
Item 6. Selected Financial Data
This section presents our selected historical and pro forma consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements.
The following historical consolidated financial data, as it relates to each of the fiscal years ended December 31, 2005 through 2009, has been derived from our audited historical consolidated financial statements for such periods. You should read the following selected historical consolidated financial data in connection with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and our historical consolidated financial statements and related notes included elsewhere in this report. The selected historical consolidated results are not necessarily indicative of results to be expected in future periods.
(1) Derivative losses in 2007, 2008 and 2009 were not accounted for as hedges and therefore are shown separately.
(2) Prior to our initial 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, 2006 and prior. See Notes to Consolidated Financial Statements-Note 1. Organization and Summary of Significant Accounting Policies-Income taxes. In connection with our initial public offering, we converted to a subchapter C corporation. Pro forma adjustments are reflected to provide for income taxes 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 pro forma periods presented.
(3) At various times, we have stored crude oil due to pipeline line fill requirements or because of low prices or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes as noted. For the year 2009, crude oil sales volumes were 82 MBbls less than crude oil production volumes. For the year 2008, crude oil sales volumes were 97 MBbls more than crude oil production volumes. For the years 2007, and 2006, crude oil sales volumes were 221 MBbls and 21 MBbls less than crude oil production volumes, respectively.
(4) Average costs per Boe have been computed using sales volumes.
(5) EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains or losses and non-cash compensation expense. EBITDAX is not a measure of net income or cash flows as determined by generally accepted accounting principles (“GAAP”). EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows as determined in accordance with GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our revolving credit facility requires that we maintain a Total Funded Debt to EBITDAX ratio of no greater than 3.75 to 1 on a rolling four-quarter basis. Our revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. At December 31, 2009, our Total Funded Debt to EBITDAX ratio was approximately 1.2 to 1. The following table represents a reconciliation of our net income to EBITDAX for the periods presented:
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following discussion should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data, included elsewhere in this report. For a discussion of oil and gas reserve information, please see Item 1. Business.
Overview
We are engaged in crude oil and natural gas exploration, exploitation and production activities in the North, South and East regions of the United States. Crude oil comprised 67% of our 257.3 MMBoe of estimated proved reserves as of December 31, 2009 and 74% of our 13,623 MBoe of production for the year 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 72% of our 2,317 gross wells as of December 31, 2009. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used.
Our business strategy has focused on reserve and production growth through exploration and development. For the three-year period ended December 31, 2009, we added 181,777 MBoe of proved reserves through
extensions and discoveries, compared to 2,301 MBoe added through purchases. During this period, our production increased from 10,621 MBoe in 2007 to 13,623 MBoe in 2009. An aspect of our business strategy has been to acquire large undeveloped acreage positions in new or developing resource plays. As of December 31, 2009, we held approximately 2,165,800 gross (1,094,300 net) undeveloped acres, including 485,300 net undeveloped acres in the Bakken field in Montana and North Dakota and 149,000 net undeveloped acres in the Oklahoma Woodford 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, 2009, our crude oil and natural gas production increased to 13,623 MBoe (37,324 Boe per day), up 14% from the year ended December 31, 2008. The increase in 2009 production primarily resulted from an increase in production from our Red River units, North Dakota Bakken field and Oklahoma Woodford. Crude oil and natural gas revenues for 2009 decreased by 35% to $610.7 million due to decreases in commodity prices. Our realized price per Boe decreased $32.56 to $45.10 for 2009 compared to 2008. We experienced decreases in production expense and production tax of a combined total of $21.4 million, or 13%. Our decrease in combined per unit cost was 23%, or $2.98 per Boe, due to the increase in sales volumes of 1,438 MBoe, or 12%. At various times we have stored crude oil due to pipeline line fill requirements or because of low prices or we have sold oil from inventory. These actions result in differences between our produced and sold crude oil volumes as noted. Crude oil sales volumes were 82 MBbls less than crude oil production for the year ended December 31, 2009 and crude oil sales volumes were 97 MBbls more for the same period in 2008. Our cash flows from operating activities for the year ended December 31, 2009, was $375.9 million, a decrease of $344.0 million from $719.9 million provided by our operating activities during the comparable 2008 period. The decrease in operating cash flows was mainly due to decreases in sales prices by 42% partially offset by an increase in sales volumes. During the year ended December 31, 2009, we invested $434.0 million (inclusive of non-cash accruals of $74.7 million) in our capital program concentrating mainly in the Red River units, the Bakken field and the Oklahoma Woodford play.
Our 2010 capital expenditures budget of $850 million will primarily focus on increased development in the North Dakota Bakken, the Arkoma and Anadarko Woodford shale natural gas plays in Oklahoma and the Red River units, with total operated drilling rigs increasing to as many as 23 by mid-year 2010. We expect our cash flows from operations and the availability under our revolving credit facility will be sufficient to meet our capital expenditure needs. Continued strength in commodity prices may result in an increase in our actual capital expenditures during 2010; conversely, a significant decline in product prices could result in a decrease in our capital expenditures. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation-Liquidity and Capital Resources.
In September 2009, we issued $300 million of 8 1/4 % Senior Subordinated Notes due 2019 (Notes) for net proceeds of approximately $289.7 million, after deducting the underwriters’ discounts of approximately $6.8 million and offering expenses of approximately $1.0 million. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility.
How We Evaluate Our Operations
We use a variety of financial and operational measures to assess our performance. Among these measures are (1) volumes of crude oil and natural gas produced, (2) crude oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) EBITDAX. The following table contains financial and operational highlights for each of the three years ended December 31, 2009.
(1) At various times, we have stored crude oil due to pipeline line fill requirements or because of low prices or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes as noted. Crude oil sales volumes were 82 MBbls less than crude oil production for the year ended December 31, 2009, crude oil sales volumes were 97 MBbls more than crude oil production for the year ended December 31, 2008 and 221 MBbls less than crude oil production for the year ended December 31, 2007. Average prices and per unit expenses have been calculated using sales volumes and excluding any effect of derivative transactions.
(2) General and administrative expense ($/Boe) includes non-cash equity compensation expense of $0.84 per Boe, $0.75 per Boe, and $1.23 per Boe for the years ended December 31, 2009, 2008 and 2007, respectively.
(3) EBITDAX represents earnings before interest expense, income taxes, 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 flows as determined by GAAP. A reconciliation of net income to EBITDAX is provided in Item 6. Selected Financial Data.
(4) Prior to our initial public offering, we were a subchapter S corporation and income taxes were payable by our shareholders. See Notes to Consolidated Financial Statements-Note 1. Organization and Summary of Significant Accounting Policies-Income taxes. In connection with our initial 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.
(5) Pro forma adjustments are reflected to provide for income taxes in accordance with authoritative accounting guidance 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 pro forma periods presented.
Results of Operation
The following table presents selected financial and operating information for each of the three years ended December 31, 2009:
(1) 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, 2006. See Notes 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.
(2) At various times, we have stored crude oil due to pipeline line fill requirements or because of low prices or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes as noted. Crude oil sales volumes were 82 MBbls less than crude oil production for the year ended December 31, 2009, crude oil sales volumes were 97 MBbls more than crude oil production for the year ended December 31, 2008 and 221 MBbls less than crude oil production for the year ended December 31, 2007. Average prices have been calculated using sales volumes and excluding any effect of derivative transactions.
Year ended December 31, 2009 compared to the year ended December 31, 2008
Production
The following tables reflect our production by product and region for the periods presented.
Crude oil production volumes increased 10% during the year ended December 31, 2009 compared to the year ended December 31, 2008. Production increases in the Bakken field area contributed incremental volumes in excess of production for the same period in 2008 of 1,055 MBoe. Favorable results from drilling have been the primary contributors to production growth in this area. Natural gas volumes increased 4,455 MMcf, or 26%, during the year ended December 31, 2009 compared to the same period in 2008. The majority of the increase, 3.6 Bcf of natural gas, was from the South region due to the results of our exploration efforts in the Oklahoma Woodford play. The North region natural gas production was up 0.8 Bcf for the year ended December 31, 2009 compared to the same period in 2008 mainly due to additional natural gas being connected and sold in the North Dakota Bakken area.
Revenues
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the year ended December 31, 2009 were $610.7 million, a 35% decrease from sales of $939.9 million for 2008. Our sales volumes increased 1,438 MBoe or 12% over the same period in 2008 due to the continuing success of our enhanced oil recovery and drilling programs and additional natural gas being connected and sold in the North region. Our realized price per Boe decreased $32.56 to $45.10 for the year ended December 31, 2009 from $77.66 for the year ended December 31, 2008. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the year ended December 31, 2009 was $8.29 compared to $9.50 for 2008. Factors contributing to the changing differentials included Canadian crude oil imports and increases in production in the North region, coupled with downstream transportation capacity constraints, refinery downtime in the North region, and seasonal demand fluctuations for gasoline.
Derivatives. We are required to recognize 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. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value on derivative instruments in the income statements under the caption “Loss on mark-to-market derivative instruments.”
During the year ended December 31, 2009, we realized gains on gas derivatives of $0.6 million. We reported an unrealized non-cash mark-to-market gain on gas derivatives of $1.6 million and an unrealized non-cash mark-to-market loss on oil derivatives of $3.7 million.
Crude Oil and Natural Gas Service Operations. Our crude oil and natural gas service operations consist primarily of the treatment and sale of lower quality crude oil, or reclaimed crude oil, and the sales of high-pressure air. Prices for reclaimed crude oil sold from our central treating unit were lower for the year ended December 31, 2009 than the comparable 2008 period. The price decreased $45.30 per barrel from 2008 to 2009 which decreased reclaimed crude oil income by $10.2 million contributing to an overall decrease in crude oil and natural gas service operations revenue of $11.5 million for the year ended December 31, 2009. Associated crude oil and natural gas service operations expenses decreased $7.5 million to $10.7 million during the year ended December 31, 2009 from $18.2 million during the year ended December 31, 2008 due mainly to a decrease in the costs of purchasing and treating crude oil for resale compared to the same period in 2008. We sold high-pressure air from our Red River units to a third party and recorded revenues of $2.2 million for the year ended December 31, 2009 compared to revenues of $3.0 million for the year ended December 31, 2008.
Operating Costs and Expenses
Production Expense, Production Tax and Other Expenses. Production expense decreased $8.4 million, or 8%, during the year ended December 31, 2009 to $93.2 million from $101.6 million during the year ended December 31, 2008. The decrease in production expense was mainly attributable to reductions in energy costs, repairs and workovers. During the year ended December 31, 2009, we participated in the completion of 217 gross (67.8 net) wells. Production expense per Boe decreased to $6.89 for the year ended December 31, 2009 from $8.40 per Boe for the year ended December 31, 2008.
Production tax and other expenses decreased $13.0 million, or 22%, during the year ended December 31, 2009 compared to the year ended December 31, 2008 as a result of lower revenues resulting from decreased sales prices partially offset by the expiration of various tax incentives and increases in other charges. Production tax and other expenses on the consolidated income statement includes other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Arkoma Woodford area of $6.8 million and $3.4 million for the years ended December 31, 2009 and 2008, respectively. Production tax, excluding other expenses, as a percentage of crude oil and natural gas sales was 6.5% for the year ended December 31, 2009 compared to 6.0% for the year ended December 31, 2008. 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 crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana, North Dakota and Oklahoma new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate increases to the statutory rates. Our overall rate is expected to increase as production tax incentives we currently receive for horizontal wells reach the end of their incentive period.
On a unit of sales basis, production expense and production tax and other expenses were as follows:
Exploration Expense. Exploration expense consists primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expense decreased $27.6 million in the year ended December 31, 2009 to $12.6 million due primarily to a decrease in seismic expense of $14.9 million to $2.0 million and a decrease in dry hole expense of $13.5 million to $6.5 million. The majority of the dry hole costs, 67%, were in the East region for the year ended December 31, 2009 and 67% of the dry hole costs for the 2008 period were in the North region.
Depreciation, Depletion, Amortization and Accretion (DD&A). Total DD&A increased $58.7 million in the year ended December 31, 2009 compared to the same period in 2008, primarily due to an increase in production volumes and additional properties with higher cost reserves being added through our drilling program. Additionally, DD&A increased as a result of the decrease in commodity prices used to calculate reserve volumes at December 31, 2008 that affected DD&A for the first six months of 2009. Lower prices have the effect of decreasing the economic life of crude oil and natural gas properties, which lowers future reserve volumes and increases DD&A. The following table shows the components of our DD&A rate per Boe.
Property Impairments. Property impairments, non-producing and developed, increased in the year ended December 31, 2009 by $54.9 million to $83.7 million compared to $28.8 million during the year ended December 31, 2008. Impairment of non-producing properties increased $30.6 million during the year ended December 31, 2009 to $47.1 million compared to $16.5 million for 2008 reflecting higher amortization of lease costs in our existing fields resulting from further defining likely drilling locations, capital constraints, and amortization of new fields. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. 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 crude oil and natural gas properties were approximately $36.6 million for the year ended December 31, 2009 compared to approximately $12.3 million for the year ended December 31, 2008, an increase of $24.3 million, or 198%. We evaluate our developed crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair market value based on discounted cash flows. Impairments in 2009 reflect uneconomic drilling results in certain small fields primarily in our South region and our Rockies Other area in the North region, which resulted in impairments of $36.6 million in 2009. Impairments in 2008 were primarily related to uneconomic wells in our South region and our Rockies Other area in the North region.
General and Administrative Expense. General and administrative expense increased $5.4 million to $41.1 million during the year ended December 31, 2009 from $35.7 million during the comparable period of 2008. General and administrative expense includes non-cash charges for stock-based compensation of $11.4 million and $9.1 million for the years ended December 31, 2009 and 2008, respectively. General and administrative expense excluding equity compensation increased $3.7 million for the twelve months ended December 31, 2009 compared to the twelve months ended December 31, 2008. The increase was primarily related to an increase in personnel costs of approximately $2.0 million due to additional employees and higher wages and increased benefits along with an increase in donations of approximately $1.0 million and an increase in professional fees including litigation expense of approximately $1.5 million. On a volumetric basis, general and administrative expense was $3.03 per Boe for the year ended December 31, 2009 compared to $2.95 per Boe for the year ended December 31, 2008.
Interest Expense. Interest expense increased 91%, or $11.0 million, for the year ended December 31, 2009 compared to the year ended December 31, 2008, due to increased debt partially offset by lower interest rates in 2009. Our average revolving credit facility balance increased to $426.3 million for the year ended December 31, 2009 compared to $248.7 million for the year ended December 31, 2008, but the weighted average interest rate on our revolving credit facility was 1.64% lower at 2.90% for the year ended December 31, 2009 compared to
4.54% for the same period in 2008. At December 31, 2009, our outstanding balance under our revolving credit facility was $266.0 million with a weighted average interest rate of 2.66%. On September 23, 2009, we issued $300 million of 8 1/4% Senior Notes due 2019 (“Notes”). The Notes, which carry a coupon rate of 8.25%, were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. We recorded $7.0 million in interest on the Notes for the year ended December 31, 2009. Including the effect of the Notes, our weighted average interest rate for the year ended December 31, 2009 was 3.78% while at December 31, 2009 our weighted average rate was 5.92%.
Income Taxes. Income taxes for the year ended December 31, 2009 were $38.7 million compared to $197.6 million for the year ended December 31, 2008. We provide taxes at a combined federal and state tax rate of approximately 35% for 2009 compared to approximately 38% for 2008 after taking into account permanent taxable differences. The decrease in the effective tax rate is related to state losses and utilization of state net operating loss carry forwards. See Notes to Consolidated Financial Statements-Note 8. Income Taxes for more information.
Year ended December 31, 2008 compared to the year ended December 31, 2007
For the year ended December 31, 2009, we changed our reporting regions from Rockies, Mid-Continent and Gulf Coast to North, South and East. The primary effect of this change was to combine the Mid-Continent and Gulf Coast regions into the South region and to split the East region from the new South region. Where appropriate, the following discussion has been revised from our previous filings to reflect this change.
Production
The following tables reflect our production by product and region for the periods presented.
Crude oil production volumes increased 5% during the year ended December 31, 2008 in comparison to the year ended December 31, 2007. Production increases in the North area contributed incremental volumes in excess of 2007 levels of 313 MBbls, including 219 MBbls which came from the Bakken field. The South area contributed incremental volumes of 113 MBbls in excess of 2007 levels. Favorable results from drilling and acquisitions have been the primary contributors to production growth in these areas. Natural gas volumes increased 5,617 MMcf, or 49%, during the year ended December 31, 2008 compared to 2007. The majority of the increase, 3.8 Bcf, was from the South region due to the results of our exploration efforts in the Arkoma Woodford. The North region natural gas production was up 1.9 Bcf for the year ended December 31, 2008 compared to 2007 due to additional natural gas being sold through the Hiland Partners Badlands plant, which became operational in late August 2007. Since that time, we have sold 2.8 Bcf of natural gas from the Red River units through the new plant.
Revenues
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the year ended December 31, 2008 were $939.9 million, a 55% increase from sales of $606.5 million for 2007. Our sales volumes increased 1,703 MBoe or 16% over the 2007 volumes due to the continuing success of our enhanced crude oil recovery and drilling programs. Our realized price per Boe increased $19.35 to $77.66 for the year ended December 31, 2008 from $58.31 for the year ended December 31, 2007. During 2008, the differential between NYMEX calendar month average crude oil prices and our realized crude oil prices widened. The differential per barrel for the year ended December 31, 2008 was $9.50 compared to $8.85 for 2007. Factors contributing to the higher differentials in 2008 included Canadian crude oil imports, increases in production in the North region, coupled with downstream transportation capacity constraints, refinery downtime in the North region, and reduced seasonal demand for gasoline.
Derivatives. In July 2007, we entered into fixed-price swap contracts covering 10,000 barrels of crude oil per day for the period from August 2007 through April 2008. During each month of the contract, we received a fixed-price of $72.90 per barrel and paid to the counterparties the average of the prompt NYMEX crude oil futures contract settlement prices for such month. SFAS No. 133, “Accounting for Derivative Instruments and Hedging 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 marked our derivative instruments to fair value in accordance with the provisions of SFAS No. 133 and recognized the realized and unrealized change in fair value as a gain (loss) on derivative instruments in the statements of income. These contracts expired in April 2008 and during the year ended December 31, 2008 we had recognized losses on derivatives of $8.0 million. We did not have any open derivative positions at December 31, 2008.
Crude Oil and Natural Gas Service Operations. Our crude 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 crude oil. We sold high-pressure air from our Red River units to a third party and recorded revenues of $3.0 million for the year ended December 31, 2008 and revenues of $3.1 million for the year ended December 31, 2007. Prices for reclaimed crude oil sold from our central treating unit were higher for the year ended December 31, 2008 than the comparable 2007 period. The price increased $27.45 per barrel which increased reclaimed crude oil income by $6.5 million contributing to an overall increase in crude oil and natural gas service operations revenue of $8.0 million for the year ended December 31, 2008. Associated crude oil and natural gas service operations expenses increased $5.5 million to $18.2 million during the year ended December 31, 2008 from $12.7 million during the year ended December 31, 2007 due mainly to an increase in the costs of purchasing and treating crude oil for resale compared to the same period in 2007.
Operating Costs and Expenses
Production Expense and Tax. Production expense increased $25.1 million, or 33%, during the year ended December 31, 2008 to $101.6 million from $76.5 million during the year ended December 31, 2007. The increase in production expense is partially attributable to our increase in sales volumes of 16% which is a direct result of new wells being drilled and escalating field service costs. During the year ended December 31, 2008, we participated in the completion of 359 gross (152.5 net) wells. Production expense per Boe increased to $8.40 for the year ended December 31, 2008 from $7.35 per Boe for the year ended December 31, 2007.
Production taxes increased $26.0 million, or 80%, during the year ended December 31, 2008 compared to the year ended December 31, 2007 as a result of higher revenues resulting from increased sales prices and volumes and the expiration of various tax incentives. The majority of the production tax increase was in the South and North regions due to an increase of 1,697 MBoe sold in the year ended December 31, 2008 compared to the year ended December 31, 2007. Production tax as a percentage of crude oil and natural gas sales was 6.2% for the year ended December 31, 2008 compared to 5.4% for the year ended December 31, 2007. 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 crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana, North Dakota and Oklahoma new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate increases to the statutory rates. Our overall rate is expected to increase as production tax incentives we currently receive for horizontal wells reach the end of their incentive period.
On a unit of sales basis, production expense and production taxes were as follows:
Exploration Expense. Exploration expense consists primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expense increased $31.0 million in the year ended December 31, 2008 to $40.2 million due primarily to an increase in dry hole expense of $16.5 million to $20.0 million and an increase in seismic expense of $14.0 million to $16.9 million. The majority of the dry hole costs were in the North region for the years ended December 31, 2008 and 2007.
Depreciation, Depletion, Amortization and Accretion (DD&A). Total DD&A increased $55.3 million in 2008 primarily due to an increase in crude oil and natural gas DD&A of $54.4 million as a result of increased production and additional properties being added through our drilling program and acquisitions. Additionally, DD&A increased as a result of the decrease in commodity prices used to calculate year end reserves volumes. Lower prices have the effect of decreasing the economic life of crude oil and natural gas properties, which lowers future reserve volumes and increases DD&A. The following table shows the components of our DD&A rate.
Property Impairments. Property impairments, both non-producing and developed, increased in the year ended December 31, 2008 by $10.9 million to $28.8 million compared to $17.9 million during the year ended December 31, 2007. Impairment of non-producing properties increased $3.3 million during the year ended December 31, 2008 to $16.5 million compared to $13.2 million for 2007 reflecting higher amortization of lease costs in our existing fields resulting from further defining likely drilling locations and amortization of new fields. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. 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 crude oil and natural gas properties were approximately $12.3 million for the year ended December 31, 2008 compared to approximately $4.7 million for the year ended December 31, 2007, an increase of $7.6 million, or 161%. We evaluate our developed crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair market value based on
discounted cash flows. Impairments in 2008 reflect uneconomic drilling results in certain small fields primarily in our South region and our Rockies Other area which resulted in impairments of $8.8 million in 2008. The significant decrease in crude oil and natural gas prices at December 31, 2008 resulted in 2008 impairments of $3.5 million. Impairments in 2007 were primarily related to uneconomic wells in our Gulf Coast area in the South region and certain small fields primarily in our South region.
General and Administrative Expense. General and administrative expense increased $2.9 million to $35.7 million during the year ended December 31, 2008 from $32.8 million during the comparable period of 2007. General and administrative expense includes non-cash charges for stock-based compensation of $9.1 million and $12.8 million for the years ended December 31, 2008 and 2007, respectively. Stock compensation expense was higher in 2007 due to an increase in the value of our stock as we approached our initial public offering. Until our initial public offering in May 2007, the outstanding options and restricted stock were accounted for as liability awards and their value fluctuated with the value of the underlying stock. General and administrative expense excluding equity compensation increased $7.2 million for the twelve months ended December 31, 2008 compared to the twelve months ended December 31, 2007. The increase was primarily related to a $6.6 million increase in personnel costs due to additional employees and higher wages and increased benefits. On a volumetric basis, general and administrative expense was $2.95 per Boe for the year ended December 31, 2008 compared to $3.15 per Boe for the year ended December 31, 2007 due to higher sales volumes.
Interest Expense. Interest expense decreased 6%, or $0.8 million, for the year ended December 31, 2008 compared to the year ended December 31, 2007, due to lower interest rates during 2008 partially offset by higher debt balances. Our average debt balance increased to $248.7 million for the year ended December 31, 2008 compared to $182.2 million for the year ended December 31, 2007, but the weighted average interest rate on our revolving credit facility was 1.93% lower at 4.54% for the year ended December 31, 2008 compared to 6.47% for the same period in 2007. At December 31, 2008 our outstanding debt balance was $376.4 million with a weighted average interest rate of 4.11%.
Income Taxes. Income taxes for the year ended December 31, 2008 were $197.6 million compared to $268.2 million for the year ended December 31, 2007. The 2007 taxes 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 Notes to Consolidated Financial Statements-Note 7 for more information.
Liquidity and Capital Resources
Our primary sources of liquidity have been cash flows generated from operating activities, financing provided by our revolving credit facility, and the issuance of the Notes in September 2009. As we exited the fourth quarter of 2008, crude oil and natural gas prices had declined significantly from their record levels which reduced our operational cash flows. In response, we began reducing capital expenditures during the last quarter of 2008 and prepared our capital expenditure budget for 2009 assuming lower commodity prices. During the second quarter of 2009 we began to see increases in crude oil prices to levels double the first quarter lows; however, natural gas prices remained depressed. Since crude oil accounts for more than 70% of our production, the price increase resulted in improved cash flows from operations and better liquidity. Additionally, we were able to increase our revolving credit facility commitment from $672.5 million to $750.0 million during the second quarter of 2009.
Our current revolving credit facility is backed by a syndicate of 15 banks, which approved an increase in our borrowing base from $850.0 million to $1.0 billion effective December 1, 2009. We believe that our current syndicate banks have the capability to fund up to our current commitment of $750.0 million. If one or more banks should not be able to do so, we may not have the full availability of $750.0 million commitment. On September 23, 2009, we issued $300.0 million of 8 1/4% Senior Notes due 2019 and received net proceeds of
approximately $289.7 million after deducting underwriters’ discounts and other expenses and after giving effect to the discount at which the Notes were issued. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility. As of December 31, 2009, we had $523.4 million available under our revolving credit facility and $16.3 million in working capital. During the first quarter of 2009, we had rig commitments on up to 6 rigs. Five of the contracts expired in 2009 and we currently have one remaining rig contract that expires in August 2011. Our current plan is to expand capital expenditures in a measured manner without long-term rig commitments. This will allow us to adapt rapidly to commodity price changes or other external factors. During 2009, we experienced reductions in crude oil field service costs, including drilling costs, compared to 2008.
We believe that funds from operating cash flows and the revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments and contingencies for the next 12 months.
We currently anticipate that we will be able to generate or obtain funds sufficient to meet our long-term cash requirements. We intend to finance our future capital expenditures primarily through cash flows 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 or the sale of assets. Lower crude oil and natural gas prices will reduce our cash flows and borrowing ability. Although our average realized price received for crude oil and natural gas was $45.10 per Boe for the year ended December 31, 2009, it was effected by lower crude oil prices for the first half of the year. In the fourth quarter of 2009, our average realized price received for crude oil and natural gas was $56.69 per Boe. Furthermore, the issuance of additional debt may require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows 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. Please see Item 1A. Risk Factors-Our exploration, 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 crude oil and natural gas reserves.
In the future, we may not be able to access adequate funding under our bank credit facilities as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.
If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.
Cash Flows from Operating Activities
Our net cash provided by operating activities was $375.9 million, $719.9 million and $390.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. The decrease in operating cash flows for the year ended December 31, 2009 was mainly due to decreases in revenue as a result of lower commodity prices as explained above.
Cash Flows from Investing Activities
During the years ended December 31, 2009, 2008 and 2007 we had cash flows used in investing activities (excluding asset sales) of $507.0 million, $930.8 million and $486.4 million, respectively, in our capital program,
inclusive of dry hole costs. The decrease in our cash flows used in investing activities for the year ended December 31, 2009 was mainly due to decreases in capital expenditures as a result of lower commodity prices in 2009.
Cash Flows from Financing Activities
Net cash provided by financing activities of $133.0 million for the year ended December 31, 2009, was mainly the result of amounts received from the issuance of the Notes less amounts repaid under our revolving credit facility to fund capital expenditures, including the reduction in accounts payable. Net cash provided by financing activities of $204.2 million for the year ended December 31, 2008 was mainly the results of borrowings under our revolving credit facility to fund capital expenditures, including acquisitions. Net cash provided by financing activities of $94.6 million for the year ended December 31, 2007 was mainly the results of proceeds of our initial public offering net of amounts used to pay cash dividends.
Revolving Credit Facility
We had $226.0 million and $376.4 million outstanding under our revolving credit facility at December 31, 2009 and 2008, respectively. The decrease was largely due to the repayment of a portion of the outstanding borrowings under our revolving credit facility with the net proceeds from the issuance of the Notes in September 2009. As of February 19, 2010, the amount outstanding under our credit facility had decreased by $28.0 million to $198.0 million.
The revolving credit facility matures on April 12, 2011, and borrowings under our revolving credit facility bear interest, payable quarterly, at (a) a rate per annum equal to the London Interbank Offered Rate for one, two, three or six months as offered by the lead bank plus an applicable margin ranging from 175 to 250 basis points, depending on the percentage of our borrowing base utilized or (b) the lead bank’s reference rate. At December 31, 2009 and 2008, we had cash and cash equivalents of $14.2 million and $5.2 million, respectively, and available borrowing capacity on our revolving credit facility of $523.4 million and $176.1 million, respectively. At February 19, 2010, we had available borrowing capacity on our revolving credit facility of $551.2 million. We anticipate that we will negotiate a new revolving credit facility during the second quarter of 2010 as our current revolving credit facility matures in April 2011.
The revolving credit facility was amended in December 2009 to increase the borrowing base from $850.0 million to $1.0 billion, subject to semi-annual redetermination. Borrowings under the revolving credit facility are secured by liens on substantially all of our crude oil and natural gas properties and associated assets. Our next semi-annual redetermination will occur in April 2010. The terms of the revolving credit facility commitment level can be increased up to the lesser of the borrowing base or note amount subject to bank agreement. The note amount remains at $750.0 million which is also our commitment level.
The revolving 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 revolving 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 therein, of no greater than 3.75 to 1.0. As of December 31, 2009, we were in compliance with all covenants.
8 1/4% Senior Subordinated Notes due 2019
On September 23, 2009, the Company issued $300 million of the Notes. The Notes, which carry a coupon rate of 8.25%, were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. The Company received net proceeds of approximately $289.7 million, after deducting the
underwriters’ discounts of approximately $6.8 million and offering expenses of approximately $1.0 million. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility.
The Notes will mature on October 1, 2019, and interest is payable on the Notes on each April 1 and October 1, commencing April 1, 2010. The Company has the option to redeem all or a portion of the Notes at any time on or after October 1, 2014 at the redemption price specified in the Indenture dated September 23, 2009 (the “Indenture”) plus accrued and unpaid interest. The Company may also redeem the Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to October 1, 2014. In addition, the Company may redeem up to 35% of the Notes prior to October 1, 2012 under certain circumstances with the net cash proceeds from certain equity offerings. The Indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants as of December 31, 2009. The Notes are not subject to any sinking fund requirements. Our subsidiary, which currently has no independent assets or operations, fully and unconditionally guarantees this debt.
Capital Expenditures and Commitments
We evaluate opportunities to purchase or sell crude oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunities to expand our existing core areas. Acquisition expenditures are not budgeted.
We invested approximately $434.0 million (inclusive of non-cash accruals of $74.7 million) for capital and exploration expenditures in 2009 as follows:
Expenditures for exploration and development of crude oil and natural gas properties are the primary use of our capital resources. In response to significantly lower crude oil and natural gas prices during the first half of 2009 and the resulting decrease in expected cash flows, we reduced our capital expenditures budgeted from $609.0 million in 2008 to $275.0 million for 2009. In August 2009, when crude oil prices and our cash flows began to increase, we increased our budget to $390.0 million. In November 2009, we increased our budget again to $415.0 million with the majority of the additional spending directed at drilling operations in the North Dakota Bakken.
Cash flows from operations as shown on our statements of cash flows was negatively impacted by payments made to reduce prior year accruals and was less than our capital expenditures for the year ended December 31, 2009. However, when you consider the $74.7 million in non-cash December 31, 2008 accruals paid in 2009, cash generated from current year operating activities exceeded our capital expenditures.
Based on strong cash flows and our positive outlook, in November 2009, our Board of Directors approved a preliminary 2010 capital expenditures budget of $650.0 million. In February 2010, our Board of Directors increased the capital expenditures budget to $850 million in order to accelerate our drilling program as follows:
Our 2010 budgeted capital expenditures are approximately 95% higher than the $434.0 million invested during 2009. We plan to invest approximately $671 million in drilling of which 77% will be invested in the Bakken field, 14% in the Oklahoma Woodford play, 5% in the Red River units and 4% in various other plays
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 under our revolving credit facility will be sufficient to satisfy our 2010 capital budget. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flows, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
Shareholder Distribution
On January 10, 2007, we declared a cash dividend of approximately $18.8 million to our shareholders and, subject to forfeiture, to holders of unvested restricted stock. On January 31, 2007, we paid $18.7 million of the dividend declared, of which $16.9 million was paid to our principal shareholder. On March 6, 2007, we declared a cash dividend of approximately $33.3 million to our shareholders of record and, subject to forfeiture, to holders of unvested restricted stock. On April 12, 2007, we paid $33.1 million of the dividend declared, of which $30.0 million was paid to our principal shareholder. We converted from a subchapter S corporation to a subchapter C corporation on May 14, 2007 when we became a publicly traded company, and we do not anticipate paying any additional cash dividends on our common stock in the foreseeable future.
Obligations and Commitments
We have the following contractual obligations and commitments as of December 31, 2009:
(1) Does not reflect the discount at which the Notes were issued.
(2) Interest expense includes interest on the Notes and revolving credit facility and assumes that the interest rate of 2.66% at December 31, 2009 continues for the life of the revolving credit facility.
(3) See Notes to Consolidated Financial Statements-Note 10. Commitments and Contingencies-Drilling Commitments for a description of drilling contract commitments.
(4) Amounts represent expected asset retirements by period.
Oil and Gas Hedging
As part of our risk management program, we hedge a portion of our anticipated future crude oil and natural gas production for the next 12-24 months to reduce our exposure to fluctuations in crude oil and natural gas prices. In addition, we may utilize basis contracts to hedge the differential between the NYMEX posted prices and those of our physical pricing points. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions.
While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. All of our hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. Substantially all of our hedging transactions are settled based upon reported settlement prices on the NYMEX.
Between January 1, 2010 and February 19, 2010, we entered into additional crude oil and natural gas derivative contracts summarized in the table below. None of these contracts have been designated for hedge accounting.
Crude Oil
Natural Gas
Please see Notes to Consolidated Financial Statements-Note 5. Derivative Contracts appearing later in this report for more discussion and tables and a description of the accounting applicable to our hedging program, a listing of open contracts as of December 31, 2009 and the estimated fair market value of those contracts as of that date.
Critical Accounting Policies and Practices
Our historical consolidated financial statements and notes to our historical consolidated financial statements contain information that is pertinent to our management’s discussion and 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. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.
In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for derivatives and crude oil and natural gas activities, asset retirement obligations, impairment of assets and income taxes. 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.
Crude Oil and Natural Gas Reserves and Standardized Measure of Future Cash Flows
Our independent engineers and technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Current accounting guidance allows only proved crude 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, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Even though our independent engineers and technical 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. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. 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, crude oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. We
cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter future DD&A and result in impairment of assets that may be material.
In addition, the SEC has not reviewed our reserve estimates, or any reporting company’s reserve estimates, under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of our proved reserves at December 31, 2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.
Revenue Recognition
We derive substantially all of our revenues from the sale of crude oil and natural gas. Crude oil and natural 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.
Derivative Activities
We sometimes utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future crude oil and natural gas production. We may hedge a portion of our anticipated crude oil and natural gas production for the next 12-24 months. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. We do not use derivative instruments for trading purposes. Under accounting rules, we may elect to designate those derivatives that qualify for hedge accounting as cash flow hedges against the price that we will receive for our future crude oil and natural gas production. We have elected not to designate any future price risk management activities as accounting hedges. Because our derivative contracts are not designated for hedge accounting they are accounted for on a mark-to-market basis through the income statements, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. Derivative assets and liabilities with the same counterparty and subject to contractual terms which provide for net settlement are reported on a net basis on our consolidated balance sheet.
In determining the amounts to be recorded for our open hedge contracts, we are required to estimate the fair value of the derivative. We use a third party to provide our derivative valuations. Their valuation models for derivative contracts are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the hedge agreements and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. We validate our valuations by comparison to our counterparty marks and management reviews.
Successful Efforts Method of Accounting
We use the successful efforts method of accounting for our crude oil and natural gas properties, including enhanced recovery projects, whereby costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells or projects that find proved reserves and to drill and equip development wells or projects and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs,
seismic costs, lease rentals and costs associated with unsuccessful exploratory wells or projects, including enhanced recovery projects, are expensed as incurred. Maintenance, repairs and costs of injection are expensed as incurred, except that the cost of replacements or renewals that expand capacity or improve production are capitalized.
Depreciation, depletion and amortization, or DD&A, of capitalized drilling and development costs of crude oil and natural gas properties are generally computed using the unit of production method on a field basis based on total estimated proved developed crude 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 crude oil and natural gas are established based on estimates made by our geologists and engineers and 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.
Unproved crude oil and natural gas properties, the majority of the costs of which relates to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level consistent with the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of the unproved properties’ costs which we feel will not be transferred to proved properties over the life of the lease.
Asset Retirement Obligations
We are required to recognize an estimated liability for future costs associated with the abandonment of our crude oil and natural gas properties. We base our estimate of the liability on our historical experience in abandoning crude oil and natural gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit adjusted risk-free rate to use. The impact to the consolidated statement of income from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our crude oil and natural gas properties.
Impairment of Assets
All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk adjusted proved reserves. For producing properties the evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce these products, estimates of future crude 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 downward revisions to crude 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.
Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of 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. Other non-producing properties are
amortized on a composite method based on the Company’s estimated experience of successful drilling and the average holding period. The estimate of successful drilling rate is highly judgmental and subject to material revision in future periods as better information becomes available.
Income Taxes
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2009, we believe that all of our deferred tax assets recorded on our consolidated balance sheet will ultimately be recovered. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing crude oil and natural gas prices). If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not probable.
Our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect taxpaying companies. Our effective tax rate is affected by changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state. As the mix of property, payroll, and revenues varies by state, our estimated tax rate changes. Due to the size of our gross deferred tax balances, a small change in our estimated future tax rate can have a material effect on current period earnings.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
Recent Accounting Pronouncements Not Yet Adopted
For a description of the accounting standards that we adopted in 2009, see Notes to Consolidated Financial Statements-Note 1. Organization and Summary of Significant Accounting Policies.
In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update No. 2010-06 which amended the authoritative accounting guidance related to fair value measurements and disclosures. The update requires new disclosures about transfers in and out of Level 1 and Level 2 fair value measurements and additional disaggregation of activity in Level 3 fair value measures. It also provides clarification about existing disclosures. The disclosures and clarifications will be effective for us for our year ended December 31, 2010 except for the disaggregation disclosures of activity in Level 3 fair value measures which will be effective for us for the year ended December 31, 2011.
Inflation
Historically, general inflationary trends have not had a material effect on our operating results. However, in recent years we have experienced inflationary pressure on technical staff compensation and the cost of oilfield services and equipment due to the increases in drilling activity and competitive pressures resulting from higher crude oil and natural gas prices and may again in the future.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments.
Commodity Price Risk. Our primary market risk exposure is in the pricing applicable to our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the year ended December 31, 2009, our annual revenue would increase or decrease by approximately $100.0 million for each $10.00 per barrel change in crude oil prices and $22.0 million for each $1.00 per MMBtu change in natural gas prices.
To partially reduce price risk caused by these market fluctuations, we may hedge a portion of our anticipated crude oil and natural gas production for the next 12-24 months as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between NYMEX Henry Hub posted prices and those of our physical pricing points. We may use hedging to reduce our exposure to fluctuations in crude oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty.
For the year ended December 31, 2009, we realized gains on gas derivatives of $0.6 million. We reported an unrealized non-cash mark-to-market gain on gas derivatives of $1.6 million and an unrealized non-cash mark-to-market loss on oil derivatives of $3.7 million. The fair value of our derivative instruments at December 31, 2009 was a liability of $2.1 million. A 10% increase or decrease in the future prices used in the valuation would have increased the liability to $25.4 million or changed the valuation to a receivable of $19.9 million, respectively.
For a further discussion of our hedging activities, see information under the caption Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Oil and Gas Hedging of this report and the discussion and tables in Notes to Consolidated Financial Statements-Note 5. Derivative Instruments appearing later in this report.
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 joint interest receivables ($59.8 million at December 31, 2009) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($125.8 million in receivables at December 31, 2009). See Notes to Consolidated Financial Statements.-Note 1. Organization and Summary of Significant Accounting Policies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in
order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.
We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to support crude oil and natural gas sales receivables owed to us.
Interest Rate Risk. Our exposure to changes in interest rates relates primarily to long-term debt obligations. We may 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 revolving credit facility. We had revolving credit facility debt of $198.0 million outstanding under our revolving credit facility at February 19, 2010. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $2.0 million per year and a $1.2 million decrease in net income. Our revolving credit facility matures in 2011 and the weighted-average interest rate at February 19, 2010 was 3.09%. On September 23, 2009, we issued $300 million of 8 1/4% Senior Notes due 2019. The Notes, which carry a coupon rate of 8.25%, were sold at a discount of 99.16% of par and equates to an effective yield to maturity of approximately 8.375%. Interest is payable on the Notes on each April 1 and October 1, commencing April 1, 2010. The following table presents our long-term debt maturities and the weighted average interest rates by expected maturity date:
(1) This amount does not reflect the discount at which the Notes were issued of ($2.5) million.
Changes in interest rates affect the amount we pay on borrowings under our revolving credit facility. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. However, changes in interest rates do affect the fair value of our debt.
Item 8.
Item 8. Financial Statements and Supplemental Data
Index to Consolidated Financial Statements
Page
Continental Resources, Inc. and Subsidiary Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Continental Resources, Inc.
We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and Subsidiary (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Continental Resources, Inc. and Subsidiary as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Continental Resources, Inc. and Subsidiary’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 26, 2010 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 26, 2010
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
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. and Subsidiary
Notes to Consolidated Financial Statements
1. Organization and Summary of Significant Accounting Policies
Description of Company
Continental Resources, Inc. (the “Company”) is incorporated under the laws of the State of Oklahoma. It was originally formed in 1967 to explore, develop and produce crude oil and natural gas properties in Oklahoma. Through 1993, its activities and growth remained focused primarily in Oklahoma. In 1993, the Company expanded its activity into the North region. Approximately 76% of its estimated proved reserves as of December 31, 2009 are located in the North region. As of December 31, 2009, the Company had interests in 2,317 wells and serves as the operator of 1,661 of these wells.
On May 14, 2007, the Company completed its initial public offering. In conjunction therewith, the Company effected an 11 for 1 stock split by means of a stock dividend. All prior period share and per share information contained in this report has 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.
Basis of presentation
Continental had one wholly owned subsidiary, Banner Pipeline Company, L. L. C., at December 31, 2009, which currently has no assets or operations. The consolidated financial statements include the accounts of Continental and its wholly owned subsidiary after all significant inter-company accounts and transactions have been eliminated.
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. The estimate of the Company’s crude oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment on producing crude oil and natural gas properties, is the most significant of the estimates and assumptions that affect reported results.
Pro forma information (unaudited)
Pro forma adjustments are reflected on the consolidated statements of income to provide for income taxes as if the Company had been a subchapter C corporation for all pro forma 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 basis. 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. The pro forma tax effects are based upon 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 attained had the transactions actually taken place.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Revenue recognition
Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received 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 received are recorded in the month payment is received. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or liability is recognized only to the extent that an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2009 and 2008 were not material. Charges for gathering and transportation are included in production expenses.
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 crude oil and natural gas exploration and production related activities. Crude 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, 2009, 2008 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 crude oil and natural gas production accounted for 56% (one purchaser), 44% (one purchaser) and 44% (three purchasers) of total revenues for 2009, 2008 and 2007, respectively. These purchasers constituted all purchasers with sales in excess of 10% of total revenues. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Inventories
Inventories are stated at the lower of cost or market and consists of the following:
As of December 31, 2009, our total crude oil inventory of 398,000 barrels valued at $14.7 million consisted of approximately 253,000 barrels of line fill requirements and 145,000 barrels of temporarily stored crude oil. As of December 31, 2008, our total crude oil inventory of 275,000 barrels valued at $7.3 million consisted of approximately 230,000 barrels of line fill requirements and 45,000 barrels of temporarily stored crude oil. Our inventory, including line fill, is valued at the lower of cost or market using the FIFO inventory method.
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:
Crude Oil and natural gas properties
The Company uses the successful efforts method of accounting for crude oil and natural gas properties, including enhanced recovery projects, whereby costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves and to drill and equip development wells or projects and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs, lease rentals and costs associated with unsuccessful exploratory wells or projects, including enhanced recovery projects, are expensed as incurred. Maintenance, repairs and costs of injection are expensed as incurred, except the cost of replacements or renewals that expand capacity or improve production are capitalized.
As required, the Company reports capitalized exploratory drilling costs on the balance sheet. 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, 2009 and 2008, pending the
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
determination of proved reserves were $22.9 million and $46.3 million, respectively. As of December 31, 2009, exploratory drilling costs of $2.4 million representing 3 wells were suspended one year beyond the completion of drilling and are expected to be fully evaluated in 2010. Of the suspended costs, $0.1 million was incurred in 2007, $1.8 million was incurred in 2008 and the balance in 2009.
Production expenses are those costs incurred by the Company to operate and maintain its crude 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 is required to account for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected abandonment amount over the asset’s life.
The Company’s primary asset retirement obligations relate to future plugging and abandonment expenses on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liability from January 1, 2007 through December 31, 2009:
As of December 31, 2009 and 2008, property and equipment included $33.8 million and $30.5 million, respectively, of net asset retirement costs.
Depreciation, depletion, amortization and accretion
Depreciation, depletion, and amortization (DD&A) of capitalized drilling and development costs, including related support equipment and facilities, of producing crude oil and natural gas properties are computed using the units of production method on a field basis based on total estimated proved developed crude 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 crude oil and natural gas are established based on estimates made by the Company’s geologists, engineers and independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Impairment
Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves. Individually significant non-producing properties are periodically assessed for
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
impairment of value and a loss is recognized at the time of impairment. Other non-producing properties are amortized on a composite method based on the Company’s estimated experience of successful drilling and the average holding period. Impairment of non-producing properties was $47.1 million, $16.6 million and $13.2 million for 2009, 2008, and 2007 respectively.
The Company recognizes impairment expenses for developed crude oil and natural gas properties and other long-lived assets when indicators of impairment are present and the undiscounted cash flows from proved and risk-adjusted probable reserves are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows. The Company’s crude oil and natural gas properties are reviewed for indicators of impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $36.6 million, $12.3 million and $4.7 million, respectively, for 2009, 2008 and 2007. The majority of the impairment recognized in these years relates to fields comprised of a small number of properties or single wells on which the Company does not expect sufficient future net cash flows to recover its carrying cost.
Debt issuance costs
Costs incurred in connection with the revolving credit facility are capitalized and amortized over the term of the related debt using the straight-line basis, the use of which approximates the effective interest method. Costs incurred in issuance of the 8 1/4% Senior Notes due 2019 (“Notes”) were capitalized and amortized using the effective interest method, over the life of the Notes. The Company had capitalized costs of $10.8 million and $2.8 million (net of accumulated amortization of $7.8 million and $5.6 million) relating to the issuance of its long-term debt at December 31, 2009 and 2008, respectively. During the years ended December 31, 2009, 2008 and 2007, the Company recognized associated amortization expense of $2.2 million, $0.6 million and $0.6 million, respectively.
Derivatives
The Company is required to recognize 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 date. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation.
Fair value of financial instruments
The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short maturity of these instruments.
Long-term debt consists of the revolving credit facility and the 8 1/4% Senior Notes due 2019 (“Notes”). The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The estimated fair value of the revolving credit facility is $226.0 million and $376.4 million at December 31, 2009 and 2008, respectively. The fair value of the Notes is based on quoted market prices and is $315.8 million at December 31, 2009.
Income taxes
On May 14, 2007, the Company completed its initial public offering. Prior to completion of the public offering, the Company was a subchapter S corporation and income taxes were payable by its shareholders. In
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
connection with the public offering, the Company converted to a subchapter C corporation and recorded a charge to income in the second quarter of 2007 of $198.4 million to initially recognize deferred taxes at May 14, 2007. Thereafter, the Company has provided for income taxes on income.
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.
The Company’s policy is to recognize penalties and interest, if any, in income tax expense.
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 earnings per share computations for the years ended December 31, 2009, 2008 and 2007:
New accounting standards
In December 2007, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) 805-10 (formerly SFAS No. 141 (R)), Business Combinations, and ASC 810-10 (formerly SFAS No. 160), Noncontrolling Interests in Consolidated Financial Statements, and amendment of ARB No. 51, which changes how business acquisitions are accounted for and impacts financial statements both on the acquisition date and in subsequent periods. There are also changes in the accounting and reporting for minority interests, which are re-characterized as noncontrolling interests and classified as a component of equity. Both of these standards are effective for the Company for the year ended December 31, 2009. ASC 805-10 will be applied prospectively while ASC 810-10 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements will be applied prospectively. The adoption of these standards did not have any impact on the Company’s financial position or results of operations though it would impact financial reporting for any future acquisitions.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
In February 2008, the FASB issued ASC 820-10 (formerly Financial Staff Position SFAS 157-2), Effective Date of FASB Statement No. 157, which provided a one year delay of the effective date of ASC 820-10 (formerly SFAS 157) to January 1, 2009 for the Company for non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, the Company applied the provisions of the standard to non-financial assets and liabilities. The standard applies to the Company’s non-financial assets and liabilities in calculating fair value related to impairments of long-lived assets and asset retirement obligations. In both cases, the standard had no effect on these calculations. Both calculations are based primarily on level three inputs. The adoption of the standard on January 1, 2009 did not have a material impact on the Company’s financial position or results of operations although the required disclosures have been made in Notes to Consolidated Financial Statements-Note 5, Derivative Instruments.
In March 2008, the FASB issued ASC 815-10 (formerly SFAS No. 161), Disclosures about Derivative Instruments and Hedging Activities, which amends and expands disclosure requirements to require qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The Company adopted the disclosure requirements of the standard beginning January 1, 2009 and it did not have an impact on the Company’s financial position or results of operations.
In April 2009, the FASB issued additional application guidance and enhancements to disclosures regarding fair value measurements and impairments of securities.
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ASC 820-10 (formerly FASB Staff Position (“FSP”) No. FAS 157-4), “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidelines for making fair value measurements more consistent. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. The Company adopted this FSP for the period ended June 30, 2009 and the adoption did not have an impact on its financial position or results of operations.
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ASC 825-10 (formerly FSP No. FAS 107-1 and APB 28-1), “Interim Disclosures about Fair Value of Financial Instruments,” requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements, which enhances consistency in financial reporting. The Company adopted the provisions for the period ended June 30, 2009 and the adoption did not have an impact on its financial position or results of operations.
In May 2009, the FASB issued ASC 855-10 (formerly SFAS No. 165), “Subsequent Events” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that previously existed. This statement, which includes a new required disclosure of the date through which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. The Company adopted the standard for the period ending June 30, 2009 and the adoption did not have an impact on its financial position or results of operations.
In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168), Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles. The FASB Accounting Standards CodificationTM (“Codification”) has become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All existing accounting standard documents are superseded by the Codification. All other non-grandfathered non-SEC accounting
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
literature not included in the Codification will become non-authoritative. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Codification does not change or alter existing GAAP and, therefore, did not have an impact on our financial position, results of operations, cash flows or disclosures.
On December 31, 2008, SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting. Release 33-8995 adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in Release 33-8995 include, but are not limited to:
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Oil and gas reserves must be reported using the unweighted arithmetic average of the first day of the month prices for each month within the preceding 12 month period, rather than year-end prices;
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Companies will be allowed to report, on an optional basis, probable and possible reserves;
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Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;
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Companies will be required to disclose, in narrative form, additional details about their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs; and
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Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.
In October 2009, the SEC issued Staff Accounting Bulletin No. 113 (SAB No. 113), which revises portions of the interpretive guidance included in the section of the Staff Accounting Bulletin Series titled Topic 12: Oil and Gas Producing Activities (Topic 12). The principal changes involve revisions to bring Topic 12 into conformity with the contents of Release 33-8995.
We adopted the provisions of the amendments on Modernization of Oil and Gas Reporting for the year ended December 31, 2009. It increased the disclosures about the Company’s reserves; it changed the definition of proved reserves and changed the pricing assumptions. For a discussion of the impact of these provisions, please see Note 15. Supplemental Crude Oil and Natural Gas Information (unaudited).
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:
Noncash investing and financing activities are as follows:
3. Property, Plant, and Equipment
Property, plant, and equipment include the following at December 31, 2009 and 2008:
4. Accrued Liabilities and Other
Accrued liabilities and other includes the following at December 31, 2009 and 2008:
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
5. Derivative Instruments
The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company elected not to designate its derivatives as cash flow hedges and as a result marked its derivative instruments to fair value and recognized the realized and unrealized change in fair value on derivative instruments in the statements of income under the caption “Loss on mark-to-market derivative instruments.”
We have utilized swap and collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements.
With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price, we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price and neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price.
All of our derivative contracts are carried at their fair value on our consolidated balance sheet under the captions “Receivables, joint interest and other, net” and “Accrued liabilities and other.” Substantially all of our oil and gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, and, in the case of collars, volatility and the time value of options. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 6. Fair Value Measurements.
At December 31, 2009, we had outstanding contracts with respect to our future production as set forth in the tables below.
Crude Oil
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Natural Gas
Natural Gas Basis Centerpoint East
Derivative Fair Value Income (Loss)
The following table presents information about the components of derivative fair value loss for the following periods presented:
The table below provides data about the carrying values of derivatives that are not accounted for using hedge accounting. The Company did not have any derivative assets or liabilities at December 31, 2008.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
6. Fair Value Measurements
The Company is required to calculate fair value based on a hierarchy which prioritizes the input to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. The Company uses Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. In determining the fair value of our fixed price and basis swaps, due to the unavailability of relevant comparable market data for our exact contracts, a discounted cash flow method is used. The discounted cash flow method estimates future cash flows based on quoted market prices for future commodity prices, observable inputs relating to basis differentials and a risk-adjusted discount rate. The fair value of fixed price and basis swap derivatives is calculated using mainly significant observable inputs (Level 2). The calculation of the fair value of our collar contracts requires the use of an option-pricing model with significant unobservable inputs (Level 3). The valuation models for derivative contracts are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company’s calculation for all trades is then compared to the counterparty valuation for reasonableness. The following table summarizes the valuation of investments and financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2009:
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods:
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Financial Instruments not Recorded at Fair Value
The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Consolidated Financial Statements.
The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The fair value of the Notes is based on quoted market prices.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate the fair values.
Asset Impairments-Proved crude oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The estimated future cash flows expected in connection with the property are compared to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used. The discounted cash flow method estimates future cash flows based on management’s expectations for the future and includes estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate. The fair value of crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3).
As a result of changes in reserves and the forward futures price strip, developed crude oil and natural gas properties were reviewed for impairment at December 31, 2009 and the Company determined that the carrying amount of certain fields were not recoverable from future cash flows and, therefore, were impaired. The affected fields had a fair value of $0.8 million at December 31, 2009 resulting in $0.5 million of developed property impairments for the quarter ended December 31, 2009. A similar calculation at June 30, 2009, determined that the carrying amount of certain fields were not recoverable from future cash flows and, therefore, were impaired. The affected fields had a fair value of $1.8 million at June 30, 2009 resulting in $10.1 million of developed property impairments for the quarter ended June 30, 2009. A similar calculation at March 31, 2009 determined that the carrying amount of certain fields was not recoverable from future cash flows and, therefore, was impaired. The affected fields at March 31, 2009 had a fair value of $13.1 million resulting in $26.0 million of developed property impairments for first quarter of 2009. Total pre-tax (non-cash) impairments related to developed crude oil and natural gas properties were $36.6 million for the twelve months ended December 31, 2009.
Asset Retirement Obligations-The fair value of asset retirement obligations (AROs) is estimated based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. The fair value of ARO additions for the year ended December 31, 2009 was $1.2 million. The fair value of ARO is calculated using significant unobservable inputs (Level 3).
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
7. Long-term Debt
Long-term debt consists of the following:
(1) This amount includes the discount included in long-term debt of ($2.5) million.
Revolving credit facility-The Company had $226.0 million and $376.4 million in long-term debt outstanding at December 31, 2009 and 2008, respectively, on its revolving credit facility due April 11, 2011. Borrowings under the facility bear interest, payable quarterly, at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by the Company, plus a margin ranging from 175 to 250 basis points, depending on the percentage of its borrowing base utilized, or the lead bank’s reference rate (prime). The revolving credit facility has a maximum facility amount of $750.0 million and a borrowing base of $1.0 billion, subject to semi-annual re-determination. The commitment level was increased from $672.5 million to $750.0 million in June 2009. Under the terms of the revolving credit facility, the commitment level can be increased up to the lesser of the borrowing base or the note amount subject to bank agreement. The Company’s weighted average interest rate was 2.66% at December 31, 2009.
The Company had $523.4 million of unused commitments under the revolving credit facility at December 31, 2009 and incurs commitment fees of 0.25% to 0.375% of the daily average excess of the commitment amount over the outstanding credit balance. The revolving credit facility contains certain covenants including that the Company maintain a Current Ratio of not less than 1.0 to 1.0 (inclusive of availability under the revolving credit facility) and a Total Funded Debt to EBITDAX, as such terms are defined in the credit agreement, of no greater than 3.75 to 1.0. The Company was in compliance with these covenants at December 31, 2009.
8 1/4% Senior Subordinated Notes due 2019-On September 23, 2009, the Company issued Notes. The Notes, which carry a coupon rate of 8.25%, were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. The Company received net proceeds of approximately $289.7 million, after deducting the underwriters’ discounts of approximately $6.8 million and offering expenses of approximately $1.0 million. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility.
The Notes will mature on October 1, 2019, and interest is payable on the Notes on each April 1 and October 1, commencing April 1, 2010. The Company has the option to redeem all or a portion of the Notes at any time on or after October 1, 2014 at the redemption price specified in the Indenture dated September 23, 2009 (the “Indenture”) plus accrued and unpaid interest. The Company may also redeem the Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to October 1, 2014. In addition, the Company may redeem up to 35% of the Notes prior to October 1, 2012 under certain circumstances with the net cash proceeds from certain equity offerings. The Indenture contains certain
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants as of December 31, 2009. The Notes are not subject to any sinking fund requirements. Our subsidiary, which currently has no independent assets or operations, fully and unconditionally guarantees this debt.
Information Technology Financing Arrangement-On August 21, 2009, the Company entered into a Project Financing Agreement with IBM Credit LLC pursuant to which IBM Credit may advance up to $10.0 million for information technology services and software products to be provided to us by International IBM. The financing agreement matures on September 30, 2013, is unsecured and the interest rate under the agreement is 4.73%. In December 2009, the Company paid the note in full and does not plan to take any additional advances in the future.
8. Income Taxes
The following is an analysis of the Company’s income tax provision.
The following table reconciles the income tax provision with income tax at the Federal statutory rate for the years ended December 31, 2009, 2008 and 2007.
(1) Federal tax at the statutory rate and state income taxes have been calculated based upon the net income before tax for the year. However, the Company converted from a subchapter S corporation to a subchapter C
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
corporation on May 14, 2007 and deferred taxes were provided for temporary differences that existed on that date. This adjustment eliminates the taxes related to the net income before tax from the beginning of the year presented through May 14, 2007, which tax effects are already included in deferred taxes recorded upon conversion to a subchapter C corporation.
(2) The Company calculated its estimate of income allocation to the subchapter S corporation period assuming the use of the pro-rata income allocation method for tax purposes instead of the specific identification method used for financial reporting purposes. Using the pro-rata income allocation method, the Company’s income for the year is allocated to the subchapter S corporation and the subchapter C corporation based on number of days without regard to when the income was actually earned.
Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2009 and 2008 are as follows:
(1) Deferred and prepaid taxes on the accompanying consolidated balance sheets contain receivables of $3.0 million and $18.1 million for overpaid taxes at December 31, 2009 and 2008, respectively.
As of December 31, 2009, the Company had a Federal net operating loss carryforward of $17.8 million which will expire beginning in 2028 and state net operating losses totaling $178,000 which have expiration periods that vary according to state jurisdiction. Included in the net operating loss carryforward is excess tax benefit related to stock compensation of $12.9 million ($4.9 million tax effected) for which the deferred tax asset cannot be recorded until the Company is paying regular federal income taxes. When recorded, the offsetting account will be additional paid-in capital. In addition, the Company has an alternative minimum tax credit carryforward of $12.8 million and a statutory depletion carryforward, which will be recognized when realized, of $7.4 million, neither of which expires. The Company’s major tax jurisdictions are the U. S. Federal, Oklahoma, North Dakota and Montana. The earliest year subject to examination in each is 2004. However, prior to May 15, 2007, the Company was an S corporation and any taxes for periods prior to that would be payable by the then existing shareholders.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
9. Lease Commitments
Lease expense associated with the Company’s operating leases for the years ended December 31, 2009, 2008 and 2007, was $1.6 million, $6.0 million and $6.0 million, respectively. At December 31, 2009, including leases renewed and entered into subsequent to December 31, 2009, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year, including leases from related parties, are as follows:
The Company leases compressors from a related party for approximately $400,000 per month under an operating lease with the related party furnishing all labor, lubricants and supplies, and the Company paying for the electric power. The primary term of the operating lease expired on January 28, 2009 and continued on a month-to-month basis through 2009. A new agreement has been negotiated effective February 1, 2010 for a term of 16 months resulting in the monthly lease fee being reduced to $50,000 and Continental assuming 100% of the labor, lubricants and supplies, which previously had been covered under the old lease agreement. The Company leases office space under operating leases from the principal shareholder as explained in Note 11.-Related Party Transactions.
10. Commitments and Contingencies
Drilling Commitments. As of December 31, 2009, the Company had one drilling rig contract that expires in August 2011. This commitment is not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2009 are $14.6 million.
Employee retirement plan. The Company maintains a defined contribution retirement plan for its employees and makes discretionary contributions to the plan based on a percentage of each eligible employee’s compensation. During 2009, 2008 and 2007, contributions to the plan were 5% of eligible employees’ compensation, excluding bonuses. Expense for the years ended December 31, 2009, 2008 and 2007, was $1.3 million, $1.1 million and $0.9 million, respectively.
Employee health claims. The Company self insures employee health claims up to the first $125,000 per employee. The Company self insures employee workers’ compensation claims up to the first $250,000 per employee. Any amounts paid above these are reinsured through third-party providers. The Company accrues for claims that have been incurred but not yet reported based on a review of claims filed versus expected claims based on claims history. At December 31, 2009 and 2008, the accrued liability for health and worker’s compensation claims was $1.3 million and $873,000, respectively.
Litigation. 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, 2009 and 2008, the Company has provided a reserve of $2.7
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
million and $1.2 million, respectively, for various matters none of which are believed to be individually significant.
Environmental Risk. Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
11. Related Party Transactions
The Company currently markets a portion of its natural gas sales to an affiliate. During the years ended December 31, 2009, 2008, and 2007, these sales were approximately $26.6 million, $64.7 million, and $33.9 million. The Company also contracts for field services such as compression and drilling rig services and purchases residue fuel gas and reclaimed crude oil from certain affiliates. Production expense attributable to these affiliates was $16.5 million, $20.7 million and $18.9 million for the years ended December 31, 2009, 2008 and 2007, respectively. The total amount paid to these companies, a portion of which was billed to other interest owners, was approximately $90.4 million, $104.1 million and $76.3 million during the years ended December 31, 2009, 2008 and 2007, respectively. The Company also received $428,000 from an affiliate for saltwater disposal fees. The Company operated crude oil gathering lines in North Dakota and Wyoming on behalf of an affiliated company for which they paid the Company approximately $82,000 and $332,000 during 2009 and 2008, respectively. At December 31, 2009 and 2008, approximately $7.8 million and $14.9 million were due from affiliates and approximately $9.6 million and $25.7 million was due to affiliates, respectively.
Certain officers of the Company own or control entities that own working and royalty interest in wells operated by the Company. The Company paid revenues, including royalties, of approximately $11.3 million, $16.7 million, and $10.4 million and billed expenses of $15.9 million, $14.2 million, and $9.1 million during the years ended December 31, 2009, 2008, and 2007, respectively, to these affiliates. The Company also paid to these affiliates $508,000 in 2009 and $157,000 in 2008 for their share of undeveloped leasehold sales.
The Company leases office space under an operating lease from a company owned by the Company’s principal shareholder. Rents paid associated with this lease totaled approximately $921,000, $804,000 and $707,000 for the years ended December 31, 2009, 2008 and 2007, respectively. The term of the lease is through February 2011 at an annual rate of approximately $988,000.
Under a contract for natural gas sales to an affiliate the Company pays for gathering and treating fees which amounted to $4.5 million in 2009 and $1.0 million in 2008.
12. 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 8,850,000 shares of common stock in the offering and Harold G. Hamm, the Chairman and Chief Executive Officer and principal shareholder of the Company, sold 20,650,000 shares of common stock in the offering. The offering generated gross proceeds of $132.8 million to the Company. The Company incurred underwriters’ discounts of approximately $8.0 million and other expenses of approximately $2.3 million. The Company netted an additional $290,000, representing 30% of the legal, accounting and other costs incurred by the Company after the Company decided to participate in the offering, against the proceeds of the offering. The balance of the offering costs were expensed as incurred. After the payment of offering expenses, the net proceeds were used to repay a portion of the outstanding indebtedness under the revolving credit facility.
On May 14, 2007 the Company converted from a subchapter S corporation to a subchapter C corporation. As a result, the Company recorded an adjustment in the amount of $234.1 million to reduce retained earnings to
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
$65.1 million as of the conversion date, which represents the retained earnings balance of the Company when it originally converted from a subchapter C corporation to a subchapter S corporation in May 1997. The amount of the adjustment represents undistributed earnings of $432.5 million, net of the related provision for deferred income taxes of $198.4 million which was included in the determination of net income for the year ended December 31, 2007.
The terms of the restricted stock grants and stock option grants stipulated that prior to the Company’s initial public offering, it was required to purchase the vested restricted stock and stock acquired from stock option exercises at each employee’s request. Therefore, the awards were accounted for as liability awards. The right to sell and requirement to purchase lapsed when the Company completed its initial public offering. Therefore, the liability for equity compensation of approximately $29.8 million was reclassified to additional paid-in capital on May 14, 2007.
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 2009 and 2008, the Company paid cash dividends of $41,000 and $207,000, respectively, upon vesting of restricted stock granted prior to dividend declaration in 2007.
13. Stock Compensation
The Company has granted stock options and restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) as discussed below. Pursuant to the award agreements, the Company had the right to purchase vested restricted shares and shares acquired by option exercise at all times the employee remained in the employment of the Company and for a period of two years subsequent to leaving the employment of the Company and grantees had the right to require the Company to purchase vested restricted shares and shares acquired by option exercise, each at a purchase price as determined by a formula specified in each award agreement, prior to completion of its initial public offering in May 2007. All grants of stock options were issued with an exercise price equal to the then estimated fair value of the Company’s stock determined according to the plans. Before becoming a public reporting entity, the awards were accounted for as liability awards. The associated liability was transferred to additional paid in capital in May 2007 when the purchase rights lapsed. The Company’s associated compensation expense included in general and administrative expense was $11.4 million, $9.1 million and $12.8 million during 2009, 2008 and 2007, respectively.
Stock Options
Effective October 1, 2000, the Company adopted the 2000 Plan and granted options to eligible employees. These grants consisted of 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, 2009, options covering 2,001,473 shares had been exercised and 478,496 had been cancelled.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
The Company’s stock option activity under the 2000 Plan from December 31, 2006 to December 31, 2009 was as follows:
The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 was $5.3 million, $15.1 million and $11.1 million, respectively. The intrinsic value of a stock option is the amount by which the value of the underlying stock exceeds the exercise price of the option at its exercise date. At December 31, 2009, all options were exercisable and had a weighted average life of 1.31 years with an aggregate intrinsic value of $13.1 million.
For public entities, stock option liability awards are required to be valued using the Black-Scholes or similar option valuation model. In connection therewith, the Company changed from the intrinsic value method to the fair value method of accounting for its stock options and restricted stock. In determining the fair value of the vested stock options and compensation expense as of and for the year ended December 31, 2007 the Company utilized the Black-Sholes option pricing value model based on a fair value for stock option grants of $11.96 per share, weighted average expected life of 2.38 years, expected volatility of 38%, weighted average risk-free interest rate of 4.75% and a dividend yield of zero. The expected life is based on management’s expectations of option exercises. The volatility is based on the average volatility of our peer group for a period approximating the expected life of the options. The risk-free interest rate is based on treasury rates in effect at December 31, 2006 commensurate with the expected life of the stock options.
The following table summarizes information about stock options outstanding at December 31, 2009:
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Restricted Stock
On October 3, 2005, the Company adopted the 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, 2009, the Company had 3,291,186 shares of restricted stock available to grant to directors, officers and key employees under the 2005 Plan. All grants were made on or after October 3, 2005. Restricted stock is awarded in the name of the recipient and except for the right of disposal, constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction including the right to receive dividends, subject to forfeiture. Restricted stock grants vest over periods ranging from one to three years.
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, 2006 to December 31, 2009, is presented below:
The fair value of the restricted shares that vested during 2009, 2008 and 2007 at their vesting date was $13.3 million $11.1 million and $4.3 million, respectively. As of December 31, 2009, there was $19.3 million of unrecognized compensation expense related to non-vested restricted shares. The expense is expected to be recognized over a weighted average period of 1.6 years.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
14. Crude Oil and Natural Gas Property Information
The following table sets forth the Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2009, 2008 and 2007. Prior to the completion of the Company’s initial public offering, the Company was a subchapter S corporation and its taxes were payable by its shareholders. The table below shows taxes for 2007 from May 14, 2007 to the end of the year at statutory rates and pro forma for the remaining periods.
Costs incurred in crude oil and natural gas activities
Costs incurred, both capitalized and expensed, in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities for the three years ended December 31, 2009, 2008 and 2007 are shown below:
Exploration costs above include asset retirement costs of $368,000, $687,000 and $236,000 and development costs above include asset retirement costs of $859,000, $3,252,000 and $401,000 for the years 2009, 2008 and 2007, respectively.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Aggregate capitalized costs
Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, and related accumulated depreciation, depletion and amortization as of December 31, 2009 and 2008 are as follows:
Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, management determines whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved. Often, the determination of whether proved reserves can be recorded under Securities and Exchange Commission guidelines cannot be made when drilling is completed. In those situations where management believes that commercial hydrocarbons have not been discovered, the exploratory drilling costs are reflected in the consolidated statement of income as dry hole costs, a component of exploration expense. Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred on the consolidated balance sheet pending the outcome of those activities.
Operating and financial management review quarterly 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 pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
15. Supplemental Crude Oil and Natural Gas Information (Unaudited)
The following table shows estimates of proved reserves prepared by the Company’s technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L. P.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
prepared reserve estimates for properties comprising approximately 90% of the Company’s standardized measure of discounted future net cash flows as of December 31, 2009 and 83% for 2008 and 2007. Remaining reserve estimates were prepared by the Company’s technical staff. All reserves stated here are located in the United States of America. We adopted the provisions of the amendments on Modernization of Oil and Gas Reporting for the year ended December 31, 2009. It increased the disclosures about the Company’s reserves; it changed the definition of proved reserves and changed the pricing assumptions.
Proved reserves are 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.
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
Natural gas imbalance receivables and liabilities for each of the three years ended December 31, 2009, 2008 and 2007, were not material and have not been included in the reserve estimates.
Proved crude oil and natural gas reserves
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. December 31, 2008 revisions were primarily due to lower commodity prices at the end of 2008.
Reserves at December 31, 2009 were computed using the 12-month unweighted average of the first-day-of-the-month prices as required by the new SEC rules. However, had we been able to use December 31, 2009 prices as in previous years, our revisions for 2009 would have increased by an additional 4,070 MBoe.
Extensions, discoveries and other additions. These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions at December 31, 2009 include increases in proved undeveloped locations as a result of the change in the SEC’s rules to allow producers in continuous accumulation plays to report additional undrilled locations beyond one offset on each side of a horizontal producing well.
The increase in 2009 reserves described above had an effect on our depreciation, depletion and amortization, net income and earnings per share for the fourth quarter of 2009. Other than the effect the change in price methodology had on the reserves as discussed above, the Company is unable to estimate the effect of the remaining changes because a comparative reserve report prepared under the previous rules does not exist.
The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2007, 2008 and 2009:
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 crude oil equivalent using a conversion factor of six thousand cubic feet per barrel.
Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves
The standardized measure of discounted future net cash flows presented in the following table was computed using the unweighted average of first-day-of-the-month commodity prices over the preceding year for 2009 and year-end prices for 2008 and 2007, costs in effect at December 31, 2009 and a 10% discount factor. However, the Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flows computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
The weighted average crude oil price utilized in the computation of future cash inflows was $52.76, $39.69, and $82.86 per barrel at December 31, 2009, 2008 and 2007, respectively. The weighted average natural gas price utilized in the computation of future cash inflows was $3.67, $4.90, and $6.16 per Mcf at December 31, 2009, 2008 and 2007, respectively. Future cash flows are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions.
The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years:
Continental Resources, Inc. and Subsidiary
Notes to Consolidated Financial Statements-(continued)
16. Quarterly Financial Data (Unaudited)
Our quarterly financial data for 2009 and 2008 is summarized below.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There have been no changes in accountants or any disagreements with accountants.
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rule 240.13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in reports that it files or submits with this report accumulated and communicated to the issuer’s management, including its Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, as appropriate to make timely decisions regarding required disclosures and are designed to record, process, summarize and report such information within the time periods specified. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that as of December 31, 2009, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in this report are recorded, processed, summarized and reported, within the time periods specified.
Management’s Report on Internal Control Over Financial Reporting
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on our evaluation under the framework in Internal Control-Integrated Framework, the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2009.
The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that follows.
Harold Hamm
Chief Executive Officer
John D. Hart
Senior Vice President, Chief Financial Officer and Treasurer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Continental Resources, Inc.
We have audited Continental Resources, Inc. (an Oklahoma corporation) and Subsidiary’s (the Company) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Continental Resources, Inc. and Subsidiary maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Continental Resources, Inc. and Subsidiary as of December 31, 2009 and 2008, and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2009 and our report dated February 26, 2010, expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 26, 2010
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 2009 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.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information as to Item 10 will be set forth in the Proxy Statement for the Annual Meeting of Shareholders to be held in 2010, (the “Annual Meeting”) and is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions
The information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
The information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(1) Financial Statements
The Consolidated Financial Statements of Continental Resources, Inc. and the Report of the Independent Registered Public Accounting Firm are included in Item 8 of this report beginning on page 63.
(2) Financial Statement Schedules
None.
(3) Index to Exhibits
The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32 and 99) with this Form 10-K. The exhibits marked with the cross symbol () are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.
Signatures
Pursuant to the requirements Section 13 or 15 (d) of the Securities Exchange Act of 1934, Continental Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Continental Resources, Inc. in the capacities and on the dates indicated.