CONTINENTAL RESRCES (CLR, Financial) filed Quarterly Report for the period ended 2010-09-30.
Continental Resrces has a market cap of $8.61 billion; its shares were traded at around $49.99 with a P/E ratio of 34.5 and P/S ratio of 13.7. CLR is in the portfolios of Richard Aster Jr of Meridian Fund, John Keeley of Keeley Fund Management, Steven Cohen of SAC Capital Advisors, Jeremy Grantham of GMO LLC.
In July 2010, our Board of Directors increased our 2010 capital expenditures budget to $1.3 billion to accelerate our drilling program and increase our acreage positions in strategic plays in the United States. Our previous 2010 capital expenditures budget was $850 million. Our revised 2010 capital expenditures budget of $1.3 billion focuses primarily on increased development in the Bakken shale of North Dakota and Montana, the Anadarko Woodford shale in western Oklahoma, and the Niobrara shale in Colorado and Wyoming. In October 2010, our Board of Directors approved a 2011 capital expenditures budget of $1.36 billion, which will continue to focus primarily on increased development in the Bakken shale of North Dakota and Montana, the Anadarko Woodford shale in western Oklahoma and the Niobrara shale in Colorado and Wyoming. We expect our cash flows from operations and the availability under our revolving credit facility will be sufficient to meet our capital expenditure needs.
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the three months ended September 30, 2010 were $238.8 million, a 42% increase from sales of $168.4 million for the same period in 2009. Our sales volumes increased 701 MBoe, or 20%, over the same period in 2009 due to the continuing success of our enhanced crude oil recovery and drilling programs. Our realized price per Boe increased $8.73 to $56.92 for the three months ended September 30, 2010 from $48.19 for the three months ended September 30, 2009. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended September 30, 2010 was $8.93 compared to $9.39 for the three months ended September 30, 2009 and $8.29 for the year ended December 31, 2009. Factors contributing to the changing differentials included Canadian crude oil imports and increases in production in the North region, coupled with downstream transportation capacity and seasonal demand fluctuations.
During the three months ended September 30, 2010, we realized gains on natural gas derivatives of $5.7 million and realized gains on crude oil derivatives of $6.7 million. During the three months ended September 30, 2010, we reported an unrealized non-cash mark-to-market gain on natural gas derivatives of $9.6 million and an unrealized non-cash mark-to-market loss on crude oil derivatives of $46.2 million. During the three months ended September 30, 2009, we had no derivative contracts related to our crude oil production and we reported unrealized non-cash mark-to-market losses from our natural gas derivatives of $2.1 million for such period.
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 9% to $24.9 million during the three months ended September 30, 2010 from $22.7 million during the three months ended September 30, 2009 due to higher production volumes. Production expense per Boe decreased to $5.92 for the three months ended September 30, 2010 from $6.50 per Boe for the three months ended September 30, 2009. In the prior year, we leased compressors from a related party for approximately $400,000 per month under an operating lease and a new agreement was negotiated effective February 1, 2010 resulting in the monthly lease fee being reduced to $50,000, lowering production expense per Boe for the 2010 period.
Production taxes and other expenses increased $7.1 million, or 58%, during the three months ended September 30, 2010 compared to the three months ended September 30, 2009 as a result of higher revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses include charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Arkoma Woodford area of $1.1 million and $1.5 million for the three months ended September 30, 2010 and 2009, respectively. Production taxes, excluding other charges, as a percentage of crude oil and natural gas sales, were 7.7% for the three months ended September 30, 2010 compared to 6.7% for the three months ended September 30, 2009. The increase is due to the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, our most active area, which has production tax rates of up to 11.5% of oil revenues. 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 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 production tax rate is expected to increase as incentives we currently receive for horizontal wells reach the end of their incentive period.
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Continental Resrces has a market cap of $8.61 billion; its shares were traded at around $49.99 with a P/E ratio of 34.5 and P/S ratio of 13.7. CLR is in the portfolios of Richard Aster Jr of Meridian Fund, John Keeley of Keeley Fund Management, Steven Cohen of SAC Capital Advisors, Jeremy Grantham of GMO LLC.
Highlight of Business Operations:
For the first nine months of 2010, our crude oil and natural gas production increased to 11,392 MBoe (41,728 Boe per day), up 1,241 MBoe, or 12%, from the first nine months of 2009. The increase in 2010 production was primarily driven by an increase in production from our North Dakota Bakken field and Oklahoma Woodford plays. Our crude oil and natural gas revenues for the first nine months of 2010 increased 66% to $675.4 million due to a 44% increase in commodity prices compared to the same period in 2009. Our realized price per Boe increased $17.90 to $58.82 for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. For the nine month period ended September 30, 2010, we experienced increases in production taxes and other expenses of $22.9 million, a 74% increase compared to the first nine months of 2009, primarily due to an increase in crude oil and natural gas revenues resulting from higher commodity prices and an increase in sales volumes. 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. For the nine months ended September 30, 2010, crude oil sales volumes were 90 MBbls more than crude oil production, and crude oil sales volumes were 196 MBbls less than crude oil production for the same period in 2009. Our cash flows from operating activities for the nine months ended September 30, 2010 were $495.3 million, an increase of $279.3 million from $216.0 million provided by our operating activities during the comparable 2009 period. The increase in operating cash flows was primarily due to increased revenues as a result of higher commodity prices and sales volumes. During the nine months ended September 30, 2010, we invested $866.1 million (including increased accruals for capital expenditures of $115.4 million and $3.1 million of seismic costs) in our capital program concentrating mainly in the Bakken field, the Arkoma Woodford and Anadarko Woodford plays, and the Red River units.In July 2010, our Board of Directors increased our 2010 capital expenditures budget to $1.3 billion to accelerate our drilling program and increase our acreage positions in strategic plays in the United States. Our previous 2010 capital expenditures budget was $850 million. Our revised 2010 capital expenditures budget of $1.3 billion focuses primarily on increased development in the Bakken shale of North Dakota and Montana, the Anadarko Woodford shale in western Oklahoma, and the Niobrara shale in Colorado and Wyoming. In October 2010, our Board of Directors approved a 2011 capital expenditures budget of $1.36 billion, which will continue to focus primarily on increased development in the Bakken shale of North Dakota and Montana, the Anadarko Woodford shale in western Oklahoma and the Niobrara shale in Colorado and Wyoming. We expect our cash flows from operations and the availability under our revolving credit facility will be sufficient to meet our capital expenditure needs.
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the three months ended September 30, 2010 were $238.8 million, a 42% increase from sales of $168.4 million for the same period in 2009. Our sales volumes increased 701 MBoe, or 20%, over the same period in 2009 due to the continuing success of our enhanced crude oil recovery and drilling programs. Our realized price per Boe increased $8.73 to $56.92 for the three months ended September 30, 2010 from $48.19 for the three months ended September 30, 2009. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended September 30, 2010 was $8.93 compared to $9.39 for the three months ended September 30, 2009 and $8.29 for the year ended December 31, 2009. Factors contributing to the changing differentials included Canadian crude oil imports and increases in production in the North region, coupled with downstream transportation capacity and seasonal demand fluctuations.
During the three months ended September 30, 2010, we realized gains on natural gas derivatives of $5.7 million and realized gains on crude oil derivatives of $6.7 million. During the three months ended September 30, 2010, we reported an unrealized non-cash mark-to-market gain on natural gas derivatives of $9.6 million and an unrealized non-cash mark-to-market loss on crude oil derivatives of $46.2 million. During the three months ended September 30, 2009, we had no derivative contracts related to our crude oil production and we reported unrealized non-cash mark-to-market losses from our natural gas derivatives of $2.1 million for such period.
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 9% to $24.9 million during the three months ended September 30, 2010 from $22.7 million during the three months ended September 30, 2009 due to higher production volumes. Production expense per Boe decreased to $5.92 for the three months ended September 30, 2010 from $6.50 per Boe for the three months ended September 30, 2009. In the prior year, we leased compressors from a related party for approximately $400,000 per month under an operating lease and a new agreement was negotiated effective February 1, 2010 resulting in the monthly lease fee being reduced to $50,000, lowering production expense per Boe for the 2010 period.
Production taxes and other expenses increased $7.1 million, or 58%, during the three months ended September 30, 2010 compared to the three months ended September 30, 2009 as a result of higher revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses include charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Arkoma Woodford area of $1.1 million and $1.5 million for the three months ended September 30, 2010 and 2009, respectively. Production taxes, excluding other charges, as a percentage of crude oil and natural gas sales, were 7.7% for the three months ended September 30, 2010 compared to 6.7% for the three months ended September 30, 2009. The increase is due to the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, our most active area, which has production tax rates of up to 11.5% of oil revenues. 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 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 production tax rate is expected to increase as incentives we currently receive for horizontal wells reach the end of their incentive period.
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