Denbury Resources Inc. (DNR, Financial) filed Annual Report for the period ended 2011-12-31.
Denbury Res Inc has a market cap of $8.19 billion; its shares were traded at around $20.44 with a P/E ratio of 14.5 and P/S ratio of 3.6. Denbury Res Inc had an annual average earning growth of 10.9% over the past 10 years.
Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive. For the years ended December 31, 2011 and December 31, 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (43% and 46% in 2011 and 2010, respectively) and Plains Marketing LP (16% and 14% in 2011 and 2010, respectively). For the year ended December 31, 2009, we had two significant purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (52%) and Hunt Crude Oil Supply Co. (21%).
2011 Operating Highlights. We achieved record net income and cash flows from operations in 2011. We had net income of $573.3 million, or $1.45 per basic common share, during 2011, compared to net income of $271.7 million, or $0.73 per basic common share, during 2010. The increase between the two periods is primarily attributable to a $475.9 million increase in oil and natural gas revenues due to higher oil prices, partially offset by lower production as a result of assets sold in late 2010, and to a lesser extent due to an $87.9 million decrease in costs related to the Encore Merger. These increases to net income between 2010 and 2011 were offset by the absence in 2011 of a $101.5 million gain on the 2010 sale of Genesis Energy, LLC, and to a lesser extent were due to a $16.1 million loss on the early extinguishment of debt in 2011, certain asset impairment charges in 2011 related to our investment in Vanguard common units ($6.3 million), and the abandonment of our investment in certain CO2 properties ($16.6 million). Overall, our total expenses decreased by $57.4 million, from $1.44 billion in 2010 to $1.39 billion in 2011. Our cash flow from operations was $1.2 billion in 2011, compared to $855.8 million in 2010, the increase also primarily due to the increase in oil revenues.
Oil prices during 2011 were considerably higher than prices during 2010, with NYMEX oil prices averaging $95.08 per Bbl in 2011, compared to average NYMEX prices of $79.51 per Bbl in 2010. Oil revenues made up approximately 98% of our oil and natural gas revenues in 2011 as compared to approximately 93% in 2010. Our average price per barrel of oil, excluding the impact of derivative contracts, was $100.03 per barrel in 2011, as compared to $75.97 per barrel in 2010, a 32% increase between the two periods. Oil prices received in 2011 were positively impacted by the favorable price differential for crude oil sold under Louisiana Light Sweet (“LLS”) pricing. See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information.
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at ÂÂ10%), based on unescalated period-end oil and natural gas prices during the first three quarters of 2009; and beginning in the fourth quarter of 2009, the average first-day-of-the-month oil and natural gas price for each month during the 12-month periods ended December 31, 2009, 2010 and 2011; (2) plus the cost of properties not being amortized; (3) plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; (4) less related income tax effects. Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor for those related to the cost of constructing CO2 pipelines, as those costs have already been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of the Company s capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.
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Denbury Res Inc has a market cap of $8.19 billion; its shares were traded at around $20.44 with a P/E ratio of 14.5 and P/S ratio of 3.6. Denbury Res Inc had an annual average earning growth of 10.9% over the past 10 years.
Highlight of Business Operations:
Phase 8 (Oyster Bayou). Phase 8, which we acquired in 2007, consists of two fields located in southeast Texas on the east side of Galveston Bay. The Oyster Bayou and Fig Ridge Fields are located in close proximity to each other. We acquired a majority interest in Oyster Bayou Field and a relatively small interest in Fig Ridge Field. Oyster Bayou Field was unitized in the spring of 2010 and we began CO2 injections there in June 2010. Oyster Bayou Field is somewhat unique when compared to our other CO2 EOR projects because the field covers a relatively small area of 3,912 acres and will be developed in essentially one stage. We commenced production from Oyster Bayou Field in December 2011, with the first oil sales occurring at the end of that month. We expect to book initial proved tertiary reserves for the field by the end of 2012. In 2012, we expect to invest $35 million to complete several patterns and expand facilities in Oyster Bayou Field.Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive. For the years ended December 31, 2011 and December 31, 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (43% and 46% in 2011 and 2010, respectively) and Plains Marketing LP (16% and 14% in 2011 and 2010, respectively). For the year ended December 31, 2009, we had two significant purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (52%) and Hunt Crude Oil Supply Co. (21%).
2011 Operating Highlights. We achieved record net income and cash flows from operations in 2011. We had net income of $573.3 million, or $1.45 per basic common share, during 2011, compared to net income of $271.7 million, or $0.73 per basic common share, during 2010. The increase between the two periods is primarily attributable to a $475.9 million increase in oil and natural gas revenues due to higher oil prices, partially offset by lower production as a result of assets sold in late 2010, and to a lesser extent due to an $87.9 million decrease in costs related to the Encore Merger. These increases to net income between 2010 and 2011 were offset by the absence in 2011 of a $101.5 million gain on the 2010 sale of Genesis Energy, LLC, and to a lesser extent were due to a $16.1 million loss on the early extinguishment of debt in 2011, certain asset impairment charges in 2011 related to our investment in Vanguard common units ($6.3 million), and the abandonment of our investment in certain CO2 properties ($16.6 million). Overall, our total expenses decreased by $57.4 million, from $1.44 billion in 2010 to $1.39 billion in 2011. Our cash flow from operations was $1.2 billion in 2011, compared to $855.8 million in 2010, the increase also primarily due to the increase in oil revenues.
Oil prices during 2011 were considerably higher than prices during 2010, with NYMEX oil prices averaging $95.08 per Bbl in 2011, compared to average NYMEX prices of $79.51 per Bbl in 2010. Oil revenues made up approximately 98% of our oil and natural gas revenues in 2011 as compared to approximately 93% in 2010. Our average price per barrel of oil, excluding the impact of derivative contracts, was $100.03 per barrel in 2011, as compared to $75.97 per barrel in 2010, a 32% increase between the two periods. Oil prices received in 2011 were positively impacted by the favorable price differential for crude oil sold under Louisiana Light Sweet (“LLS”) pricing. See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information.
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at ÂÂ10%), based on unescalated period-end oil and natural gas prices during the first three quarters of 2009; and beginning in the fourth quarter of 2009, the average first-day-of-the-month oil and natural gas price for each month during the 12-month periods ended December 31, 2009, 2010 and 2011; (2) plus the cost of properties not being amortized; (3) plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; (4) less related income tax effects. Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor for those related to the cost of constructing CO2 pipelines, as those costs have already been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of the Company s capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.
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