Denbury Resources Inc. is a Canadian corp. organized under the Canada Business Corp Act engaged in the acquisition, development, operation and exploration of oil and gas properties primarily in the Gulf Coast region of the U.S. through its wholly-owned subsidiary, Denbury Management, Inc. Denbury's production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, Denbury has not experienced any difficulty in finding a market for all of its product as it becomes available or in transporting its product to these markets. Denbury Resources Inc. has a market cap of $3.37 billion; its shares were traded at around $13.51 with a P/E ratio of 19.6 and P/S ratio of 2.5. Denbury Resources Inc. had an annual average earning growth of 14.9% over the past 10 years. GuruFocus rated Denbury Resources Inc. the business predictability rank of 3-star. Highlight of Business Operations: In addition to the decrease in our third quarter 2009 production due to the Barnett Shale sale, our oil and natural gas revenues were 45% lower in the third quarter of 2009 than in the prior year third quarter, as the average price we received for our production on a per BOE basis was 41% lower in the current year period. Since over 80% of our production is oil, oil prices have a much larger impact on our revenues than natural gas prices. NYMEX oil prices moved from $44.60 per barrel at December 31, 2008 to as low as $34.00 per barrel in mid-February 2009, up to $49.66 per barrel at March 31, 2009, $69.89 per barrel at June 30, 2009 and $70.61 per barrel at September 30, 2009. NYMEX natural gas prices have decreased from year-end 2008, falling from $5.62 per Mcf at December 31, 2008 to $3.78 per Mcf at March 31, 2009, $3.84 per Mcf at June 30, 2009, then recovering slightly, and ending the third quarter 2009 at $4.84 per Mcf.
Subsequent to September 30, 2009, we entered into additional costless collar crude oil commodity derivative contracts to protect our cash flows during 2010 as follows: 5,000 barrels per day during the first quarter of 2010 with a floor price of $70 per barrel and a ceiling price of $92.20 per barrel; 5,000 barrels per day during the second quarter of 2010 with a floor price of $70 per barrel and a ceiling price of $95.25 per barrel; and 5,000 barrels per day during the third and fourth quarters of 2010 with a floor price of $70 per barrel and a ceiling price of $96.50 per barrel. Also, in light of the recently announced acquisition of Encore and our desire to protect our cash flows given the increased debt levels we expect in connection with the acquisition, we recently entered into costless collar crude oil commodity derivative contracts for 25,000 barrels per day during 2011 with a floor price of $70 per barrel and a ceiling price of $102.58 per barrel.
Based on our current cash flow projections using futures prices as of the end of October 2009, and including the expected cash settlements on our 2009 oil derivative contracts, we anticipate that these projected 2009 capital expenditure amounts of approximately $750 million, plus our already closed $201 million Hastings acquisition, could, in the aggregate, exceed projected cash flow by as much as $450 million to $550 million. This shortfall should be covered by the $381.4 million of net proceeds from our February 2009 subordinated debt issuance and the estimated $259.8 million of net proceeds (after closing adjustments and net of $8.1 million for natural gas swaps transferred in the sale) from the sale of 60% of our Barnett Shale properties.
During the first nine months of 2009, we have recorded approximately $833 million of cash used for capital expenditures, which includes $49 million in capitalized interest and $44 million that was subsequently leased in sale leaseback transactions. In addition, our liabilities for capital expenditures were approximately $55 million lower at September 30, 2009 than at December 31, 2008, representing cash outflows related to our capital expenditures actually incurred in 2008. These amounts net together resulting in $685 million of our $750 million capital budget. In addition, we have approximately $55 million of equipment available for sale leaseback financings for the remainder of 2009, which if completed, would leave $120 million of our 2009 capital expenditure budget available for the fourth quarter. If we do not complete the full $55 million of remaining equipment leases in 2009, it is likely that we would carry those over into 2010.
On February 2, 2009, we closed our $201 million purchase of Hastings Field. Under the agreement, we are required to make aggregate net cumulative capital expenditures in this field of approximately $179 million over the next six years cumulating as follows: $26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the required amounts by the due dates, we are required to make a cash payment equal to 10% of the cumulative shortfall at each applicable date. Further, we are committed to injecting at least an average of 50 MMcf/d of CO2 (total of purchased and recycled) in the West Hastings Unit for the 90 day period prior to January 1, 2013. If such injections do not occur, we must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign to Venoco all assets previously purchased for the value of such assets at that time based upon the discounted value of the fields proved reserves using a 20% discount rate, or (2) make an additional payment of $20 million in January 2013, less any payments made for failure to meet the capital spending requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less amounts paid for capital expenditure shortfalls) until the CO2 injection rate in the Hastings Field equals or exceeds the minimum required injection rate.
We spent approximately $0.16 per Mcf to produce our CO2 during the first nine months of 2009, comprised of $0.14 per Mcf during the first quarter of 2009, $0.18 per Mcf during the second quarter of 2009, and $0.19 per Mcf during the third quarter of 2009. This rate is down significantly from $0.25 per Mcf during the first nine months of 2008, due primarily to decreased CO2 royalty expense as a result of lower oil prices (upon which royalties are based) in the first nine months of 2009. Our estimated total cost per thousand cubic feet of CO2 during the first nine months of 2009 was approximately $0.25, after inclusion of depreciation and amortization expense, down from the 2008 first nine months average of $0.33 per Mcf. Our estimated total cost per thousand cubic feet of CO2 during the third quarter of 2009 was approximately $0.27, after inclusion of depreciation and amortization expense.
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