Denbury announced that its total proved oil and natural gas reserves as of December 31, 2008 were 250.4 million barrels of oil equivalent (“MMBOE”), consisting of 179.0 million barrels (“MMBbls”) of crude oil, condensate and natural gas liquids and 428.0 billion cubic feet (“Bcf”) (71.3 MMBOE) of natural gas.
This year-end proved reserve quantity represents a 29% increase over Denbury's year-end proved reserve quantity estimates a year earlier (194.7 MMBOE at year-end 2007), in spite of an estimated 13.8 MMBOE (approximately 6% of year-end 2008 quantities) that were excluded as a result of the lower commodity prices at year-end 2008. Most of these excluded reserves were unrelated to the Company's tertiary operations. The Company also announced that its proved carbon dioxide (“CO2”) reserves were 5.6 trillion cubic feet ("Tcf") at year-end 2008, approximately the same as its proved CO2 reserve quantities at December 31, 2007 as the Company's incremental CO2 reserves added during 2008 were offset by 2008 CO2 production. The independent reservoir engineering firm of DeGolyer and MacNaughton prepared Denbury's year-end reserve report, including its proved CO2 reserve quantities, for the eighth consecutive year. Approximately 50% of Denbury's year-end 2008 proved reserve quantities are proved tertiary oil reserves, approximately 72% are oil reserves, and approximately 58% are categorized as proved developed.
Proved Reserve and Analysis
Denbury added 89.0 MMBOE of proved reserves during 2008 (before netting out 2008 production, property sales and reserve revisions due to lower commodity prices) replacing approximately 525% of its currently estimated 2008 production, virtually all from internal organic growth. The most significant reserve additions during 2008 were approximately 63.3 MMBbls added in the Company's tertiary oil operations and approximately 117 Bcfe (19.5 MMBOE) in the Barnett Shale area near Fort Worth, Texas, both before netting out 2008 production. The Company's tertiary-related oil reserves added during the year were primarily at Tinsley (34.8 MMBOE), Heidelberg (22.4 MMBOE) and Lockhart Crossing Fields (4.0 MMBOE), in Phases III, II and I, respectively. Based on the fourth quarter 2008 production level, the Company's tertiary oil reserves have a 15.7 R/P ratio (reserve life in years based on current production levels). The Company sold approximately 2.5 MMBOE of proved reserves during 2008 (based on December 31, 2007 reserve quantities) related to the last portion of its Louisiana natural gas properties.
Preliminary unaudited estimates of 2008 capital spending include approximately $590 million for oil and natural gas development and exploration activities, approximately $460 million spent on Denbury's CO2 producing wells, pipelines and facilities, and approximately $31 million expended on acquisitions. The Company received approximately $59 million in net proceeds from the sale of properties during 2008, primarily related to the closing of the remaining portion of the Company's sale of its Louisiana natural gas properties, the majority of which were sold in late 2007. These capital expenditures include approximately $180 million incurred on unproved properties, primarily related to capital expenditures on new tertiary properties for which there were no proven reserves as of December 31, 2008. As part of the initial recognition of proved tertiary reserves at Tinsley, Heidelberg and Lockhart Crossing, the Company moved significant amounts of previously unevaluated costs to its full cost pool. The preliminary estimated net change in the Company's unevaluated properties for 2008 is a net decrease of approximately $120 million.
Based on these preliminary and unaudited 2008 estimates, 2008 finding costs, including the net change in future development cost for proved reserves, are currently estimated to be $12.07 per BOE (see reconciliation below). Using the more common "short-cut" method of computing finding cost which excludes the changes in future development costs and unevaluated properties, the Company's 2008 finding costs would be estimated at less than $7.00 per BOE.
The Company's proved CO2 reserves remained at approximately 5.6 Tcf at December 31, 2008 (on a working interest basis), as the Company's incremental reserves added were generally offset by the estimated 233 Bcf of CO2 produced during the year. During 2008, the Company's estimated CO2 production capacity grew from approximately 700 MMcf/d at year-end 2007 to between 900 MMcf/d and 1 Bcf/d at year-end 2008.
In accordance with Securities and Exchange Commission ("SEC") requirements, Denbury's proved reserves at December 31, 2008 were computed using unescalated year-end 2008 commodity prices of $44.60 per Bbl of oil (based on NYMEX prices) and a Henry Hub cash price of $5.71 per MMBtu of natural gas, with necessary adjustments applied to each field to arrive at the net price received by the Company as of December 31, 2008.
The average price net to Denbury, contained in the reserve report, is approximately $40.87 per Bbl of oil, $21.59 per Bbl of natural gas liquids, and $4.92 per MMBtu of natural gas. Using these prices, the estimated discounted net present value of Denbury’s proved reserves, before projected income taxes, using a 10% per annum discount rate (“PV-10 Value”) was $1.9 billion at December 31, 2008, as compared to a PV-10 Value of $5.4 billion a year earlier.
This decrease is primarily due to the 54% reduction in oil prices and 17% reduction in natural gas prices between the respective year-ends, partially offset by incremental reserves added during 2008. PV-10 Value is different than the standardized measure of discounted estimated future net cash flows, which is an after-tax calculation. Proved reserves at December 31, 2007 were computed using unescalated NYMEX commodity prices of $95.98 per Bbl of oil and a Henry Hub cash price of $6.80 per MMBtu of natural gas.
The Company estimates that the PV-10 Value at December 31, 2008 would change by approximately $80 million for each dollar change in the oil price per Bbl and approximately $15 million for each $0.10 change in the natural gas price per Mcf, if the oil and natural gas prices were to change by relatively minor amounts. If oil and/or natural prices were to change significantly, it is likely that the NYMEX differentials and cost assumptions used in estimating the proved reserves would also need to be adjusted.
Based on preliminary unaudited data, the Company’s average daily production rate for the fourth quarter of 2008 is approximately 48,235 BOE/d, a 5% sequential increase over the third quarter of 2008 average of 45,913 BOE/d. This results in an average annual production rate for 2008 of approximately 46,340 BOE/d. The Company's preliminary fourth quarter production rate for its tertiary oil production is approximately 21,870 Bbls/d, a 10% sequential increase over the third quarter of 2008 average of 19,784 Bbls/d. The Company anticipates that it will have a $240 million non-cash fair value pre-tax gain on the Company's derivative commodity contracts during the fourth quarter, partially offset by an anticipated full cost pool ceiling test writedown which is currently expected to be less than $150 million. The benefit of these hedges will not be included in the ceiling test calculation as the Company utilizes mark-to-market accounting (vs. hedge accounting) for its derivative contracts.
Gareth Roberts, Chief Executive Officer, said, "We are very pleased to have a 29% increase in our proved reserves despite the fact that oil prices have dropped more than 50% since last year-end. We estimate that our break-even cost on our tertiary oil projects at today's oil price is in the mid-twenties with a cash break-even in the upper teens. Therefore, all of our tertiary projects were economic at year-end commodity prices and we had very few reserve revisions in our tertiary operations due to lower oil prices. We have seen some savings in our operating and capital costs to date, but we are focusing on further reducing our costs in this lower price environment."
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