The Company also announced that its proved carbon dioxide ("CO2") reserves were 5.5 Tcf at year-end 2006, a 19% increase over its proved CO2 reserve quantities at December 31, 2005. The independent reservoir engineering firm of DeGolyer and MacNaughton prepared Denbury's year-end reserve report, including its proved CO2 reserve quantities, for the seventh consecutive year.
Proved Reserve and Analysis
Denbury added 35.0 MMBOE of proved reserves during 2006 (before netting out 2006 production) replacing over 260% of its 2006 estimated production, approximately 40% from acquisitions and 60% from internal organic growth. The most significant reserve additions during 2006 were in the Barnett Shale area near Fort Worth, Texas, where the Company added approximately 106 Bcfe (17.7 MMBOE) before netting out 2006 production. The incremental Tcf of proven CO2 reserves added during 2006 (before netting out 2006 CO2 production) replaced over 800% of the Company's 2006 estimated CO2 production.
The Company added approximately 6.1 MMBbls of tertiary-related oil reserves during the year, primarily at McComb Field through further expansion there and at Mallalieu Field where the Company increased its expected recovery rate from 17% to 20% of originally estimated reserves in place at that field, based on the oil production response to date. The Company did not add substantial additional tertiary oil reserves during 2006 as only two new significant tertiary floods that did not already have proved reserves, Soso and Martinville Fields, were initiated during the year. Tertiary floods in both of these fields were completed so late in the year that there was not a significant production response before year-end (the requirement to book proved reserves in these fields). Generally, 2006 was a transition year for the Company with regard to its tertiary oil reserves. Previously, the Company booked proved tertiary oil reserves near the start of a tertiary project as almost all the oil fields in Southwest Mississippi were analogous to Little Creek (an already-producing substantial tertiary flood) and thus it was not necessary to have an oil production response to the CO2 injections before the reserves in those fields were considered proven. Conversely, the Company's new floods (beyond Phase I) are generally not analogous, as the tertiary floods there will be in different geological formations. Therefore for these new phases, there must be an oil production response to the CO2 injections before the Company can recognize proven oil reserves in those fields, even though the Company believes that there is a similar risk profile in flooding those fields. Since many of the Company's Phase II projects were delayed during 2006 as previously discussed in the Company's prior releases, the required production response needed to record any significant incremental tertiary oil reserves in this new phase did not occur. The Company anticipates booking significant amounts of incremental proven tertiary oil reserves during 2007 and beyond, although the magnitude of those additional reserves will depend on the Company's progress with Phases III and IV, two areas the Company plans to initiate during 2007.
Current preliminary estimates of 2006 capital spending include approximately $470 million for oil and natural gas development and exploration activities, approximately $320 million expended on acquisitions, and approximately $60 million spent on Denbury's CO2 producing wells and facilities. These capital expenditures include approximately $250 million incurred on unproved properties, primarily related to the portion of acquisition expenditures allocated to future tertiary floods and to capital expenditures on new tertiary properties for which there were not proven reserves as of December 31, 2006. The Company anticipates that proved reserves associated with these unproved properties will be recognized over the next few years. In addition, the Company spent $37.5 million in 2006 as partial payment for an option to acquire Hastings Field, which is not included in the preceding capital expenditure amounts.
Based on these preliminary 2006 capital expenditure estimates, excluding the CO2 source related expenditures and without taking into account the change in future development cost and retirement obligations, Denbury estimates its finding and development costs for 2006 to be $22.55 per BOE. After adjusting for the $250 million expended on unproved projects, this estimate of 2006 finding costs decreases to approximately $15.41 per BOE. Approximately 65% of Denbury's year-end 2006 proved reserves are categorized as proved developed and approximately 72% are oil reserves.
During 2006, the Company increased its proved CO2 reserves from 4.6 Tcf at December 31, 2005 to 5.5 Tcf at December 31, 2006 (both volumes on a working interest basis), a 19% increase. Virtually all of this increase was attributable to additional reserves at DRI Ice Field, a field initially discovered late in 2005.
In accordance with SEC requirements, Denbury's proved reserves at December 31, 2006 were computed using unescalated year-end 2006 commodity prices of $61.05 per Bbl of oil (based on NYMEX prices) and a Henry Hub cash price of $5.63 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, 2006. The average price net to Denbury, contained in the reserve report, is approximately $53.16 per Bbl of oil and liquids and $5.02 per Mcf of natural gas. Using these prices, the estimated discounted net present value of Denbury's proved reserves, before projected income taxes, at December 31, 2006, using a 10% per annum discount rate ("PV-10 Value") was $2.65 billion, approximately 18% lower than the Company's PV-10 Value of $3.22 billion a year earlier. This decrease is primarily due to the significant drop in natural gas prices between the respective year-ends and higher operating and capital costs at year-end 2006. The Company estimates that the decrease in PV-10 Value attributable to increased operating expenses, which in turn primarily resulted from industry inflation since 2005, is approximately $160 million. 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, 2005 were computed using unescalated NYMEX commodity prices of $61.04 per Bbl of oil (virtually identical to year-end 2006 oil prices) and $10.08 per MMBtu of natural gas (79% higher than year-end 2006 natural gas prices). The Company estimates that the PV-10 Value at December 31, 2006 would change by approximately $61 million for each dollar change in the oil price per Bbl and approximately $14 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.
Following is a preliminary reconciliation of the Company's proved reserve quantities between December 31, 2005 and December 31, 2006:
MMBOE ------------- Balance at 12/31/2005 152.6 Acquisitions 14.3 Extensions, discoveries, enhanced recoveries, and other revisions 20.7 Estimated 2006 production (13.4) ------------- Balance at 12/31/2006 174.2 =============
The Company anticipates that its average daily production rate for the fourth quarter of 2006 will be between 36,250 BOE/d and 36,750 BOE/d, resulting in an average annual production rate for 2006 of between 36,500 BOE/d and 37,000 BOE/d. Preliminary production figures for January 2007 indicate that the Company's net tertiary oil production for the month averaged in excess of 11,000 BOE/d, approximately 9% higher than the third quarter 2006 production level of 10,114 BOE/d (the fourth quarter 2006 rate is expected to be about the same as the third quarter rate). Modest production increases have occurred at all of the Phase I fields except for Little Creek, the Company's oldest tertiary field purchased in 1999 which is on a gradual decline. In addition, response continues to improve at Eucutta and Martinville Fields, two of the three new floods in Phase II, with initial production response expected at Soso Field, the third Phase II property, in the second quarter of 2007. The Company has begun to inject CO2 at Tinsley Field (Phase III) although in very modest amounts, using a small existing pipeline. Development at this field will accelerate once the new CO2 pipeline to that field is installed, with completion currently expected late in the third quarter of 2007.
CO2 production is continuing to increase and is expected to average between 450 MMcf/d and 500 MMcf/d in the first quarter of 2007, a significant increase from the 2006 estimated average rate of 341 MMcf/d. The increase has been a result of the recent completion of the Barksdale dehydration facility and connection of two new wells, with another well in the process of being completed and another well currently drilling. The Company expects production to continue to increase above 500 MMcf/d by the second quarter, making Denbury the largest known producer of CO2 (net to any one entity) in the country.
The Company has initiated studies to select a route for its proposed 280 to 300 mile CO2 pipeline from Louisiana to Hastings Field, near Houston, Texas, with completion currently expected during 2009. Work to secure right-of-ways for the CO2 pipeline from Tinsley Field to Delhi Field is ongoing, with that line currently expected to be completed during the second quarter of 2008.
Production is still increasing in the Barnett Shale area, averaging approximately 37 MMcfe/d (net) during January 2007, as compared to approximately 30 MMcfe/d in the third quarter of 2006. The Company currently has three rigs running in that area, all in Parker County, and expects to drill 35 to 40 wells during 2007.
The Company's second Gumbo well is still drilling with total depth expected to be reached in the next 30 to 60 days.
Gareth Roberts, Chief Executive Officer, said: "Our tertiary operations continue to expand as we pursue our core strategy. Recently, we have seen production responses from two of our new East Mississippi floods, Martinville and Eucutta Fields, and our tertiary related oil production has resumed its incline at most of our previously existing tertiary floods. The key to this improvement is a continued expansion of our CO2 production, which is currently at our highest rates to date of approximately 450 MMcf/d. We are in the process of completing an additional well at Jackson Dome, with another well expected to reach total depth by the end of the first quarter, both of which should further increase our CO2 production capacity. While there is always a delay between CO2 injections and oil production, we are encouraged as it all starts with the CO2 injections.
"The addition of an additional Tcf of proven CO2 reserves during 2006 is a significant milestone in our business plan. With these incremental reserves, we have enough proven CO2 resources for our Hastings project near Houston, Texas, with about 250 Bcf left over for additional potential projects. In addition to the estimated 70 MMBbls of potential oil recoverable with tertiary operations at Hastings Field (the mid-point of our range of estimates of potential recoverable oil of 50 MMBbls to 90 MMBbls), our new currently unallocated proved CO2 reserves give us the ability to acquire additional oil fields and recover an estimated 20 MMBbls of additional potential oil reserves through tertiary operations (using our rough internal standard of 10 Mcf of CO2 required for one barrel of oil). We expect to further increase our CO2 proved reserves and production rates over the next several years by continuing our CO2 drilling program.
"Even though we have had a recent pullback in commodity prices, our future continues to look bright. We are continuing our expansion plans in the Texas Gulf Coast area by seeking a route for our planned new CO2 pipeline to that area. We hope to take advantage of lower oil prices to acquire additional future tertiary flood candidates during this year. We believe that the rate of inflation in our costs should be reduced by lower commodity prices, but that could quickly change again if commodity prices resume their ascent. We have a large inventory of opportunities and continue to accumulate more and more, putting us in an enviable position amongst our industry peer group. Our future continues to look bright."
Denbury Resources Inc. is a growing independent oil and gas company. The Company is the largest oil and natural gas operator in Mississippi, owns the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and holds key operating acreage in the onshore Louisiana and Texas Barnett Shale areas.
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