We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our Internet website, www.denbury.com , as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
The Company
Denbury Resources Inc. is a Delaware corporation organized under Delaware General Corporation Law (DGCL) and is engaged in the acquisition, development, operation and exploration of oil and natural gas properties in the Gulf Coast region of the United States, primarily in Louisiana, Mississippi, Alabama, and Texas. Our corporate headquarters is located at 5100 Tennyson Parkway, Suite 1200, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2006, we had 596 employees, 390 of whom were employed in field operations or at the field offices. Our employee count does not include the approximately 190 employees of Genesis Energy, Inc. as of December 31, 2006, as its employees exclusively carry out the business activities of Genesis Energy, L.P., which we do not consolidate in our financial statements (see Note 1 to the Consolidated Financial Statements).
Incorporation and Organization
Denbury was originally incorporated in Canada in 1951. In 1992, we acquired all of the shares of a United States operating company, Denbury Management, Inc. (DMI), and subsequent to the merger we sold all of its Canadian assets. Since that time, all of our operations have been in the United States.
In April 1999, our stockholders approved a move of our corporate domicile from Canada to the United States as a Delaware corporation. Along with the move, our wholly owned subsidiary, DMI, was merged into the new Delaware parent company, Denbury Resources Inc. This move of domicile did not have any effect on our operations or assets.
Effective December 29, 2003, Denbury Resources Inc. changed its corporate structure to a holding company format. As part of this restructure, Denbury Resources Inc. (predecessor entity) merged into a newly formed limited liability company, and survived as Denbury Onshore, LLC, a Delaware limited liability company and an indirect subsidiary of the newly formed holding company, Denbury Holdings, Inc. Denbury Holdings, Inc. subsequently assumed the name Denbury Resources Inc. (new entity). Stockholders’ ownership interests in the business did not change as a result of the new structure and shares of the Company remain publicly traded under the same symbol (DNR) on the New York Stock Exchange.
Business Strategy
As part of our corporate strategy, we believe in the following fundamental principles:
| • | remain focused in specific regions; | ||
| • | acquire properties where we believe additional value can be created through a combination of exploitation, development, exploration and marketing, including secondary and tertiary operations; | ||
| • | acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it; | ||
| • | maximize the value of our properties by increasing production and reserves while reducing cost; and | ||
| • | maintain a highly competitive team of experienced and incentivized personnel. |
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Acquisitions
Information as to recent acquisitions and divestitures by Denbury is set forth under Note 2, “Acquisitions and Divestitures,” to the Consolidated Financial Statements.
Oil and Gas Operations
Our CO 2 Assets
During 2006, we concentrated on implementing new tertiary floods in our Phase II fields, Eucutta, Soso and Martinville Fields, while continuing to develop our Phase I fields Little Creek, Mallalieu, McComb and Brookhaven. We increased our potential tertiary flood candidates during 2006 with the acquisition of Tinsley Field (Phase III) and Delhi Field (Phase V), and an option to purchase Hastings Field, adding to our inventory of future tertiary floods. Our tertiary operations are our principal focus and our core assets. During the last seven years, we have learned a considerable amount about tertiary operations and working with carbon dioxide (“CO 2 ”) and our knowledge continues to grow. We like these tertiary operations because (i) CO 2 investments provide a reasonable rate of return, even at relatively low oil prices, (ii) tertiary flooding exhibits a lower risk profile, and (iii) to date, in our region of the United States, we have not encountered any industry competition. Generally, from the Texas Gulf Coast to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO 2 are the foundation for our entire tertiary program.
CO 2 is one of the most efficient tertiary recovery mechanisms for crude oil. The CO 2 acts somewhat like a solvent for the oil, removing it from the oil bearing formation as the CO 2 passes through the rock. CO 2 tertiary floods are unique because they require large volumes of CO 2 , which to our knowledge is limited to a few geological basins, one of which is our source near Jackson, Mississippi. Further, the most efficient way to transport CO 2 is via dedicated pipelines, which are also in limited supply. Because the sources and methods of transportation of CO 2 are limited, only 3% or 250,000 Bbls/d of the United States domestic oil production is derived from tertiary recovery projects.
Our CO 2 source field, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s while being explored for hydrocarbons. This significant source of CO 2 is the only known one of its kind in the United States east of the Mississippi River. Mississippi’s first enhanced oil recovery project began in the mid 1980s in Little Creek Field following the installation of Shell Oil Company’s Choctaw CO 2 Pipeline. The 183-mile Choctaw Pipeline (now referred to as NEJD pipeline) transported CO 2 produced from Jackson Dome to Little Creek Field. While the CO 2 flood initially proved to be successful in recovering significant amounts of oil, commodity prices at that time made the projects unattractive for Shell and they later sold their oil fields in this area, as well as the CO 2 source wells and pipeline.
While enhanced oil recovery (EOR) projects utilizing CO 2 may not be considered a new technology, Denbury applies several additional technologies to the fields: well evaluations, new completion or stimulation techniques, operating equipment and seismic interpretations. We began our CO 2 operations in August 1999, when we acquired Little Creek Field in Mississippi, followed by our acquisition of Jackson Dome in 2001. Based upon our success at Little Creek we embarked upon a strategic program to improve our understanding and knowledge of CO 2 production and tertiary recovery to build a dominant position in this niche play.
We talk about our tertiary operations by labeling operating areas or groups of fields as phases. Phase I is in Southwest Mississippi and includes several fields along our 183-mile CO 2 pipeline that we acquired in 2001. The most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which we just started with the 2006 completion of our CO 2 pipeline to East Mississippi, includes Eucutta, Soso, Martinville and later, Heidelberg Fields. With the properties acquired in our January 2006 acquisition, we have labeled the planned operations at Tinsley Field, Northwest of Jackson Dome, as Phase III. Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi/ Louisiana border acquired in 2005 and which are located west of the Phase I fields. Phase V is Delhi Field, a Louisiana field we acquired in May 2006. We also plan to ultimately flood Citronelle Field, another field acquired in 2006, and Hastings Field, a field on which we recently acquired a purchase option. We have not yet labeled these two fields as a specific phase.
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Jackson Dome. In February 2001, we acquired approximately 800 Bcf of proved producing CO 2 reserves for $42.0 million, a purchase that gave us control of most of the CO 2 supply in Mississippi, as well as ownership and control of a critical 183-mile CO 2 pipeline. This acquisition provided the platform to significantly expand our CO 2 tertiary recovery operations by assuring that CO 2 would be available to us on a reliable basis and at a reasonable and predictable cost. Since February 2001, we have acquired two additional wells and drilled 11 additional CO 2 producing wells, significantly increasing our estimated proved CO 2 reserves to approximately 5.5 Tcf as of December 31, 2006, which is more than enough for our existing and currently planned phases of operations. The estimate of 5.5 Tcf of proved CO 2 reserves is based on 100% ownership of the CO 2 reserves, of which Denbury’s net ownership (net revenue interest) is approximately 4.5 Tcf and is included in the evaluation of proven CO 2 reserves prepared by DeGolyer & MacNaughton. In discussing our available CO 2 reserves, we make reference to the gross amount of proved reserves, as this is the amount that is available both for Denbury’s tertiary recovery programs and for industrial users who are customers of Denbury and others, as Denbury is responsible for distributing the entire CO 2 production stream for both of these uses. Today, we own every producing CO 2 well in the region. Although our current proven and potential CO 2 reserves are quite large, in order to continue our tertiary development of oil fields in the area, incremental deliverability of CO 2 is needed. In order to obtain additional CO 2 deliverability, we plan to drill several additional CO 2 wells in the future, including up to three additional wells during 2007.
During the fourth quarter of 2006, we produced an average of 394 MMcf/d of CO 2 . We sold an average of 78 MMcf/d of CO 2 to commercial users and we used an average of 316 MMcf/d for our tertiary activities. We estimate that our current daily CO 2 deliverability is around 470 MMcf/d. By year-end 2007, we estimate that our planned tertiary operations will require between 650 and 700 MMcf/d, but with our planned 2007 Jackson Dome projects, we expect to increase our CO 2 deliverability to between 700 MMcf/d and 800 MMcf/d by that time. Our geoscientists are using a 100 square mile 3-D seismic survey to locate additional structures that are expected to contain CO 2 . We plan to continue our CO 2 drilling activity in 2007 and beyond, as our CO 2 deliverability needs will continue to grow as we expand our planned tertiary projects.
Man-made CO 2 sources . We entered into an agreement and committed to purchase (if the plant is built) 100% of the CO 2 production from a man-made (anthropogenic) source of CO 2 , a planned petroleum coke gasification project scheduled to be completed in 2010. This Faustina plant, proposed to be located near Donaldsonville, Louisiana, will convert petroleum coke into ammonia. As a byproduct of the combustion, large quantities of CO 2 will be produced, estimated to be around 200 MMcf/d. We plan to use this CO 2 in our tertiary operations to recover oil that may otherwise not be produced. In addition, our use of this CO 2 will also eliminate the release of this greenhouse gas into the earth’s atmosphere. The Faustina agreement allows us to add the potential equivalent volume of an additional one Tcf of CO 2 over the term of our contract. Construction of this plant has not yet begun, so we are not certain whether this plant will be built, although it appears likely. We are in discussions with several other entities that are considering other types of coal or petroleum coke gasification plants. These plants may convert petroleum coke or coal into a variety of products including ammonia, methanol, synthetic diesel fuel, or electrical power generation. The cost of this man-made CO 2 will likely be higher than CO 2 from our natural source, but the location of these plants could mitigate some of the incremental cost of transportation. Further, we see these sources as a possible expansion of our natural Jackson Dome source, assuming they are economical, and we believe that our potential ability to tie these sources together with pipelines will give us a significant advantage over our competitors in our geographic area in acquiring additional oil fields and future potential man-made sources of CO 2.
CO 2 pipelines. We acquired the NEJD 183-mile CO 2 pipeline that runs from Jackson Dome to near Donaldsville, Louisiana as part of the 2001 acquisition (see above). During the first quarter of 2006, we completed the 20”, 86-mile Free State Pipeline, which we are initially using to transport CO 2 to our three new Phase II fields in East Mississippi (Eucutta, Soso, and Martinville). Completion of this line was a significant accomplishment for our team and expands our CO 2 tertiary recovery technology to many potentially significant reservoirs in the eastern part of the state.
During 2006, we reached agreement with Southern Natural Gas Company to acquire a natural gas pipeline that runs from Gwinville Field to near Lake St. John Field in Louisiana. This pipeline crosses our existing NEJD 20” CO 2 pipeline in Southwest Mississippi, and once converted to CO 2 service, will allow us to transport CO 2 from the NEJD pipeline to Lake St. John and Cranfield Fields, both acquired in 2005 (our planned Phase IV). We are in the process of building a small replacement natural gas pipeline to service certain communities currently supplied by
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the acquired line, after which we can convert the acquired natural gas line to CO 2 service. We expect to have this completed by the fourth quarter of 2007.
The 2006 acquisition of Tinsley Field included an eight-inch pipeline, previously being used for natural gas sales and storage, from our Jackson Dome area to the field. We converted the natural gas line to a CO 2 pipeline and in early 2007 began using it to transport CO 2 to Tinsley Field, albeit in limited volumes. During 2007, we plan to construct a 24”, 31 mile line from Jackson Dome to Tinsley Field, with completion anticipated in the third or fourth quarter of 2007. We plan to further extend this line by building a 68 mile 20” extension from Tinsley Field to Delhi Field with completion for this segment anticipated during the first half of 2008.
In late 2006, we purchased an option to acquire Hasting Field, a potential tertiary flood located near Houston, Texas. We plan to build a pipeline to transport CO 2 to this field from the southern end of our existing CO 2 pipeline that terminates near Donaldsonville, Louisiana, estimated at between 280 and 300 miles. Based on very preliminary estimates, this pipeline is expected to cost between $450 million and $650 million, although this cost could vary significantly depending on the ultimate size of the pipeline, its pressure rating, its specific route, and other variables, all of which are unknown at this time. We are initiating studies related to construction of this line, with a goal of having it installed and operational during 2009. We anticipate initially transporting CO 2 from our natural source at Jackson Dome, but ultimately plan to use man-made (anthropogenic) sources of CO 2 for this tertiary operation.
Overall economics. Initially, our tertiary operations were economic at oil prices below $20 per Bbl, although the economics have always varied by field. Our costs have escalated during the last few years due to general cost inflation in the industry, raising our current economic oil price to around $30 per Bbl, again dependent on the specific field. Our inception to date finding and development costs (including future development and abandonment costs but excluding expenditures on fields without proven reserves) for our tertiary oil fields through December 31, 2006, was approximately $8.50 per BOE. Currently, we forecast that these costs will range from $5 to $10 per BOE over the life of each field, depending on the state of a particular field at the time we begin operations, the amount of potential oil, the proximity to a pipeline or other facilities, etc. Our operating costs for tertiary operations are expected to range from $13 to $15 per BOE over the life of each field (at today’s prices), again depending on the field itself.
Oil quality is another significant factor that impacts the economics. In Phase I (Southwest Mississippi), the light sweet oil produced from our tertiary operations receives near NYMEX prices, while the average discount to NYMEX for the lower quality oil produced from the fields in Phase II (East Mississippi), some of which we started flooding during 2006, was $13.51 per BOE during 2006, a differential that is significantly higher than our historical corporate averages and one that appears to increase as oil prices increase.
While these economic factors have wide ranges, our rate of return from these operations has generally been better than the rate of return on our traditional oil and gas operations and entail less risk, and thus our tertiary operations have become our single most important focus area. While it is extremely difficult to accurately forecast future production, we do believe that our tertiary recovery operations provide significant long-term production and reserve growth potential at reasonable rates of return, with relatively low risk, and thus will be the backbone of our Company’s growth for the foreseeable future. Although we believe that our plans and projections are reasonable and achievable, there could be delays or unforeseen problems in the future that could delay or affect the economics of our overall tertiary development program. We believe that such delays or price effects, if any, should only be temporary.
Tentatively, we plan to spend approximately $70 million in 2007 in the Jackson Dome area with the intent to add additional CO 2 reserves and deliverability for future operations. Approximately $60 million in capital expenditures is budgeted in 2007 for our Phase II properties (East Mississippi) and approximately $200 million for Phase III properties (Tinsley), plus an additional $70 million for properties in other phases, making our combined CO 2 related expenditures just over 60% of our $650 million 2007 capital budget.
Our Tertiary Oil Fields with Proven Tertiary Reserves
At December 31, 2006, we had total tertiary-related proved oil reserves of approximately 62.2 MMBbls, consisting of 3.7 MMBbls at Little Creek Field (and surrounding smaller fields), 13.6 MMBbls at Mallalieu Field, 12.7 MMBbls at McComb Field, 19.0 MMBbls at Brookhaven Field, 2.7 MMBbls at Smithdale Field, 10.3 MMBbls at Eucutta Field and 0.2 MMBbls at Martinville Field. Overall, our production from tertiary operations has
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increased from approximately 1,350 Bbls/d in 1999, the then existing production at Little Creek Field at the time of acquisition, to an average of 10,028 Bbls/d during the fourth quarter of 2006. We expect this production to continue to increase for several years as we expand our tertiary operations to additional fields.
With regard to our proven tertiary reserves, 2006 was a transition year for us, as we added only 6.0 MMBbls of tertiary-related proved oil reserves during the year, primarily incremental oil reserves at McComb and Mallalieu Fields (both Phase I). Previously, we booked most proven tertiary oil reserves near the start of a project as almost all the oil fields in Phase I were analogous to Little Creek Field (our first flood) and thus it was not necessary to have an oil production response to the CO 2 injections before they were considered proven. Conversely, our new floods (after Phase I) are not analogous (for the most part), as the tertiary floods will be in different geological formations. Therefore, for these new phases, there must be an oil production response to the CO 2 injections before we can recognize proven oil reserves, even though we believe that these formations have a similar risk profile. Since many of our Phase II projects were delayed during 2006, the production response needed to record any significant incremental tertiary oil reserves in this new area was delayed. We anticipate booking significant amounts of proven tertiary oil reserves during 2007 and beyond, although the magnitude will depend on our progress with Phases III and IV, two areas we plan to initiate development of during 2007, and the response from our new Phase II projects.
Mallalieu Field. The Mallalieu Field consists of two fields, West Mallalieu and the smaller East Mallalieu fields. Combined they are our most prolific tertiary flood, producing in excess of 4,994 Bbls/d for the fourth quarter 2006. In contrast to many of our existing fields, West Mallalieu Field was not waterflooded prior to CO 2 injection. Therefore, we believe that the tertiary recovery of oil from West Mallalieu Field as a result of CO 2 injection could approach 25% of the original oil in place. During 2006, we increased our proved reserves in this area, raising our estimated recovery factor from 17% to 20% for these fields, based on production performance to date. A total of $27.6 million was invested in this field during 2006 to drill, re-enter or recomplete wells in efforts to improve production. During 2007, we plan to expand the Mallalieu production facilities to accommodate the expected production growth. Reservoir modeling indicates the field may be producing in excess of 6,500 Bbls/d by the fourth quarter of 2007.
From inception through December 31, 2006, we had net positive cash flow (revenue less operating expenses and capital expenditures) from Mallalieu Field of $139.3 million, plus the fields have a PV-10 Value of $457.2 million, using December 31, 2006, NYMEX pricing of $61.05 per barrel.
McComb and Smithdale Fields. We commenced tertiary recovery operations in 2003 at McComb Field and started injecting CO 2 late that year. Significant development occurred during 2004 and 2005 as we expanded the nearby Olive Field CO 2 facility to handle the processing of McComb’s produced oil, water and CO 2 and developed an additional four injection patterns. The first production response occurred in the second quarter of 2004 and has gradually increased since that time, averaging 1,463 Bbls/d in the fourth quarter of 2006. During 2006, we continued the expansion of our operations within McComb Field and further expanded the production facilities. Although we have encountered injection issues during 2006, which limited our CO 2 injections at McComb, by the second quarter of 2007 we expect to have all the necessary equipment installed, which we believe will eliminate the injection issues. In addition, we are injecting CO 2 at the nearby, much smaller, Smithdale Field utilizing the same CO 2 facilities. We started injecting CO 2 at Smithdale in the second quarter of 2005, although our production through December 31, 2006 has generally been less than 100 Bbls/day.
From inception through December 31, 2006, we had not yet recovered our costs in these fields with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from these fields of $91.2 million, although the fields have a PV-10 Value of $370.7 million, using December 31, 2006, NYMEX pricing.
Brookhaven Field. Our first tertiary CO 2 production response at Brookhaven Field occurred during the fourth quarter of 2005, with oil production rates averaging 125 Bbls/d during the fourth quarter of 2005. Production rates continued to increase throughout 2006 as additional patterns were developed. Production during the fourth quarter of 2006 increased only slightly from third quarter 2006 rates, as CO 2 injection rates were less than initially planned. Incremental work on CO 2 injection wells was required to improve injection rates and to ensure the CO 2 was entering the proper intervals. Additional injection pumps were installed on certain wells to increase injection rates. Oil production during the fourth quarter of 2006 averaged 1,014 Bbls/d.
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From inception through December 31, 2006, we had not yet recovered our costs in this field with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Brookhaven of $50.9 million, although the field has a PV-10 Value of $353.4 million attributed to the tertiary recovery reserves, using December 31, 2006, NYMEX pricing.
Little Creek Field. During the fourth quarter of 2006, production averaged 2,279 Bbls/d (including Lazy Creek). Production at Little Creek Field began declining in 2006 and is expected to continue to decline over the next several years. We are working to mitigate production declines by monitoring injection patterns, reworking producing wells and using injection surveys to control at which intervals the CO 2 is injected. From inception through December 31, 2006, we had net positive cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Little Creek (including adjoining smaller fields) of $127.2 million, plus the fields have a PV-10 Value of $90.6 million, using December 31, 2006, NYMEX pricing.
Eucutta Field. Eucutta Field is the only field in East Mississippi (Phase II) that currently has significant proven tertiary oil reserves. This field is analogous to Heidelberg Field in that the majority of its historical production was produced from the Eutaw formation. The Eutaw formation at Eucutta was unitized for water flooding in 1966 and has gone through several stages of development. During the 1980s, Amerada Hess installed an inverted 5-spot injection pilot in the First City Bank sand (one of the Eutaw sands) to test the application of CO 2 flooding. Although the pilot test only covered approximately 20 acres, the pilot was successful in recovering an additional 17% of the original oil in place within the pattern. Based on this success, we designed and constructed a CO 2 flood and facility for the Eucutta Field. Initial well work was completed and CO 2 injection started during the first quarter of 2006, with the first minor tertiary oil production during the fourth quarter of 2006. Our plans for 2007 include the development of the remaining patterns and expansion of our CO 2 facilities. At December 31, 2006 we had 10.3 MMBbls of proved reserves in the Eucutta field attributable to the CO 2 flood. The proved reserve estimate is based on a 13% recovery factor, lower than was achieved in the pilot program in the 1980s, and therefore we expect to have upward reserve increases in the future.
Martinville Field. We initiated our first injections of CO 2 in Martinville Field during the first quarter of 2006 in both the Rodessa and Mooringsport formations. As is the case with most of the East Mississippi fields, Martinville produces from multiple reservoirs. Unlike the majority of our other planned CO 2 projects, Martinville does not contain a single large reservoir to CO 2 flood, but rather several smaller reservoirs. We completed construction of the CO 2 facilities and essentially completed the development of the Mooringsport sand during 2006. During the fourth quarter of 2006, the first well responded, although the average rate for the quarter was only 24 Bbls/d. The tertiary oil rate has increased to approximately 400 Bbls/d during the month of January 2007. The second reservoir, the Rodessa, although smaller in size, has similar reservoir characteristics to the Mooringsport. We initiated injection into the Rodessa with three injection wells during 2006. We have not seen CO 2 response to date from the Rodessa.
The Wash Fred 8500’ reservoir in the Martinville Field contains a low oil gravity (thick oil), 15 API, which will not develop miscibility with CO 2 at reservoir conditions. Denbury has several fields with similar gravity oils, which like the Wash Fred 8500’ have had lower recoveries due to the low oil gravities and strong water drives, which do not sweep the oil efficiently. We initiated CO 2 injection during the first quarter of 2006 at the crest of the structure. Although we will not achieve miscibility, the injection of CO 2 is expected to swell the oil, decrease the oil viscosity, and displace the water and oil downward in the reservoir to the adjacent producing wells and result in incremental oil production. Well bore issues delayed the implementation of this flood during 2006, but we are currently injecting CO 2 and observing the production from offset wells to determine what effect the CO 2 will have on oil and water production. The success of this flood would provide the impetus to look at a whole new array of fields that have historically not been considered for CO 2 injection, although there can be no assurance that this technique will be successful or economic.
Our Tertiary Oil Fields without Proven Tertiary Reserves
During 2007, we plan to commence tertiary operations at a small field, Lockhart Crossing (Phase I), our first Louisiana flood, and Cranfield Field in West Mississippi (Phase IV), and install the pipeline necessary to deliver CO 2 to Delhi Field (Phase V) so that injection can begin there in 2008. We initiated CO 2 injections at Tinsley Field (Phase III) in January 2007, although in very limited amounts, with more significant development expected there when the larger, replacement CO 2 pipeline to Tinsley is completed, which we anticipate will be in the fourth quarter of 2007.
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Soso Field. Soso Field, near Laurel, Mississippi, produced from numerous reservoirs during primary production including the Rodessa, Bailey and Cotton Valley sands, all of which we plan to CO 2 flood. The Bailey sand exhibits comparable reservoir characteristics to our West Mississippi floods and we expect the Bailey tertiary flood to perform in a similar manner. We elected to co-develop the Bailey sand and Rodessa sand to accelerate the development of the potential tertiary oil reserves at Soso. Although we began initial development of the Bailey sand very late in 2005, the majority of our capital investment to date occurred in 2006, which involved the construction of CO 2 facilities and the establishment of the two tertiary injection projects. During the first quarter 2006, we initiated our first injections of CO 2 into five Bailey injection wells and initiated injection in the Rodessa during the second quarter of 2006, although injections in the Bailey formation were initially limited because of delays in getting the well work done and limited CO 2 supplies. We expect to see our first tertiary production in Soso Field during the second quarter of 2007.
Tinsley Field. Tinsley field was acquired in January 2006 and is one of the largest oil fields in the state of Mississippi. As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs. While we are working the other reservoirs in an attempt to increase current conventional production and reserves, our primary target in Tinsley for CO 2 enhanced oil recovery operations is the Woodruff formation. One of the prior operators performed a pilot CO 2 project at Tinsley in the Perry sandstone. The CO 2 was successful at mobilizing oil but the operator decided not to expand the flood due to low oil prices. The acquisition of the field included an 8” pipeline that was installed to deliver CO 2 to the pilot project but was converted to natural gas service some time ago. We have reconditioned the pipeline for CO 2 service and initiated limited CO 2 injection in Tinsley Field in January 2007. In order to expand our injection of CO 2 to the entire field, it will be necessary to install a new CO 2 pipeline, which we expect will be completed by the third or fourth quarter of 2007.
Delhi Field . During May 2006, we purchased the Delhi Holt-Bryant Unit (“Delhi”) in Northern Louisiana for $50 million, plus a 25% reversionary interest to the seller after we achieve $200 million in net operating revenue, as defined. Delhi is also a future potential CO 2 tertiary oil flood candidate that will require construction of a CO 2 pipeline before flooding can commence, with current plans to make such a line an extension of the larger, new CO 2 pipeline currently planned from Jackson Dome to Tinsley Field. Our goal is to have this CO 2 pipeline installed by 2008, with initial oil production from tertiary operations currently anticipated during 2009. As of December 31, 2006, there was not any significant oil production or proved oil reserves at Delhi Field.
Hastings Field. During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc. that gives us an option, between November 1, 2008 and November 1, 2009, to purchase their interest in Hastings Field a strategically significant potential tertiary flood candidate located near Houston, Texas. The agreement provides for the parties to agree upon a purchase price for the conventional proved reserves at the time of the exercise of the option, which may be paid in cash or through a volumetric production payment; failing agreement as to price, the price will be determined by a pre-designated independent petroleum engineering firm using specified criteria for calculation of the discounted present value of proved reserves at that time. As consideration for the option agreement, we made an upfront payment of $37.5 million and are required to make additional payments totaling $12.5 million over the next 20 months. We can extend the option period beyond November 2009 for up to seven additional years at an incremental cost of $30 million per year. None of the option payment amounts will be credited against the purchase price if we exercise the option. If we exercise the option, we will be committed to make aggregate net capital expenditures in the field of approximately $175 million over the subsequent five years to develop the field for tertiary operations, with an obligation to commence CO 2 injections in the field within three years following the option exercise. Hastings Field is currently producing approximately 2,400 Bbls/d, although we currently have no economic interest in this production.
Based on preliminary engineering data, the West Hastings Unit (the most likely area to be initially developed as a tertiary flood) has significant net reserve potential from CO 2 tertiary floods, more reserve potential than any other single field in our inventory. We plan to build a pipeline to transport CO 2 to this field (see “CO 2 pipelines” above). Based on preliminary estimates, it will cost between $400 million and $600 million to develop the West Hastings Unit as a tertiary flood, excluding the cost of the CO 2 pipeline.
The Hasting Field agreement provides for a significant strategic addition, giving us an anchor field to the Texas Gulf Coast region. The field and the CO 2 pipeline will significantly expand our area of operations and growth opportunities into the Texas Gulf Coast region. Denbury continues to evaluate fields in the area to add to a reserve base in the Texas Gulf Coast area.
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Overall Tertiary Economics to Date. Through December 31, 2006, we spent a total of $665.4 million on tertiary oil fields (including the allocated acquisition costs), and received $472.2 million in net positive cash flow (revenue less operating expenses), or net unrecovered cash flow of $193.2 million, the deficit primarily due to the significant funds expended on acquisitions during 2006. Of our total spending, approximately $273.5 million was spent on fields that had little or no proved reserves at December 31, 2006 (i.e. significant incremental proved reserves are anticipated during 2007 and beyond). These amounts do not include the capital costs or related depreciation and amortization of our CO 2 producing properties at Jackson Dome, which had an unrecovered net cash flow of $198.7 million as of December 31, 2006, including $54.6 million associated with the Free State CO 2 pipeline. At year-end 2006, the proved oil reserves in our tertiary recovery oil fields had a PV-10 Value of $1.46 billion, using December 31, 2006, NYMEX pricing of $61.05 per barrel. In addition, there is significant probable and potential reserves at several other fields for which tertiary operations are underway or planned.
Texas and the Barnett Shale
We currently own approximately 74,700 gross acres and 53,800 net acres of leases in the Barnett Shale area in North Central Texas, of which approximately 22,100 gross acres and 19,600 net acres are in the more tested northern areas of Parker and Wise Counties, with the remainder in Erath and adjoining more southern and untested counties. We acquired our initial acreage in this area in 2001 and did only limited development until 2005. Through December 31, 2006, we have spent a total of $267.2 million on the Barnett Shale area and have received $90.1 million in net operating income (revenue less operating expenses), or net negative cash flow of $177.1 million. At December 31, 2006, we had approximately 252.4 Bcfe of proved reserves in the Barnett Shale area with a PV-10 Value of approximately $243.5 million, using December 31, 2006, Henry Hub indicative cash pricing of $5.63 per MMBtu.
We continue to refine our completion and fracturing techniques, including an analysis of the best number of fracture treatments to adequately stimulate the entire length of the lateral sections of our horizontal wells, which can exceed 4,000 feet. During 2006, we drilled an additional 46 horizontal wells, increasing our net Barnett Shale production from approximately 18.3 MMcfe/d in the fourth quarter of 2005 to approximately 35.4 MMcfe/d during the fourth quarter of 2006. During 2006, we finalized the acquisition and interpretation of our 3-D seismic data over our entire northern acreage position, 90 to 100 square miles, and initiated a 3-D shoot of the southern acreage. The 3-D seismic data helps us better locate our wells so that we encounter less faulting and underground sink holes, which have been associated with fracture stimulations into zones outside of the Barnett Shale that are typically water bearing. We expect production in this area to grow significantly during 2007 as we plan to drill approximately 35 to 40 horizontal wells, all of which are scheduled for Parker County. Including seismic costs and pipeline infrastructure costs, our planned 2007 capital expenditures in the Barnett Shale area are estimated to make up $122 million of our current $650 million capital budget.
At this time we are still evaluating the 2006 drilling and completion work in our southern acreage, primarily Erath County. The initial results do not look very encouraging as we drilled five wells, completing three, none of which have been economic. We elected not to complete the last two wells pending a re-analysis of all of our results to date.
East Mississippi Fields Without Proven Tertiary Oil Reserves
We have been active in East Mississippi since Denbury was founded in 1990 and are by far the largest oil producer in the basin. For years, this has been our area with the highest production and most proved reserves, representing production of approximately 12,808 BOE/d during the fourth quarter of 2006 (35% of our Company total) and proved reserves of 52.7 MMBOE as of December 31, 2006 (30% of our Company total). Since we have generally owned these Eastern Mississippi properties longer than properties in our other regions, they tend to be more fully developed, and although most are targeted for tertiary operations in the future, only three currently have tertiary operations (Soso, Martinville and Eucutta Fields). Production from our East Mississippi fields has been relatively consistent over the last three years, averaging 13,085 BOE/d in 2004, 12,072 BOE/d in 2005 and 12,743 BOE/d during 2006. For 2007, we expect our budget in this region for conventional operations to be around $50 million, about the same as in 2006, representing approximately 8% of our current 2006 exploration and development budget of $650 million.
Heidelberg Field. The largest field in the region and one of our largest fields corporately is Heidelberg Field, which for the fourth quarter of 2006 produced an average of 7,444 BOE/d, 2% more than the 2005 average of 7,312 BOE/d. Heidelberg Field was acquired from Chevron in December 1997. The field is a large salt-cored anticline that is divided into western and eastern segments due to subsequent faulting. There are 11 producing formations in
Denbury Resources Inc.
Heidelberg Field containing 40 individual reservoirs, with the majority of the past and current production coming from the Eutaw, Selma Chalk and Christmas sands at depths of 3,500 to 5,000 feet. When we acquired the property in 1997, production was approximately 2,800 BOE/d.
The majority of the oil production at Heidelberg is from six waterflood units that produce from the Eutaw formation (at approximately 4,400 feet). Most of our recent development at Heidelberg has been in the Selma Chalk, a natural gas reservoir at around 3,700 feet, making Heidelberg our second largest gas field. We have steadily developed the Selma Chalk since 2001, drilling from 13 to 20 wells per year, increasing the natural gas production at Heidelberg to a peak quarterly average of 15.8 MMcf/d in the fourth quarter of 2004, averaging 14.3 MMcf/d during 2006. During 2005 we drilled and completed our first horizontal well in the Selma Chalk. The well was drilled in an area of the field where prior vertical wells typically yielded lower than average production rates. The well was completed in two stages and the results were encouraging. During 2006, we drilled 12 Selma Chalk wells, four of which were horizontal wells, and we plan to drill 13 horizontal wells during 2007.
South Louisiana
We own interests in the land and marshes of south Louisiana, a region that produces primarily natural gas. Production from this area averaged 39.4 MMcfe/d net to our interest in the fourth quarter of 2006, a slight increase from our 2005 average of 37.0 MMcfe/d. Production was as high as 51.7 MMcfe/d during the second quarter of 2006 following the completion of several new wells drilled in late 2005 and early 2006, but has declined significantly from that peak as a result of the relatively rapid depletion for wells in this area. During 2006, we spent approximately $64.7 million (excluding acquisitions) in this region, approximately 13% of our total exploration and development expenditures, drilling approximately 12 wells, primarily in Cameron, Jefferson Davis, and Terrebonne Parish areas. For 2007, our spending is expected to be approximately $40 million or 6% of our currently planned $650 million exploration and development budget, significantly less than our 2006 expenditures in this area.
The majority of our onshore Louisiana fields lie in the Houma embayment area of Terrebonne Parish, including Lirette and South Chauvin Fields, and our recent shallow natural gas plays at Bayou Sauveur and Gibson Fields. We drilled four wells in Terrebonne Parish during 2006. In 2007, we plan to drill approximately three exploratory wells in Terrebonne Parish and four development wells.
In late 2005 we spudded our Gumbo Prospect in Terrebonne Parish, the Westerfelt #2 well, a 19,000+ foot well testing the Rob L sands. We logged the well in January 2006, constructed production facilities and completed the well. The well produced approximately 645 MMcf and 26 MBbls of condensate (gross) during a two month period. In October 2006 the well logged-off and is presently being evaluated for sidetracking to another fault block. Based on the Westerfelt #2 production information and pressures, we believe that the Westerfelt #2 encountered an isolated reservoir area that is not in communication with the large feature it was intended to test. Based upon the results of the Westerfelt #2 and review of the seismic interpretation, we decided to drill an offset, the State Lease 18380 #1 well. We believe that this well should encounter a larger reservoir with greater reserve potential. The completion of drilling operations is expected late in the first quarter or early in the second quarter of 2007. Assuming the well logs are favorable, significant production history will be required to fully evaluate the potential reserves associated with this prospect.
Denbury Resources Inc.
Field Summaries
Denbury operates in four primary areas: Louisiana, Eastern Mississippi, Western Mississippi and Texas. Our 16 largest fields (listed below) constitute approximately 93% of our total proved reserves on a BOE basis and on a PV-10 Value basis. Within these 16 fields, we own a weighted average 92% working interest and operate all of these fields. The concentration of value in a relatively small number of fields allows us to benefit substantially from any operating cost reductions or production enhancements we achieve and allows us to effectively manage the properties from our five primary field offices located in Houma, Louisiana, Laurel, Mississippi; McComb, Mississippi; Brandon; Mississippi; and Cleburne, Texas.
| Proved Reserves as of December 31, 2006 (1) | 2006 Average Daily Production | |||||||||||||||||||||||||||||||
| Natural | Average Net | |||||||||||||||||||||||||||||||
| Oil | Natural Gas | BOE | PV-10 Value | Oil | Gas | Revenue | ||||||||||||||||||||||||||
| (MBbls) | (MMcf) | MBOEs | % of total | (000's) | (Bbls/d) | (Mcf/d) | Interest | |||||||||||||||||||||||||
Mississippi
— CO2 floods |
||||||||||||||||||||||||||||||||
Brookhaven |
18,987 | — | 18,987 | 10.9 | % | $ | 353,406 | 833 | — | 82.0 | % | |||||||||||||||||||||
Mallalieu (East & West) |
13,582 | — | 13,582 | 7.8 | % | 457,200 | 5,210 | — | 76.6 | % | ||||||||||||||||||||||
McComb/Olive |
12,717 | — | 12,717 | 7.3 | % | 297,449 | 1,177 | — | 77.0 | % | ||||||||||||||||||||||
Eucutta |
10,313 | — | 10,313 | 5.9 | % | 186,229 | 47 | — | 83.5 | % | ||||||||||||||||||||||
Little Creek & Lazy Creek |
3,696 | — | 3,696 | 2.1 | % | 90,592 | 2,739 | — | 83.3 | % | ||||||||||||||||||||||
Smithdale and other |
2,872 | — | 2,872 | 1.7 | % | 71,560 | 64 | — | 79.3 | % | ||||||||||||||||||||||
Total
Mississippi — CO2 floods |
62,167 | — | 62,167 | 35.7 | % | 1,456,436 | 10,070 | — | 79.9 | % | ||||||||||||||||||||||
Other Mississippi |
||||||||||||||||||||||||||||||||
Heidelberg (East & West) |
25,943 | 51,512 | 34,528 | 19.8 | % | 477,186 | 5,036 | 14,330 | 76.2 | % | ||||||||||||||||||||||
Tinsley |
3,299 | 90 | 3,314 | 1.9 | % | 60,391 | 881 | 10 | 81.7 | % | ||||||||||||||||||||||
Eucutta |
2,708 | — | 2,708 | 1.6 | % | 35,524 | 819 | 40 | 69.4 | % | ||||||||||||||||||||||
S. Cypress Creek |
1,903 | 102 | 1,920 | 1.1 | % | 26,041 | 233 | 41 | 83.0 | % | ||||||||||||||||||||||
Summerland |
1,662 | — | 1,662 | 0.9 | % | 20,556 | 445 | — | 74.4 | % | ||||||||||||||||||||||
King Bee |
1,458 | — | 1,458 | 0.8 | % | 17,316 | 269 | — | 78.9 | % | ||||||||||||||||||||||
Other Mississippi |
5,172 | 11,694 | 7,121 | 4.1 | % | 118,821 | 1,887 | 4,618 | 33.1 | % | ||||||||||||||||||||||
Total Other Mississippi |
42,145 | 63,398 | 52,711 | 30.2 | % | 755,835 | 9,570 | 19,039 | 64.9 | % | ||||||||||||||||||||||
Louisiana |
||||||||||||||||||||||||||||||||
S. Chauvin |
436 | 13,940 | 2,759 | 1.6 | % | 57,189 | 298 | 11,744 | 38.3 | % | ||||||||||||||||||||||
Thornwell |
406 | 5,876 | 1,385 | 0.8 | % | 33,905 | 1,068 | 11,147 | 37.4 | % | ||||||||||||||||||||||
Other Louisiana |
901 | 20,076 | 4,248 | 2.4 | % | 75,305 | 789 | 11,800 | 41.0 | % | ||||||||||||||||||||||
Total Louisiana |
1,743 | 39,892 | 8,392 | 4.8 | % | 166,399 | 2,155 | 34,691 | 39.5 | % | ||||||||||||||||||||||
Texas |
||||||||||||||||||||||||||||||||
Newark (Barnett Shale) |
11,606 | 182,812 | 42,075 | 24.1 | % | 243,474 | 106 | 28,525 | 75.0 | % | ||||||||||||||||||||||
Other Texas |
179 | 669 | 290 | 0.2 | % | 1,552 | 8 | — | 79.9 | % | ||||||||||||||||||||||
Total Texas |
11,785 | 183,481 | 42,365 | 24.3 | % | 245,026 | 114 | 28,525 | 75.1 | % | ||||||||||||||||||||||
Alabama |
||||||||||||||||||||||||||||||||
Citronelle |
8,283 | — | 8,283 | 4.8 | % | 67,594 | 1,026 | — | 62.7 | % | ||||||||||||||||||||||
Other Alabama |
7 | 1,978 | 337 | 0.2 | % | 3,165 | 1 | 727 | 30.5 | % | ||||||||||||||||||||||
Total Alabama |
8,290 | 1,978 | 8,620 | 5.0 | % | 70,759 | 1,027 | 727 | 60.2 | % | ||||||||||||||||||||||
Other |
55 | 77 | 67 | 0.0 | % | 744 | — | 93 | 0.1 | % | ||||||||||||||||||||||
Company Total |
126,185 | 288,826 | 174,322 | 100.0 | % | $ | 2,695,199 | 22,936 | 83,075 | 57.2 | % | |||||||||||||||||||||
(1) The reserves were prepared using constant prices and costs in accordance with the guidelines of the SEC based on the prices received on a field-by-field basis as of December 31, 2006. The prices at that date were a NYMEX oil price of $61.05 per Bbl adjusted to prices received by field and a Henry Hub natural gas price average of $5.63 per MMBtu also adjusted to prices received by field.
Denbury Resources Inc.
Oil and Gas Acreage, Productive Wells, and Drilling Activity
In the data below, “gross” represents the total acres or wells in which we own a working interest and “net” represents the gross acres or wells multiplied by Denbury’s working interest percentage. For the wells that produce both oil and gas, the well is typically classified as an oil well or gas well based on the ratio of oil to gas production.
Oil and Gas Acreage
The following table sets forth Denbury’s acreage position at December 31, 2006:
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Mississippi |
107,930 | 86,143 | 276,809 | 54,303 | 384,739 | 140,446 | ||||||||||||||||||
Louisiana |
56,393 | 49,126 | 21,517 | 15,002 | 77,910 | 64,128 | ||||||||||||||||||
Texas |
20,256 | 18,119 | 56,454 | 37,487 | 76,710 | 55,606 | ||||||||||||||||||
Alabama |
34,329 | 21,919 | 77,524 | 18,887 | 111,853 | 40,806 | ||||||||||||||||||
Other |
5,429 | 1,503 | 38,710 | 9,687 | 44,139 | 11,190 | ||||||||||||||||||
Total |
224,337 | 176,810 | 471,014 | 135,366 | 695,351 | 312,176 | ||||||||||||||||||
Denbury’s net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 7% in 2007, 8% in 2008 and 4% in 2009.
Productive Wells
The following table sets forth our gross and net productive oil and natural gas wells at December 31, 2006:
| Producing Natural | ||||||||||||||||||||||||
| Producing Oil Wells | Gas Wells | Total | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Operated Wells: |
||||||||||||||||||||||||
Mississippi |
492 | 474.9 | 176 | 161.8 | 668 | 636.7 | ||||||||||||||||||
Louisiana |
30 | 24.7 | 47 | 39.2 | 77 | 63.9 | ||||||||||||||||||
Texas |
3 | 3.0 | 96 | 94.2 | 99 | 97.2 | ||||||||||||||||||
Alabama |
158 | 124.1 | 35 | 20.4 | 193 | 144.5 | ||||||||||||||||||
Other |
— | — | — | — | — | — | ||||||||||||||||||
Total |
683 | 626.7 | 354 | 315.6 | 1,037 | 942.3 | ||||||||||||||||||
Non-Operated Wells: |
||||||||||||||||||||||||
Mississippi |
37 | 3.4 | 17 | 3.9 | 54 | 7.3 | ||||||||||||||||||
Louisiana |
— | — | 17 | 3.7 | 17 | 3.7 | ||||||||||||||||||
Texas |
— | — | 4 | 0.5 | 4 | 0.5 | ||||||||||||||||||
Alabama |
— | — | 10 | 1.5 | 10 | 1.5 | ||||||||||||||||||
Other |
1 | — | — | — | 1 | — | ||||||||||||||||||
Total |
38 | 3.4 | 48 | 9.6 | 86 | 13.0 | ||||||||||||||||||
Total Wells: |
||||||||||||||||||||||||
Mississippi |
529 | 478.3 | 193 | 165.7 | 722 | 644.0 | ||||||||||||||||||
Louisiana |
30 | 24.7 | 64 | 42.9 | 94 | 67.6 | ||||||||||||||||||
Texas |
3 | 3.0 | 100 | 94.7 | 103 | 97.7 | ||||||||||||||||||
Alabama |
158 | 124.1 | 45 | 21.9 | 203 | 146.0 | ||||||||||||||||||
Other |
1 | — | — | — | 1 | — | ||||||||||||||||||
Total |
721 | 630.1 | 402 | 325.2 | 1,123 | 955.3 | ||||||||||||||||||
Denbury Resources Inc.
Drilling Activity
The following table sets forth the results of our drilling activities over the last three years:
| Year Ended December 31, | ||||||||||||||||||||||||
| 2006 | 2005 | 2004 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory Wells:(1) |
||||||||||||||||||||||||
Productive(2) |
10 | 8.5 | 12 | 7.1 | 8 | 5.8 | ||||||||||||||||||
Non-productive(3) |
8 | 6.8 | 1 | 0.6 | 4 | 2.3 | ||||||||||||||||||
Development Wells:(1) |
||||||||||||||||||||||||
Productive(2) |
90 | 82.7 | 81 | 74.3 | 68 | 53.8 | ||||||||||||||||||
Non-productive(3)(4) |
— | — | — | — | 1 | 0.6 | ||||||||||||||||||
Total |
108 | 98.0 | 94 | 82.0 | 81 | 62.5 | ||||||||||||||||||
| (1) | An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A developmental well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. | |
| (2) | A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. | |
| (3) | A nonproductive well is an exploratory or development well that is not a producing well. | |
| (4) | During 2006, 2005 and 2004, an additional 14, 5, and 8 wells, respectively, were drilled for water or CO2 injection purposes. |
Production and Unit Prices
Information regarding average production rates, unit sale prices and unit costs per BOE are set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Income” included herein.
Title to Properties
Customarily in the oil and gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired. Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted, and curative work is performed with respect to significant defects. During acquisitions, title reviews are performed on all properties; however, formal title opinions are obtained on only the higher value properties. We believe that we have good title to our oil and natural gas properties, some of which are subject to minor encumbrances, easements and restrictions.
Geographic Segments
All of our operations are in the United States.
Significant Oil and Gas Purchasers and Product Marketing
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 year ended December 31, 2006, we had two purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Ashland Petroleum LLC (28%) and Hunt Crude Oil Supply Co. (18%). For the year ended December 31, 2005, three purchasers each accounted for more than 10% of our total oil and natural gas revenues: Marathon Ashland Petroleum LLC (28%), Hunt Crude Oil Supply Co. (20%) and Sunoco, Inc (13%). For the year ended December 31, 2004, two purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Crude Oil Supply Co. (21%) and Genesis Energy, L.P. (14%).
Denbury Resources Inc.
Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our gas production to pipelines, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. Our production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, we have not experienced any difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.
Oil Marketing
The quality of our crude oil varies by area as well as the corresponding price received. In Heidelberg Field, one of our larger fields, and our other Eastern Mississippi properties, our oil production is primarily light to medium sour crude and sells at a significant discount to the NYMEX prices. In Western Mississippi, the location of our current CO 2 operations, our oil production is primarily light sweet crude, which typically sells at near NYMEX prices, or often at a premium. For the year ended December 31, 2006, the discount for our oil production from Heidelberg Field averaged $13.31 per Bbl and for our Eastern Mississippi properties as a whole the discount averaged $12.11 per Bbl relative to NYMEX oil prices. For Mallalieu Field, the largest producer during 2006 of our CO 2 properties in Western Mississippi, we averaged a premium of $0.20 per Bbl over NYMEX oil prices, and $0.30 per Bbl over NYMEX prices for our tertiary oil production in Western Mississippi taken as a whole. Our Louisiana properties averaged $13.82 per Bbl below NYMEX prices during 2006, largely because the reported oil sales include a significant amount of natural gas liquids, which typically sell at a lower price than crude oil.
Natural Gas Marketing
Virtually all of our natural gas production is close to existing pipelines and consequently we generally have a variety of options to market our natural gas. We sell the majority of our natural gas on one-year contracts with prices fluctuating month-to-month based on published pipeline indices with slight premiums or discounts to the index. We receive near NYMEX or Henry Hub prices for most of our natural gas sales due to our proximity to Henry Hub and the high Btu content of our natural gas. For the year ended December 31, 2006, we averaged $0.77 above NYMEX prices for our Louisiana natural gas production. However, in the Barnett Shale area in Texas, due primarily to its location, the price we received averaged $0.83 below NYMEX prices. We expect our overall differential to NYMEX prices to gradually increase in the future due to our increasing emphasis in the Barnett Shale area.
Competition and Markets
We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our standards established for minimum projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Because of the nature of our core assets (our tertiary operations) and our ownership of a relatively uncommon significant natural source of carbon dioxide, we believe that we are effective in competing in the market.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We cannot be certain when we will experience
Denbury Resources Inc.
these issues and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted.
Federal and State Regulations
Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. The following section describes some specific laws and regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.
Management believes that we are in substantial compliance with all laws and regulations applicable to our operations and that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital costs of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements. However, management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.
Regulation of Natural Gas and Oil Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in those units and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability.
Federal Regulation of Sales Prices and Transportation
The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by the availability, terms and cost of transportation. In particular, t