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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2004 FORM 10-K
(Mark One)
X Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2004
OR
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _________ to________
Commission File Number 1-12935
------------------------------
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 20-0467835
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
5100 Tennyson Parkway,
Suite 3000, Plano, TX 75024
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (972) 673-2000
Securities registered pursuant to Section 12(b) of the Act:
====================================================================================================
Title of Each Class Name of Each Exchange on Which Registered
Common Stock $.001 Par Value New York Stock Exchange
====================================================================================================
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes X No__
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2
of the Act). [ X ]
As of June 30, 2004, the aggregate market value of the registrant's Common Stock held by
non-affiliates was approximately $1.1 billion.
The number of shares outstanding of the registrant's Common Stock as of February 28, 2005, was
56,612,005.
DOCUMENTS INCORPORATED BY REFERENCE
Document Incorporated as to
1. Notice and Proxy Statement for the Annual Meeting 1. Part III, Items 10, 11, 12, 13, 14
of Shareholders to be held May 11, 2005.
Denbury Resources Inc.
2004 Annual Report on Form 10-K
Table of Contents
Page
----
Glossary and Selected Abbreviations............................ 3
PART I
Item 1. Business....................................................... 4
Item 2. Properties..................................................... 22
Item 3. Legal Proceedings.............................................. 22
Item 4. Submission of Matters to a Vote of Security Holders............ 22
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities............ 23
Item 6. Selected Financial Data........................................ 25
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 46
Item 8. Financial Statements and Supplementary Data.................... 46
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.......................... 86
Item 9A. Controls and Procedures........................................ 86
Item 9B. Other Information.............................................. 86
PART III
Item 10. Directors and Executive Officers of the Company................ 86
Item 11. Executive Compensation......................................... 87
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................... 87
Item 13. Certain Relationships and Related Transactions................. 87
Item 14. Principal Accountant Fees and Services......................... 87
PART IV
Item 15. Exhibits and Financial Statement Schedules..................... 87
Signatures..................................................... 90
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Denbury Resources Inc.
Glossary and Selected Abbreviations
Bbl One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude Oil
or other liquid hydrocarbons.
Bbls/d Barrels of oil produced per day.
Bcf One billion cubic feet of natural gas or CO2.
BOE One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural
gas liquids to 6 Mcf of natural gas.
BOE/d BOEs produced per day.
Btu Btu British thermal unit, which is the heat required to raise the temperature of a one-pound
mass of water from 58.5 to 59.5 degrees Fahrenheit.
CO2 Carbon Dioxide.
Finding and The average cost per BOE to find and develop proved reserves during a given period. It is
Development calculated by dividing costs, which includes the total acquisition, exploration and development
Cost costs incurred during the period plus future development and abandonment costs related to the
specified property or group of properties, by the sum of (i) the change in total proved
reserves during the period plus (ii) total production during that period.
MBbls One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE One thousand BOEs.
MBtu One thousand Btus.
Mcf One thousand cubic feet of natural gas or CO2.
Mcf/d One thousand cubic feet of natural gas or CO2 produced per day.
MCFE One thousand cubic feet of natural gas equivalent using the ratio of one barrel of crude oil,
condensate or natural gas liquids to 6 Mcf of natural gas.
MCFE/D MCFEs produced per day.
MMBbls One million barrels of crude oil or other liquid hydrocarbons.
MMBOE One million BOEs.
MMBtu One million Btus.
MMcf One million cubic feet of natural gas or CO2.
MMCFE One thousand MCFE.
MMCFE/D MMCFEs produced per day.
PV-10 Value When used with respect to oil and natural gas reserves, PV-10 Value means the estimated future
gross revenue to be generated from the production of proved reserves, net of estimated
production and future development and abandonment costs, using prices and costs in effect at
the determination date, and before income taxes, discounted to a present value using an annual
discount rate of 10% in accordance with the guidelines of the Securities and Exchange
Commission.
Proved Developed Reserves that can be expected to be recovered through existing wells with existing equipment
Reserves* and operating methods.
Proved Reserves* The estimated quantities of crude oil, natural gas and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves that are expected to be recovered from new wells on undrilled acreage or from existing
Reserves* wells where a relatively major expenditure is required.
Tcf One trillion cubic feet of natural gas or CO2.
* This definition is an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of
Regulation S-X. See www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the complete definition.
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Denbury Resources Inc.
PART I
ITEM 1. BUSINESS
- ----------------
WEBSITE ACCESS TO REPORTS
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") 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 and the Barnett
Shale in Texas. Our corporate headquarters is located at 5100 Tennyson Parkway,
Suite 3000, Plano, Texas 75024, and our phone number is 972-673-2000. At
December 31, 2004, we had 380 employees, 243 of which were employed in field
operations or at the field offices. Our employee count does not include the
approximately 200 employees of Genesis Energy, Inc. as of December 31, 2004 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. The purposes of creating the holding
company structure were to better reflect the operating practices and methods of
Denbury, to improve its economics, and to provide greater administrative and
operational flexibility. 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). The reorganization was structured as a tax free reorganization to
Denbury's stockholders and all outstanding capital stock of the original public
company was automatically converted into the identical number of and type of
shares of the new public holding company. 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. The new parent holding company is co-obligor (or guarantor, as
appropriate) regarding the payment of principal and interest on Denbury's
outstanding debt securities.
BUSINESS STRATEGY
As part of our corporate strategy, we believe in the following fundamental
principles:
o remain focused in specific regions;
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Denbury Resources Inc.
o acquire properties where we believe additional value can be created
through a combination of exploitation, development, exploration and
marketing, including secondary and tertiary operations;
o acquire properties that give us a majority working interest and
operational control or where we believe we can ultimately obtain it;
o maximize the value of our properties by increasing production and
reserves while reducing cost; and
o maintain a highly competitive team of experienced and incentivized
personnel.
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 CO2 Assets
Just over five years ago, we started a new focus area through an
acquisition of a carbon dioxide ("CO2") tertiary flood in an area very familiar
to us, Mississippi. We have subsequently acquired other related assets and are
making that focus area the major part of our business. We particularly like this
tertiary play as (i) it is lower risk and more predictable than most traditional
exploration and development activities, (ii) it provides a reasonable rate of
return at relatively low oil prices (low to mid twenties), and (iii) we have
virtually no competition for this type of activity in our current geographic
area. Generally, from East Texas to Florida, there are no known natural sources
of carbon dioxide except our own, and these large volumes of CO2 that we own
drive the play. Our CO2 comes from an old underground volcano located near
Jackson, Mississippi, discovered in the 1960s while companies were drilling for
oil and natural gas. These CO2 reserves are found in structural traps in the
Haynesville, Buckner, Smackover and Norphlet formations at depths of about
16,000 feet.
CO2 injection is one of the most efficient tertiary recovery mechanisms for
producing crude oil; however, because it requires large quantities of CO2, its
use has been restricted to West Texas, Mississippi and other isolated areas
where large quantities of CO2 are available. The CO2 (in liquid form) acts as a
type of solvent for the oil, causing the oil to expand and become mobile,
allowing the oil to be recovered along with the CO2 as it is produced. The CO2
is then extracted from the oil, compressed back into a liquid state, and
re-injected into the reservoir, with this recycling process occurring several
times during the life of the tertiary operations. In a typical oil field up to
50% of the oil in place can be extracted during primary and secondary
(waterflooding) recovery operations. Through the use of CO2 in tertiary
operations, it is possible to recover additional oil (for example, 17% based on
historical results at Little Creek), almost as much oil as initially recovered
during the primary production phase.
We started this play in August 1999, when we acquired our first CO2
tertiary recovery project, Little Creek Field in Mississippi, a project
originally developed by Shell Oil Company. Since our acquisition of this field,
we have increased oil production here from 1,350 Bbls/d to an average of 2,989
Bbls/d during the fourth quarter of 2004. Following our success at Little Creek,
we embarked upon a strategic program to build a dominant position in this niche
play. We recognized that several other fields in the area would also be
excellent CO2 flood candidates because they produced from the same Lower
Tuscaloosa formation, shared very similar reservoir characteristics and were in
close proximity to each other. Following are highlights of our activities over
the last three years:
o In February 2001, we acquired approximately 800 Bcf of proved
producing CO2 reserves for $42.0 million, a purchase that gave us
control of most of the CO2 supply in Mississippi, as well as ownership
and control of a critical 183-mile CO2 pipeline. This acquisition
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Denbury Resources Inc.
provided the platform to significantly expand our CO2 tertiary
recovery operations because it assured us that CO2 would be available
to us on a reliable basis and at a reasonable and predictable cost.
Since February 2001, we have acquired two and drilled seven additional
CO2 producing wells, more than tripling our estimated proved CO2
reserves to approximately 2.7 Tcf as of December 31, 2004. The
estimate of 2.7 Tcf of proved CO2 reserves is based on 100% ownership
of the CO2 reserves, of which Denbury's net ownership is approximately
2.1 Tcf and is included in the evaluation of proven CO2 reserves
prepared by DeGolyer & MacNaughton and included as Exhibit 99. In
discussing the available CO2 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 CO2 production stream for both of these.
Today, we own every producing CO2 well in the region. Although our
current proven and potential CO2 reserves are quite large, in order to
continue our tertiary development of oil fields in the area,
incremental deliverability of CO2 is needed. In order to obtain the
additional CO2 deliverability, we plan to drill several additional CO2
wells in the future, including up to four more wells during 2005.
o During 2001 and 2002, we acquired several oil fields in our CO2
operating area, including the West Mallalieu and McComb Fields.
Typical of mature properties in this area, the acquisition costs of
both of these fields were relatively low in comparison to their
significant reserve potential as tertiary recovery projects. As an
example, we acquired West Mallalieu Field in May 2001 for $4.0
million, and by year-end 2001 had recognized 10.4 MMBOE of proved
reserves, with additional future reserve potential in this field. We
acquired McComb Field in 2002 for $2.3 million, and by year-end 2002
had recognized 8.3 MMBOE of proved reserves with additional future
reserve potential here also.
o In August 2002, we acquired COHO Energy Inc.'s Gulf Coast properties
for $48.2 million, which included Brookhaven Field, another
significant tertiary flood candidate along our CO2 pipeline. Initial
development of the Brookhaven CO2 flood began in late 2004. DeGolyer &
MacNaughton has estimated that 18.7 MMBbls of oil reserves can be
recovered from Brookhaven field from our CO2 tertiary operations in
their December 31, 2004 proved reserve report.
o During the fourth quarter of 2004, we sold an average of 69 MMcf/d of
CO2 to commercial users and we used an average of 149 MMcf/d for our
tertiary activities. We estimate that our current daily CO2
deliverability is approximately 350 MMcf/d, and by year-end 2005 we
hope to further increase our CO2 deliverability to between 450 MMcf/d
and 500 MMcf/d. We plan to continue our CO2 drilling in 2005 and
beyond, as we estimate that we will need up to 700 MMcf/d in the next
few years in order to meet the projected timetable for our tertiary
projects in Southwest and East Mississippi. During 2004, two of the
CO2 wells we drilled tested new structures that increased our CO2
reserves by approximately 1 Tcf of CO2. These wells will be brought
online once we install the facilities that are necessary to produce
these wells at their maximum rates. With the increase in our CO2
deliverability and reserves, we made the strategic decision to
commence with installation of a pipeline to several of our East
Mississippi properties, and expect to commence CO2 operations in three
East Mississippi fields by mid-2006. As of December 31, 2004, the
calculated present value of the remaining industrial sales contracts
(using pricing provided in the contracts) discounted at 10% per year
was approximately $26.5 million based on the current life of each
contract.
o In October 2003 and September 2004, we sold 167.5 Bcf and 33.0 Bcf of
CO2 to Genesis for $24.9 million and $4.8 million under two separate
volumetric production payments. In conjunction with the sale, we
included the assignment of four of our existing long-term commercial
CO2 supply agreements with our industrial customers. Pursuant to the
terms of the volumetric production payments, Genesis has specific
maximums on the amount of CO2 they are allowed to take each year,
which generally relate to the anticipated volumes of the four
industrial customers. We provide Genesis with certain processing and
transportation services in connection with these agreements for a fee
of approximately $0.16 per Mcf of CO2 delivered to their industrial
customers.
o During the fourth quarter of 2004, we commenced operations to expand
our tertiary program to East Mississippi and have commenced the
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Denbury Resources Inc.
acquisition of leases and right-of-way for the construction of an
84-mile CO2 pipeline from our source wells near Jackson, Mississippi
to Eucutta Field in East Mississippi. We believe that this expansion
into East Mississippi, labeled Phase II, has significant oil potential
beyond the first six fields that we have engineered and plan to flood.
Combining the production forecast for both of these areas (Phase I and
II) extends the period during which we anticipate significant oil
production growth from a few years, for Phase I alone, to five to ten
years combined. While it is extremely difficult to accurately forecast
future production, we do believe that our tertiary recovery operations
provide significant long-term production growth potential at
reasonable rates of return, with relatively low risk, and will be the
backbone of our Company's growth for the foreseeable future.
With anticipated all-in finding and development costs (including future
development and abandonment costs) of around $6.00 per BOE and anticipated
operating costs of around $10.00 per BOE over the life of each field, our
tertiary recovery operations in West Mississippi along our pipeline should
provide a reasonable rate of return at oil prices in the low twenties, as they
produce light sweet oil that receives near NYMEX pricing. The economics will be
a little different in East Mississippi (Phase II) in the following ways: (i)
operating costs in East Mississippi are likely to be one to three dollars per
BOE higher than it is for those fields along our existing CO2 pipeline,
primarily because of the incremental cost of transporting the CO2 to this new
area (assuming another party ultimately owns the pipeline and we pay a
throughput or transportation fee), (ii) the incremental operating cost may be
partially offset by an anticipated lower finding cost, as these East Mississippi
fields may not require as many wells to be drilled or re-entered, as more wells
are currently active, (iii) there are reservoir related differences, which
although not exactly quantified, are expected to improve the overall economics
in the eastern area, and (iv) the quality of the oil is different in the two
areas. In the eastern part of the state, the oil is generally heavier and
usually sour, and thus has a higher negative differential to NYMEX prices,
ranging historically from one to six dollars per barrel lower than West
Mississippi light sweet oil. During the fourth quarter of 2004, the
differentials for these heavier crudes widened to as much as $13 to $16 per
barrel, but we expect the differentials to return to their historical levels
over time. In summary, while the fields in West Mississippi along our pipeline
provide a satisfactory rate of return at NYMEX oil prices in the low twenties,
we project that it takes NYMEX oil prices in the mid to high twenties to achieve
similar rates of return in East Mississippi.
Tentatively, we plan to spend approximately $35 million in 2005 in the
Jackson Dome area targeted to add additional CO2 reserves and deliverability for
future operations. Approximately $60 million in capital expenditures is budgeted
in 2005 for our oil fields with tertiary operations in Southwest Mississippi and
approximately $50 million for oil fields in East Mississippi, plus an additional
$45 million for the CO2 pipeline to East Mississippi, increasing our combined
CO2 and tertiary recovery related expenditures to over 60% of our current 2005
capital budget.
Our Tertiary Oil Fields
Little Creek Field was discovered in 1958, and by 1962 the field had been
unitized and waterflooding had commenced. The pilot phase of CO2 flooding began
in 1974 and the first two phases (each in a distinct area of the field) began in
1985. When we acquired the field in 1999, the first two phases were complete and
the third phase was in process. We have completed development of the third,
fourth and fifth phases and most of the currently planned development work at
this field, although we will continue to modify existing patterns and drill
wells as necessary to recover the maximum amount of oil or to extend the field
into areas that have not benefited from CO2 injection. Currently there are 28
producing wells and 34 injection wells at Little Creek. Based on the results of
the two earliest phases of CO2 flooding at Little Creek, tertiary recovery has
increased the ultimate recovery factor in the flooded portion of the field by
approximately 17%, as compared to recoveries of approximately 20% for primary
recovery and 18% for secondary recovery. The field has produced a cumulative 16
MMBbls (gross) of light sweet crude, as a result of tertiary operations, and we
currently estimate that an additional 6.1 MMBbls (gross) can be recovered.
Production from Little Creek Field was approximately 1,350 Bbls/d when we
acquired the field in 1999. During the fourth quarter of 2004, production had
increased to an average of 2,989 BOE/d (including Lazy Creek). We expect the
production from Little Creek to increase further during 2005 by another 150 to
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Denbury Resources Inc.
250 BOE/d. From inception through December 31, 2004, we had net positive cash
flow (revenues less operating expenses and capital expenditures) from Little
Creek (including Lazy Creek) of $48.5 million (at the field level), plus the
fields have a PV-10 Value, using December 31, 2004 SEC NYMEX pricing, of $122.3
million.
We purchased West Mallalieu Field in May 2001. Shell Oil Company unitized
West Mallalieu Field and commenced a pilot project in 1986. The pilot project,
consisting of four 5-spot patterns, has cumulatively produced approximately 2.1
MMBbls of oil as a result of CO2 flooding. We have expanded the pilot project by
adding four additional patterns during 2001, four patterns in 2002, three
patterns in 2003, and two patterns in 2004. We also completed our first pattern
in East Mallalieu during 2004. During 2002 we began to see initial response to
CO2 injection as the West Mallalieu Field averaged 778 Bbls/d during the fourth
quarter of 2002. Response continued throughout 2003 and 2004, averaging 3,712
Bbls/d during the fourth quarter of 2004. In contrast to Little Creek Field,
West Mallalieu Field was not waterflooded prior to CO2 injection. Therefore, we
believe that the tertiary recovery of oil from West Mallalieu Field as a result
of CO2 injection could exceed the 17% of original oil in place that we expect
from Little Creek Field.
We purchased McComb Field in 2002, a field with no pilot programs or
tertiary operations at that time and virtually no current oil production. McComb
is very close in proximity and analogous to Little Creek and Mallalieu Fields.
We commenced tertiary recovery operations in 2003 by substantially completing
two patterns, and by November 2003 had started injecting CO2. Significant
development occurred during 2004 as we expanded the nearby Olive Field CO2
facility to handle the processing of McComb's produced oil, water and CO2 and
developed an additional four patterns. The production response occurred earlier
than expected, with the field averaging 540 Bbls/d in the fourth quarter of
2004. During 2005, we expect to add three patterns within McComb Field and
further expand the production facilities. In addition, we also started our
initial work on an additional CO2 flood at nearby Smithdale Field during 2004
utilizing the same CO2 facilities, with CO2 injections expected to begin in
early 2005. We believe that the total potential at McComb and Smithdale Fields
is significantly higher than the current proved reserves (at McComb only), and
therefore expect to add additional reserves and have upward reserve revisions
here over the next several years as we fully develop these fields.
Initial development of the Brookhaven Field, a field acquired during 2002
in the COHO acquisition, began in late 2004 with the first injections of CO2 in
January 2005. During 2005, we plan to complete development of the two patterns
initiated in 2004 and develop an additional seven patterns, but do not expect
any significant production response from this field until early 2006.
At December 31, 2004, we have proved reserves of 50.5 MMBbls relating to
our tertiary recovery operations. Through December 31, 2004, we have spent a
total of $155.6 million on fields in this area, and have received $160.0 million
in net operating income (revenue less operating expenses), or net positive cash
flow of $4.4 million. These amounts do not include the capital costs or related
depreciation and amortization of our CO2 producing properties at Jackson Dome,
which had a net unrecovered cost balance of $75.4 million as of December 31,
2004. At year-end 2004, the proved oil reserves in our CO2 fields had a PV-10
Value, using December 31, 2004 SEC NYMEX pricing, of $782.9 million.
Heidelberg and East Mississippi
We own interests in 477 wells in the eastern part of the Mississippi salt
basin and operate 436 of these wells (91%) from our regional office in Laurel,
Mississippi. These fields produced an average of 10,601 Bbls/d and 17.8 MMcf/d
during the fourth quarter of 2004. We have been active in this area since
Denbury was founded in 1990 and are by far the largest producer in the basin, as
well as in the state of Mississippi. Since we have generally owned these eastern
Mississippi properties longer than properties in our other regions, they tend to
be more fully developed. During 2004, we spent a total of approximately $38.4
million (excluding acquisitions), drilling 53 wells and performing various
workovers and recompletions. Production in eastern Mississippi averaged 13,085
BOE/d during 2004, down slightly from the 2003 average of 13,638 BOE/d. For
2005, we expect our budget in this region for conventional operations to be a
little lower than it was in 2004, approximately $28.6 million, or 9% of our
current 2005 exploration and development budget of $305 million (including the
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Denbury Resources Inc.
East Mississippi CO2 pipeline), and as discussed above, we have budgeted an
additional $50.2 million to initiate three tertiary recovery projects at
Martinville, Soso and Eucutta Fields.
The fields in this region are characterized by structural traps that
generate prolific production from stacked or multiple pay sands. As such, they
provide opportunities to increase reserves through infield drilling,
recompleting wells, improving production efficiency, and in some cases, by water
flooding producing reservoirs. Most of our wells in this area produce large
amounts of saltwater and require large pumps, which increase the operating costs
per barrel relative to our properties in Louisiana that are predominantly
natural gas producers. We plan to continue our basic strategy in this region,
supplemented by additional waterflooding (secondary recovery) and tertiary
operations.
The largest field in the region, and our largest field corporately, is
Heidelberg Field, which for the fourth quarter of 2004 produced an average of
8,266 BOE/d. Heidelberg Field was acquired from Chevron in December 1997. This
field was discovered in 1944 and has produced an estimated 204 MMBbls of oil and
57 Bcf of gas since its discovery. 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 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 primary oil production at Heidelberg is from five waterflood units that
produce from the Eutaw formation (at approximately 4,400 feet). These units are
generally developed although they will require additional work and capital for
the next few years. In addition, Heidelberg is our second largest gas field. We
began extensive development of the Selma Chalk natural gas reservoir at a depth
of 3,700 feet in 2000 and 2001. Previous operators had only partially developed
this formation in order to provide fuel gas for the rest of the field. We
drilled 13 to 15 wells each year in 2001, 2002 and 2003, with an additional 24
natural gas wells drilled in 2004, increasing the natural gas production at
Heidelberg to an average for 2004 of approximately 13.8 MMcf/d. We believe that
there are opportunities to expand the field limits, to continue reducing the
well spacing and to stimulate the Upper Selma Chalk to achieve additional gas
reserves in the Selma Chalk. We plan to drill 16 additional gas wells here
during 2005, including our first horizontal test in the Selma Chalk.
Eucutta Field
Eucutta Field was purchased from Amerada Hess in 1995. The field is very
analogous to Heidelberg field in that the majority of its historical production
was produced from the Eutaw formation. Eucutta was unitized for water flooding
in 1966 and has gone through several stages of development. During the 1980's,
Amerada Hess installed an inverted 5-spot pilot test in the City Bank sand (one
of the Eutaw sands) to test the application of CO2 flooding. Although the pilot
test only covered approximately 20 acres, the pilot test was successful in
recovering an additional 17% of the original oil in place within the pattern.
Based on this success, we have designed a CO2 project for the Eucutta Field and
plan to build our CO2 facilities and develop three patterns during 2005. Initial
injection of CO2 is projected to commence mid-2006, although it could start
earlier if our CO2 pipeline to East Mississippi is completed sooner.
Soso Field
Soso Field was purchased from COHO Resources in 2002. Although this field
produces from numerous sands, the majority of our work in 2005 will involve the
building of CO2 facilities and establishing two patterns in the Bailey sand and
two partial patterns in the Cotton Valley sands. This field has not had any
previous CO2 injection or pilot projects. In reviewing Soso Field we studied the
Bailey sand which was one of the more prolific reservoirs within the field and
exhibited characteristics of a depletion drive reservoir. The Bailey reservoir
oil is 43.4 API gravity, similar to our West Mississippi floods, and is at
approximately the same depth and has very similar reservoir characteristics,
thus we expect the Bailey tertiary flood to perform in a similar manner to our
West Mississippi CO2 floods.
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Denbury Resources Inc.
Martinville Field
Martinville field was purchased from COHO Resources in 2002. As is the case
with all of the East Mississippi fields, Martinville produces from multiple
reservoirs. Unlike the majority of our other planned CO2 projects, Martinville
does not contain one very large reservoir to CO2 flood, but rather several
smaller reservoirs. We have identified three CO2 formations at Martinville on
which we plan to initiate CO2 flooding following completion of our East
Mississippi CO2 pipeline. The first reservoir to be CO2 flooded is the
Mooringsport, which, because it has been waterflooded very successfully, is
expected to CO2 flood successfully as well. We plan to install the required CO2
facilities and essentially complete the development of the Mooringsport during
2005. The second reservoir, the Rodessa, has similar reservoir characteristics
to the Mooringsport. We expect to initiate injection into the Rodessa with the
completion of one injector. The final reservoir is the Wash Fred 8500'
reservoir. This reservoir contains a low gravity oil, 15 API, which will clearly
not develop miscibility with CO2 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 gravity oil and a strong water drive which does not
drive the oil efficiently. We plan to initiate injection into the Wash Fred
8500' reservoir at the crest of the structure, allow the CO2 to swell the oil,
decrease the oil viscosity, and displace the water and oil downward in the
reservoir to the producing wells. Successful implemention of a CO2 project in
the Wash Fred 8500' reservoir would provide the impetus to look at a whole new
set of fields that have historically not been considered for CO2 injection,
although there can be no assurance that this technique will be successful or
economic.
Texas and the Barnett Shale
We own about 20,000 acres of leases and working interest in 29 wells in the
Fort Worth Basin in North Central Texas that is prospective for natural gas in
the Barnett Shale. We currently operate 18 of the producing wells with
essentially 100% ownership in most of the remaining development potential. We
acquired the majority of this acreage in 2001 and have been working to find the
optimum method to drill, complete and produce the Barnett Shale. We drilled six
wells in 2001, two in 2002, five in 2003 and 18 in 2004, seven by us and 11
under a farmout arrangement where we retained a 25% working interest. During
2004 we drilled our first three horizontal wells that produced at much higher
initial rates and declined slower than our previous vertical wells. As a result
of this initial success, we expanded our 2004 capital budget and drilled four
additional horizontal wells. The average initial producing rate for these 2004
horizontal wells is approximately 2 MMcf/d. We are still refining our fracturing
technique, including an analysis of the best number of fracture treatments to
adequately stimulate the entire length of our lateral sections, which can exceed
4,000 feet. Initial reserve estimates for these horizontal wells appear to be 3
to 4 times greater than the vertical wells we initially drilled. Although our
production during the fourth quarter of 2004 averaged only 4.4 MMcf/d, we expect
production in this area to grow substantially during 2005. During 2005, we plan
to drill approximately 25 horizontal wells. Including seismic costs and pipeline
infrastructure costs, our planned 2005 capital expenditures in the Barnett Shale
is estimated to be $31 million of our $305 million capital budget (including the
East Mississippi CO2 Pipeline).
During 2004, we also committed the necessary capital to shoot 3-D seismic
data over our entire acreage position, 50 to 60 square miles. We received our
first seismic data in February 2005 and expect to have the majority of the
remaining data by May 2005. The 3-D seismic data should allow us to 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.
During 2004, we continued to address the issue of pipeline capacity in our
area of the Barnett Shale play by installing additional pipelines to relieve
some packed lines. The largest gas purchaser in the area is installing a new 20"
gas line to handle the increasing volumes of gas in our area. In addition,
several other gas buyers and pipeline companies are entering the area and making
plans to install additional pipelines to handle the anticipated future volumes
of gas.
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Denbury Resources Inc.
South Louisiana
We own interests in 84 wells in the land and marshes of south Louisiana and
one non-operated offshore well that we did not include in our 2004 sale of
offshore properties. We operate 71 of these wells (85%) from our regional office
in Houma, Louisiana. This region produces primarily natural gas, averaging 33.7
MMcf/d net to our interest in the fourth quarter of 2004, approximately 60% of
our total natural gas production. During 2004, we spent approximately $23.7
million (excluding acquisitions) in this region, approximately 11% of our total
exploration and development expenditures, drilling approximately 10 wells,
primarily in the Thornwell and Terrebonne Parish areas. For 2005, our spending
is expected to be about the same, with a budget of $28.8 million, or 9% of our
$305 million exploration and development budget (including our East Mississippi
CO2 pipeline).
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. The advent
of 3D seismic data in these geologically complex areas has become a valuable
tool in exploration and development. We currently own or have a license covering
over 1,000 square miles of 3D data, and plan to expand our data ownership during
2005. During 2004, we expanded our seismic holdings in this area by acquiring an
additional 188 square miles of 3D data. We drilled seven wells in Terrebonne
Parish during 2004, four of which were successful. In 2005, we plan to drill
approximately six exploratory wells in Terrebonne Parish and three development
wells.
Historically we have had good success with a shallow natural gas play in
Terrebonne Parish. These shallow gas reservoirs are approximately 3,000 feet
deep, but have the ability to produce from 1.0 to 4.0 MMcf/d. During 2004, we
drilled one successful and one unsuccessful well. We plan to drill an additional
6 shallow gas prospects in Terrebonne Parish during 2005, with another 5 to 15
additional shallow gas prospects in Terrebonne Parish under review.
Thornwell Field is characterized by short-life natural gas properties that
have high initial production rates with a good rate of return, but which are
depleted in two to three years. The high rates of decline have dramatically
impacted our overall production rates the last two years, and are expected to
continue to do so throughout 2005. Production at Thornwell Field averaged 4,275
BOE/d in 2001, 3,910 BOE/d in 2002, 2,564 BOE/d in 2003 and 1,487 BOE/d in 2004,
and is expected to average approximately 750 BOE/d during 2005. Even though this
field has negatively affected our overall production growth, the purchase and
development of this field has been profitable. We had significant activity at
this field during 2001 and 2002, with positive results, but reduced our activity
during 2003 and 2004 as the field became more fully developed. Our plans for
2005 include the drilling of one exploratory well to test the Marg Tex/Bol Mex
sands and two development wells in the Bol Perc. From inception through December
31, 2004, we have net positive cash flow (revenue less operating expenses and
capital expenditures) to date of $37.0 million from this field, with a remaining
proved PV-10 Value, using December 31, 2004 constant SEC NYMEX pricing, of $37.4
million.
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Denbury Resources Inc.
FIELD SUMMARIES
Denbury operates in four primary areas: Louisiana, Eastern Mississippi,
Western Mississippi and Texas. Our 11 largest fields (listed below) constitute
approximately 90% of our total proved reserves on a BOE basis and 89% on a PV-10
Value basis. Within these 11 fields, we own a weighted average 89% 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 two primary field offices in Houma,
Louisiana, and Laurel, Mississippi.
Average
Daily
Proved Reserves as of December 31, 2004 (1) Production (2)
-------------------------------------------------------- ----------------------
Natural Average Net
Oil Natural Gas MBOE's BOE PV-10 Value Oil Gas Revenue
(MBbls) (MMcf) (000's) % of total (000's) (Bbls/d) (Mcf/d) Interest
- ---------------------------------------------------------------------------------------- ---------------------- ------------
Mississippi - CO2 floods
Brookhaven................... 18,707 - 18,707 14.5% $ 185,962 - - 80.7%
Mallalieu (East & West)...... 14,888 - 14,888 11.5% 316,010 3,351 - 80.6%
McComb/Olive................. 10,666 - 10,666 8.2% 158,583 285 - 75.1%
Little Creek & Lazy Creek.... 6,271 - 6,271 4.8% 122,320 3,148 - 83.2%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Total Mississippi-CO2 floods 50,532 - 50,532 39.0% 782,875 6,784 - 79.7%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Other Mississippi
Heidelberg (East & West).... 32,577 56,575 42,006 32.5% 364,656 5,476 13,794 76.9%
Eucutta..................... 4,485 - 4,485 3.5% 42,391 1,162 - 65.7%
King Bee.................... 2,203 - 2,203 1.7% 22,126 460 - 79.9%
Brookhaven (non-CO2)........ 1,515 - 1,515 1.2% 25,718 380 - 76.7%
Other Mississippi........... 8,047 6,728 9,168 7.1% 98,483 2,991 1,898 10.2%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Total Other Mississippi... 48,827 63,303 59,377 46.0% 553,374 10,469 15,692 38.1%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Louisiana
Lirette..................... 97 7,029 1,269 1.0% 31,778 300 13,704 61.6%
S. Chauvin.................. 372 11,169 2,234 1.7% 47,485 141 3,522 38.7%
Thornwell................... 411 6,061 1,421 1.1% 37,437 259 7,367 35.0%
Other Louisiana............. 1,048 18,627 4,153 3.2% 90,411 847 11,906 39.9%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Total Louisiana........... 1,928 42,886 9,077 7.0% 207,111 1,547 36,499 40.7%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Texas
Newark (Barnett Shale)...... - 62,295 10,383 8.0% 99,929 127 2,754 63.1%
---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------
Company Total ................ 101,287 168,484 129,369 100.0% $1,643,289 18,927 54,945 51.5%
========== =========== ========== =========== =========== =========== ========== ============
(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, 2004. The prices at that date were a NYMEX
oil price of $43.45 per Bbl adjusted to prices received by field and a NYMEX natural gas price average of
$6.15 per MMBtu also adjusted to prices received by field.
(2) Does not include production on the Company's offshore properties sold in July 2004. The total average annual
production on these properties for 2004 was 319 Bbls/d and 27.3 MMcf/d.
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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,
2004:
Developed Undeveloped Total
-------------------------- -------------------------- --------------------------
Gross Net Gross Net Gross Net
------------- ------------ ------------ ------------ ------------ ------------
Louisiana........... 39,867 31,214 25,686 19,440 65,553 50,654
Mississippi......... 92,038 71,416 256,734 36,647 348,772 108,063
Texas, other........ 15,353 10,043 92,478 18,855 107,831 28,898
------------- ------------ ------------ ------------ ------------ ------------
Total............ 147,258 112,673 374,898 74,942 522,156 187,615
============= ============ ============ ============ ============ ============
Denbury's net undeveloped acreage that is subject to expiration over the
next three years is approximately 7% in 2005, 11% in 2006 and 9% in 2007.
Productive Wells
The following table sets forth our gross and net productive oil and natural
gas wells at December 31, 2004:
Producing Natural
Producing Oil Wells Gas Wells Total
-------------------------- -------------------------- -------------------------
Gross Net Gross Net Gross Net
------------ ------------- ------------ ------------- ------------ ------------
Operated Wells:
Louisiana................ 32 25.7 39 30.9 71 56.6
Mississippi.............. 441 422.0 104 94.1 545 516.1
Offshore Gulf Coast...... - - - - - -
Texas, other............. - - 18 17.0 18 17.0
------------ ------------- ------------ ------------- ------------ ------------
Total.................. 473 447.7 161 142.0 634 589.7
============ ============= ============ ============= ============ ============
Non-Operated Wells:
Louisiana................ - - 13 3.4 13 3.4
Mississippi.............. 24 2.4 17 5.2 41 7.6
Offshore Gulf Coast...... - - 1 0.8 1 0.8
Texas, other............. - - 11 2.8 11 2.8
------------ ------------- ------------ ------------- ------------ ------------
Total.................. 24 2.4 42 12.2 66 14.6
============ ============= ============ ============= ============ ============
Total Wells:
Louisiana................ 32 25.7 52 34.3 84 60.0
Mississippi.............. 465 424.4 121 99.3 586 523.7
Offshore Gulf Coast...... - - 1 0.8 1 0.8
Texas, other............. - - 29 19.8 29 19.8
------------ ------------- ------------ ------------- ------------ ------------
Total.................. 497 450.1 203 154.2 700 604.3
============ ============= ============ ============= ============ ============
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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,
--------------------------------------------------------------------------------
2004 2003 2002
-------------------------- -------------------------- --------------------------
Gross Net Gross Net Gross Net
------------ ------------ ------------ ------------- ------------ -------------
Exploratory Wells:(1)
Production(2) 8 5.8 7 5.3 7 4.9
Non-productive(3) 4 2.3 7 4.8 4 3.2
Development Wells:(1)
Productive(2) 68 53.8 37 31.3 33 27.1
Non-productive(3)(4) 1 0.6 3 1.2 2 1.9
------------ ------------ ------------ ------------- ------------ -------------
Total 81 62.5 54 42.6 46 37.1
============ ============ ============ ============= ============ =============
(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 2004, 2003 and 2002, an additional 8, 5, and 9 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.
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Denbury Resources Inc.
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, 2004, we had two purchasers
that each accounted for 10% or more of our oil and natural gas revenues: Hunt
Refining (21%) and Genesis Energy, L.P. (14%). For the year ended December 31,
2003, two purchasers each accounted for more than 10% of our total oil and
natural gas revenues: Hunt Refining (15%) and Genesis Energy, L.P. (12%). For
the year ended December 31, 2002, two purchasers each accounted for 10% or more
of our oil and natural gas revenues: Hunt Refining (14%) and Genesis Energy,
L.P. (11%).
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, our single largest field, 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, our current CO2 operations, and in Louisiana, 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, 2004, the discount for our
oil production from Heidelberg Field averaged $9.80 per Bbl and for our Eastern
Mississippi properties as a whole the discount averaged $8.84 per Bbl relative
to NYMEX oil prices. For Mallalieu Field, the largest producer during 2004 of
our CO2 properties in Western Mississippi, we averaged a premium of $1.20 per
Bbl over NYMEX oil prices, and $1.13 per Bbl over NYMEX prices for our tertiary
oil production in Western Mississippi taken as a whole. Our Louisiana properties
averaged $2.39 per Bbl below NYMEX prices during 2004.
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.
OPERATING ENVIRONMENT RISK FACTORS
Oil and Natural Gas Price Volatility
Our future financial condition, results of operations and the carrying
value of our oil and natural gas properties depends primarily upon the prices we
receive for our oil and natural gas production. Oil and natural gas prices
historically have been volatile and likely will continue to be volatile in the
future, especially given current world geopolitical conditions. Our cash flow
from operations is highly dependent on the prices that we receive for oil and
natural gas. This price volatility also affects the amount of our cash flow
available for capital expenditures and our ability to borrow money or raise
additional capital. The amount we can borrow or have outstanding under our bank
credit facility is subject to semi-annual redeterminations. In the short-term,
our production is relatively balanced between oil and natural gas, but
long-term, oil prices are likely to affect us more than natural gas prices
because approximately 78% of our proved reserves are oil. The prices for oil and
natural gas are subject to a variety of additional factors that are beyond our
control. These factors include:
o the level of consumer demand for oil and natural gas;
o the domestic and foreign supply of oil and natural gas;
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Denbury Resources Inc.
o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
o the price of foreign oil and natural gas;
o domestic governmental regulations and taxes;
o the price and availability of alternative fuel sources;
o weather conditions;
o market uncertainty;
o political conditions in oil and natural gas producing regions,
including the Middle East; and
o worldwide economic conditions.
These factors and the volatility of the energy markets generally make it
extremely difficult to predict future oil and natural gas price movements with
any certainty. Also, oil and natural gas prices do not necessarily move in
tandem. Declines in oil and natural gas prices would not only reduce revenue,
but could reduce the amount of oil and natural gas that we can produce
economically and, as a result, could have a material adverse effect upon our
financial condition, results of operations, oil and natural gas reserves and the
carrying values of our oil and natural gas properties. If the oil and natural
gas industry experiences significant price declines, we may, among other things,
be unable to meet our financial obligations or make planned expenditures.
Since the end of 1998, oil prices have gone from near historic low prices
to historic highs. At the end of 1998, NYMEX oil prices were at historic lows of
approximately $12.00 per Bbl, but have generally increased since that time,
albeit with fluctuations. For 2004, NYMEX oil prices were high throughout the
year, averaging over $41.00 per Bbl, ending the year at $43.45 per Bbl. During
2004, the price we received for our heavier, sour crude oil did not correlate as
well with NYMEX prices as it has historically. During 2002 and 2003, our average
discount to NYMEX was $3.73 per Bbl and $3.60 per Bbl respectively. During 2004,
this differential increased to $4.91 per Bbl for the year as a result of the
price deterioration for heavier, sour crudes, and was even higher during the
fourth quarter, averaging $6.48 per Bbl. While we attempt to obtain the best
price for our crude in our marketing efforts, we cannot control these market
price swings and are subject to the market volatility for this type of oil.
These price differentials relative to NYMEX prices can have as much of an impact
on our profitability as does the volatility in the NYMEX oil prices.
Natural gas prices have also experienced volatility during the last few
years. During 1999 natural gas prices averaged approximately $2.35 per Mcf and,
like crude oil, have generally trended upward since that time, although with
significant fluctuations along the way. For 2004, NYMEX natural gas prices
averaged over $6.00 per MMBtu, ending the year at $6.15 per MMBtu.
Product Price Derivative Hedging Contracts
To reduce our exposure to fluctuations in the prices of oil and natural
gas, we currently and may in the future enter into hedging arrangements for a
portion of our oil and natural gas production. Hedging arrangements expose us to
risk of financial loss in some circumstances, including when:
o production is less than expected;
o the counter-party to the hedging contract defaults on its contract
obligations (as was the case with respect to our hedges placed in 2001
with an Enron subsidiary as counterparty, which resulted in our
suffering a loss); or
o there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received.
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Denbury Resources Inc.
In addition, these hedging arrangements may limit the benefit we would
receive from increases in the prices for oil and natural gas. Information as to
these activities is set forth under "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Market Risk Management," and in
Note 9, "Derivative Hedging Contracts," to the Consolidated Financial
Statements.
Oil and Natural Gas Drilling and Producing Operations
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be discovered. There can be no assurance
that new wells drilled by us will be productive or that we will recover all or
any portion of our investment in such wells. Drilling for oil and natural gas
may involve unprofitable efforts, not only from dry wells but also from wells
that are productive but do not produce sufficient net reserves to return a
profit after deducting drilling, operating and other costs. The seismic data and
other technologies used by us do not provide conclusive knowledge, prior to
drilling a well, that oil or natural gas is present or may be produced
economically. The cost of drilling, completing and operating a well is often
uncertain, and cost factors can adversely affect the economics of a project.
Further, our drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, including:
o unexpected drilling conditions;
o title problems;
o pressure or irregularities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o compliance with environmental and other governmental requirements; and
o cost of, or shortages or delays in the availability of, drilling rigs,
equipment and services.
Our operations are subject to all the risks normally incident to the
operation and development of oil and natural gas properties and the drilling of
oil and natural gas wells, including encountering well blowouts, cratering and
explosions, pipe failure, fires, formations with abnormal pressures,
uncontrollable flows of oil, natural gas, brine or well fluids, release of
contaminants into the environment and other environmental hazards and risks.
In accordance with industry practice, we maintain insurance against some,
but not all, of the risks described above in an amount we believe is adequate.
However, the nature of these risks is such that some liabilities could exceed
our policy limits, or, as in the case of environmental fines and penalties,
cannot be insured. We could incur significant costs, related to these risks,
that could have a material adverse effect on our results of operations,
financial condition and cash flows.
Use of Carbon Dioxide in Tertiary Recovery Operations
The crude oil production from our tertiary recovery projects depends on
having access to sufficient amounts of carbon dioxide. Our ability to produce
this oil would be hindered if our supply of carbon dioxide were limited due to
problems with our current CO2 producing wells and facilities, including
compression equipment, or catastrophic pipeline failure. Our anticipated future
production is also dependent on our ability to increase the production volumes
of CO2. If our crude oil production were to decline, it could have a material
adverse effect on our financial condition and results of operations. Our CO2
tertiary recovery projects require a significant amount of electricity to
operate the facilities. If these costs were to increase significantly, it could
have a material adverse effect upon the profitability of these operations.
Future Performance and Acquisitions
Unless we can successfully replace the reserves that we produce, our
reserves will decline, resulting eventually in a decrease in oil and natural gas
production and lower revenues and cash flows from operations. We have
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Denbury Resources Inc.
historically replaced reserves through both drilling and acquisitions. In the
future we may not be able to continue to replace reserves at acceptable costs.
The business of exploring for, developing or acquiring reserves is capital
intensive. We may not be able to make the necessary capital investment to
maintain or expand our oil and natural gas reserves if our cash flows from
operations are reduced, due to lower oil or natural gas prices or otherwise, or
if external sources of capital become limited or unavailable. Further, the
process of using CO2 for tertiary recovery and the related infrastructure
requires significant capital investment, often one to two years prior to any
resulting production and cash flows from these projects, heightening potential
capital constraints. If we do not continue to make significant capital
expenditures, or if outside capital resources become limited, we may not be able
to maintain our growth rate. In addition, our drilling activities are subject to
numerous risks, including the risk that no commercially productive oil or
natural gas reserves will be encountered. Exploratory drilling involves more
risk than development drilling because exploratory drilling is designed to test
formations for which proved reserves have not been discovered.
We are continually identifying and evaluating acquisition opportunities and
we have successfully completed acquisitions throughout our history. Estimating
the reserves and forecasted production from acquired properties is inherently
difficult and may result in our inability to achieve or maintain targeted
production levels. In that case, our ability to realize the total economic
benefit from the acquisition may be reduced or eliminated. There can be no
assurance that we will successfully consummate any future acquisitions or that
such acquisitions of oil and natural gas properties will contain economically
recoverable reserves or that any future acquisition will be profitably
integrated into our operations.
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 long-lived, high margin nature of our oil and gas reserves and
management's experience and expertise in exploiting these reserves, 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 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
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Denbury Resources Inc.
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 which 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,
the price and terms of access to pipeline transportation are subject to
extensive U.S. federal and state regulation. The Federal Energy Regulatory
Commission ("FERC") is continually proposing and implementing new rules and
regulations affecting the natural gas industry. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry. The ultimate impact of the complex rules and
regulations issued by FERC cannot be predicted. Some of FERC's proposals may,
however, adversely affect the availability and reliability of interruptible
transportation service on interstate pipelines. While our sales of crude oil,
condensate and natural gas liquids are not currently subject to FERC regulation,
our ability to transport and sell such products is dependent on certain
pipelines whose rates, terms and conditions of service are subject to FERC
regulation. Additional proposals and proceedings that might affect the natural
gas industry are considered from time to time by Congress, FERC, state
regulatory bodies and the courts. We cannot predict when or if any such
proposals might become effective and their effect, if any, on our operations.
Historically, the natural gas industry has been heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by FERC, Congress and the states will continue indefinitely into the
future.
Natural Gas Gathering Regulations
State regulation of natural gas gathering facilities generally include
various safety, environmental and, in some circumstances, nondiscriminatory-take
requirements. Although such regulation has not generally been affirmatively
applied by state agencies, natural gas gathering may receive greater regulatory
scrutiny in the future.
Federal, State or Indian Leases
Our operations on federal, state or Indian oil and gas leases are subject
to numerous restrictions, including nondiscrimination statutes. Such operations
must be conducted pursuant to certain on-site security regulations and other
permits and authorizations issued by the Bureau of Land Management, Minerals
Management Service ("MMS") and other agencies.
Environmental Regulations
Public interest in the protection of the environment has increased
dramatically in recent years. Our oil and natural gas production and saltwater
disposal operations and our processing, handling and disposal of hazardous
materials, such as hydrocarbons and naturally occurring radioactive materials
are subject to stringent regulation. We could incur significant costs, including
cleanup costs resulting from a release of hazardous material, third-party claims
for property damage and personal injuries fines and sanctions, as a result of
any violations or liabilities under environmental or other laws. Changes in or
more stringent enforcement of environmental laws could also result in additional
operating costs and capital expenditures.
19
Denbury Resources Inc.
Various federal, state and local laws regulating the discharge of materials
into the environment, or otherwise relating to the protection of the
environment, directly impact oil and gas exploration, development and production
operations, and consequently may impact the Company's operations and costs.
These regulations include, among others, (i) regulations by the EPA and various
state agencies regarding approved methods of disposal for certain hazardous and
nonhazardous wastes; (ii) the Comprehensive Environmental Response,
Compensation, and Liability Act, Federal Resource Conservation and Recovery Act
and analogous state laws which regulate the removal or remediation of previously
disposed wastes (including wastes disposed of or released by prior owners or
operators), property contamination (including groundwater contamination), and
remedial plugging operations to prevent future contamination; (iii) the Clean
Air Act and comparable state and local requirements which may result in the
gradual imposition of certain pollution control requirements with respect to air
emissions from the operations of the Company; (iv) the Oil Pollution Act of 1990
which contains numerous requirements relating to the prevention of and response
to oil spills into waters of the United States; (v) the Resource Conservation
and Recovery Act which is the principal federal statute governing the treatment,
storage and disposal of hazardous wastes; and (vi) state regulations and
statutes governing the handling, treatment, storage and disposal of naturally
occurring radioactive material ("NORM").
Management believes that we are in substantial compliance with applicable
environmental laws and regulations. To date, we have not expended any material
amounts to comply with such regulations, and management does not currently
anticipate that future compliance will have a materially adverse effect on our
consolidated financial position, results of operations or cash flows.
ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES AND PRESENT VALUE OF
ESTIMATED FUTURE NET REVENUES
DeGolyer and MacNaughton, independent petroleum engineers located in
Dallas, Texas, prepared estimates of our net proved oil and natural gas reserves
as of December 31, 2004, 2003 and 2002. The reserve estimates were prepared
using constant prices and costs in accordance with the guidelines of the
Securities and Exchange Commission ("SEC"). The prices used in preparation of
the reserve estimates were based on the market prices in effect as of December
31 of each year, with the appropriate adjustments (transportation, gravity,
basic sediment and water "BS&W," purchasers' bonuses, Btu, etc.) applied to each
field. The reserve estimates do not include any value for probable or possible
reserves that may exist, nor do they include any value for undeveloped acreage.
The reserve estimates represent our net revenue interests in our properties.
Our proved nonproducing reserves primarily relate to reserves that are to
be recovered from productive zones that are currently behind pipe. Since a
majority of our properties are in areas with multiple pay zones, these
properties typically have both proved producing and proved nonproducing
reserves.
Proved undeveloped reserves associated with our CO2 tertiary operations in
West Mississippi and our Heidelberg waterfloods in East Mississippi account for
approximately 96% of our proved undeveloped oil reserves. We consider these
reserves to be lower risk than other proved undeveloped reserves that require
drilling at locations offsetting existing production because all of these proved
undeveloped reserves are associated with secondary recovery or tertiary recovery
operations in fields and reservoirs that historically produced substantial
volumes of oil under primary production. The main reason these reserves are
classified as undeveloped is because they require significant additional capital
associated with drilling/re-entering wells or additional facilities in order to
produce the reserves and/or are waiting for a production response to the water
or CO2 injections.
20
Denbury Resources Inc.
Our proved undeveloped natural gas reserves, associated with our Selma
Chalk play at Heidelberg and the Barnett Shale play in Newark, East fields
account for approximately 87% of our proved undeveloped natural gas reserves.
The remaining undeveloped natural gas reserves are spread over multiple fields
with the single largest field accounting for less than 5% of the total
undeveloped natural gas reserves. This particular field's undeveloped reserves
are currently being developed with first production expected late in the first
quarter of 2005. Our current plans for 2005 include development of 20 to 25
wells in each of our primary natural gas plays, the Barnett Shale and Selma
Chalk.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------------
2004 2003 2002
---------------- --------------- ----------------
ESTIMATED PROVED RESERVES:
Oil (MBbls).................................................. 101,287 91,266 97,203
Natural gas (MMcf)........................................... 168,484 221,887 200,947
Oil equivalent (MBOE)........................................ 129,369 128,247 130,694
PERCENTAGE OF TOTAL MBOE:
Proved producing............................................. 39% 43% 43%
Proved non-producing......................................... 16% 18% 23%
Proved undeveloped........................................... 45% 39% 34%
REPRESENTATIVE OIL AND GAS PRICES:(1)
Oil - NYMEX.................................................. $ 43.45 $ 32.52 $ 31.20
Natural gas - NYMEX Henry Hub................................ 6.15 6.19 4.79
PRESENT VALUES:(2)
Discounted estimated future net cash flow before
income taxes ("PV-10 Value") (thousands)................... $ 1,643,289 $ 1,566,371 $ 1,426,220
Standardized measure of discounted estimated future net
cash flow after income taxes (thousands)................... 1,129,196 1,124,127 1,028,976
(1) The prices of each year-end were based on market prices in effect as of December 31 of each year, NYMEX prices
per Bbl and NYMEX Henry Hub prices per MMBtu, with the appropriate adjustments (transportation, gravity, BS&W,
purchasers' bonuses, Btu, etc.) applied to each field to arrive at the appropriate corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC,
discounted at 10% per annum.
There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and their values, including many factors
beyond our control. The reserve data included herein represents only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the quality of available
geological, geophysical, engineering and economic data, the precision of the
engineering and judgment. As a result, estimates of different engineers often
vary. The estimates of reserves, future cash flows and present value are based
on various assumptions, including those prescribed by the SEC relating to oil
and natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds, and are inherently imprecise. Actual future
production, cash flows, taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves may vary substantially
from our estimates. Such variations may be significant and could materially
affect estimated quantities and the present value of our proved reserves. Also,
the use of a 10% discount factor for reporting purposes may not necessarily
represent the most appropriate discount factor, given actual interest rates and
risks to which Denbury or the oil and natural gas industry in general are
subject. See also Note 13, "Supplemental Oil and Natural Gas Disclosures," to
the Consolidated Financial Statements.
You should not assume that the present values referred to herein represent
the current market value of our estimated oil and natural gas reserves. In
accordance with requirements of the SEC, the estimates of present values are
based on prices and costs as of the date of the estimates. Actual future prices
and costs may be materially higher or lower than the prices and costs as of the
date of the estimate.
Quantities of proved reserves are estimated based on economic conditions,
including oil and natural gas prices in existence at the date of assessment. Our
21
Denbury Resources Inc.
reserves and future cash flows may be subject to revisions based upon changes in
economic conditions, including oil and natural gas prices, as well as due to
production results, results of future development, operating and development
costs and other factors. Downward revisions of our reserves could have an
adverse affect on our financial condition, operating results and cash flows.
ITEM 2. PROPERTIES
- --------------------
See Item 1. Business - "Oil and Gas Operations." We also have various
operating leases for rental of office space, office and field equipment, and
vehicles. See "Off-Balance Sheet Agreements - Commitments and Obligations" in
Management's Discussion and Analysis of Financial Condition and Results of
Operations, and Note 10, "Commitments and Contingencies," to the Consolidated
Financial Statements for the future minimum rental payments. Such information is
incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS
- --------------------------
We are involved in various lawsuits, claims and regulatory proceedings
incidental to our businesses, including those noted below. While we currently
believe that the ultimate outcome of these proceedings, individually and in the
aggregate, will not have a material adverse effect on our financial position or
overall trends in results of operations or cash flows, litigation is subject to
inherent uncertainties. If an unfavorable ruling were to occur, there exists the
possibility of a material adverse impact on our net income in the period in
which the ruling occurs. We provide accruals for litigation and claims if we
determine that we may have a range of legal exposure that would require accrual.
The estimate of the potential impact from the following legal proceedings on our
financial position or overall results of operations could change in the future.
Along with two other companies, we have been named in a lawsuit styled J.
Paulin Duhe, Inc. vs. Texaco, Inc., et al, Cause No. 101,227, filed in late 2003
in the 16th Judicial District Court, Division "E", Terrebonne Parish, Louisiana,
seeking restoration to its original condition of property on which oil has been
produced over the past 70 years. The contract and tort claims by the plaintiffs
allege surface and groundwater damage of 26 acres that are part of our Iberia
Field in Iberia Parish, Louisiana. Recently, plaintiff's experts have initially
alleged that clean-up of alleged contamination of the property would cost $79.0
million, although settlement offers by plaintiffs have already been made for
much smaller sums. The property was originally leased to Texaco, Inc. for
mineral development in 1934 and Denbury acquired its interest in the property in
August 2000 from Manti Operating Company. Discovery is currently underway, and
the April 2005 trial setting has been continued to an unspecified date in the
future. We believe that we are indemnified by the prior owner, which we expect
to cover our exposure to most damages, if any, found to have occurred prior to
the time that we purchased the property. We believe that the allegations of this
lawsuit are subject to a number of defenses, are without merit and we and the
other defendants plan to vigorously defend this lawsuit, and if necessary, we
will seek indemnification from the prior owner.
On December 29, 2003, an action styled Harry Bourg Corporation vs. Exxon
Mobil Corporation, et al, Cause No. 140749, was filed in the 32nd Judicial
District Court, Terrebonne Parish, Louisiana against Denbury and eleven other
oil companies and their predecessors alleging damage as the result of mineral
exploration activities conducted by these oil and gas operators/companies over
the last 60 years. Plaintiff has asked for restoration of the 10,000 acre
property and/or damages in claims made under tort law and various oil and gas
contracts. The Bourg Corporation recently produced its first preliminary expert
reports that allege damages of approximately $100.0 million against Denbury.
Discovery is continuing in this case, with trial currently set for January 2006.
We believe the allegations of this lawsuit are without merit and plan to
vigorously defend this lawsuit along with the other defendants. No provision has
been accrued in our financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------------------------------------------------------------
No matters were submitted for a vote of security holders during the fourth
quarter of 2004.
22
Denbury Resources Inc.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
- -------------------------------------------------------------------------------
ISSUER PURCHASES OF EQUITY SECURITIES
- -------------------------------------
Common Stock Trading Summary
The following table summarizes the high and low reported sales prices on
days in which there were trades of Denbury's common stock on the New York Stock
Exchange ("NYSE"), for each quarterly period for the last two fiscal years. As
of February 28, 2005, to the best of our knowledge, Denbury's common stock was
held of record by approximately 8,000 holders. On February 28, 2005, the last
reported sales price of Denbury's Common Stock, as reported on the NYSE, was
$32.90 per share.
2004 2003
- ---------------------------------------------- -------------------------- -------------------------
High Low High Low
- ---------------------------------------------- ------------ ------------- ------------ ------------
First Quarter $ 16.93 $ 13.26 $ 11.59 $ 10.18
Second Quarter 21.73 16.72 13.86 10.25
Third Quarter 26.20 18.59 13.95 11.65
Fourth Quarter 29.30 24.05 14.24 11.23
- ---------------------------------------------- -------------------------- -------------------------
Annual $ 29.30 $ 13.26 $ 14.24 $ 10.18
- ---------------------------------------------- -------------------------- -------------------------
We have never paid any dividends on our common stock and we currently do
not anticipate paying any dividends in the foreseeable future. Also, we are
restricted from declaring or paying any cash dividends on our common stock under
our bank loan agreement. No unregistered securities were sold by the Company
during 2004.
Equity Compensation Plan Information
The following table summarizes information about Denbury's equity
compensation plans as of December 31, 2004.
Number of securities
remaining available
for future issuance
Number of securities to Weighted average under equity
be issued upon exercise exercise price of compensation plans
of outstanding options, outstanding options, (excluding securities
warrants and rights warrants and rights reflected in column a)
Plan Category (a) (b) (c)
- ---------------------------------------- ------------------------- ------------------------- -------------------------
Equity Compensation plans
approved by security holders:
Stock Option Plan..................... 4,440,157 $ 10.49 710,291
2004 Omnibus Plan..................... - - 1,350,000
Employee Stock Purchase Plan.......... - - 291,376
Equity compensation plans
not approved by security holders:
Director Compensation Plan............ - - 71,930
------------------------- ------------------------- -------------------------
4,440,157 $ 10.49 2,423,597
========================= ========================= =========================
23
Denbury Resources Inc.
Our Director Compensation Plan was adopted effective July 1, 2000 for a
term of ten years. The Director Plan allows each non-employee director to make
an annual election to receive his or her compensation in either cash or in
shares of our common stock and to elect to defer receipt of such compensation,
if they wish. We anticipate that the Director Plan will be modified in 2005 to
no longer allow directors to defer receipt of such compensation due to the
American Jobs Creation Act of 2004. The number of shares issued to a director
who elects to receive shares of common stock under the Director Plan is
calculated by dividing the director fees to be paid to such director by the
average price of the Company's common stock for the ten trading days prior to
the date the fees are payable. Generally director's fees are paid quarterly. We
have reserved 100,000 shares for issuance under the Director Plan, for directors
who elect to receive their compensation in stock.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company's purchases of stock in the open
market during the three months ended December 31, 2004:
ISSUER PURCHASES OF EQUITY SECURITIES
- ---------------------------------------------------------------------------------------------------
(c) Total Number of (d) Maximum Number
(a) Total Shares Purchased of Shares that May
Number of (b) Average as Part of Publicly Yet Be Purchased
Shares Price Paid Announced Plans or Under the Plan Or
Period Purchased per Share Programs Programs
- ---------------------------------------------------------------------------------------------------
October 2004.......... 50,000 $ 25.28 50,000 100,000
November 2004......... - - - 100,000
December 2004......... - - - 100,000
------------ ------------------
Total............... 50,000 $ 25.28 50,000 100,000
============ ==================
In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase
shares of our common stock on the NYSE in order for such repurchased shares to
be reissued to our employees who participate in Denbury's Employee Stock
Purchase Plan. The Plan originally provided for purchases through an independent
broker of 50,000 shares of Denbury's common stock per fiscal quarter for a
period of approximately twelve months, or a total of 200,000 shares, beginning
August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of Directors
renewed the Plan for another year beginning July 1, 2004 and ending June 30,
2005, covering another 200,000 shares at the same 50,000 shares per quarter
rate. Purchases are to be made at prices and times determined at the discretion
of the independent broker, provided however that no purchases may be made during
the last ten business days of a fiscal quarter.
24
Denbury Resources Inc.
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------
(In thousands, unless otherwise noted) Year Ended December 31,
- ------------------------------------------------------------------------------------------------------------------------------
2004(1) 2003 2002 2001(1) 2000
--------------- -------------- --------------- -------------- -------------
CONSOLIDATED STATEMENTS OF
OPERATIONS DATA:
Revenues................................. $ 382,972 $ 333,014 $ 285,152 $ 285,111 $ 181,651
Net income............................... 82,448 56,553 (2) 46,795 56,550 142,227 (3)
Net income per common share:
Basic.................................. 1.50 1.05 (2) 0.88 1.15 3.10
Diluted................................ 1.44 1.02 (2) 0.86 1.12 3.07
Weighted average number of common
shares outstanding:
Basic ................................. 54,871 53,881 53,243 49,325 45,823
Diluted................................ 57,301 55,464 54,365 50,361 46,352
CONSOLIDATED STATEMENTS OF CASH
FLOW DATA:
Cash provided by (used by):
Operating activities................... $ 168,652 $ 197,615 $ 159,600 $ 185,047 $ 95,972
Investing activities................... (71,700) (135,878) (171,161) (318,830) (133,040)
Financing activities................... (66,251) (61,489) 12,005 134,986 47,593
PRODUCTION (DAILY):
Oil (Bbls)............................. 19,247 18,894 18,833 16,978 15,219
Natural gas (Mcf)...................... 82,224 94,858 100,443 85,238 37,078
BOE (6:1).............................. 32,951 34,704 35,573 31,185 21,399
UNIT SALES PRICE (EXCLUDING HEDGES):
Oil (per Bbl).......................... $ 36.46 $ 27.47 $ 22.36 $ 21.34 $ 25.89
Natural gas (per Mcf).................. 6.24 5.66 3.31 4.12 4.45
UNIT SALES PRICE (INCLUDING HEDGES):
Oil (per Bbl).......................... $ 27.36 $ 24.52 $ 22.27 $ 21.65 $ 23.50
Natural gas (per Mcf).................. 5.57 4.45 3.35 4.66 3.57
COSTS PER BOE:
Lease operations....................... $ 7.22 $ 7.06 $ 5.48 $ 4.84 $ 4.94
Production and severance taxes......... 1.55 1.17 0.92 0.96 1.02
General and administrative............. 1.78 1.20 0.96 0.89 1.09
Depletion, depreciation, and
amortization......................... 8.09 7.48 7.26 6.27 4.62
PROVED RESERVES:
Oil (MBbls)............................ 101,287 91,266 97,203 76,490 70,667
Natural gas (MMcf)..................... 168,484 221,887 200,947 198,277 100,550
MBOE (6:1)............................. 129,369 128,247 130,694 109,536 87,425
CONSOLIDATED BALANCE SHEET DATA:
Total assets........................... $ 992,706 $ 982,621 $ 895,292 $ 789,988 $ 457,379
Total long-term liabilities............ 368,128 434,845 432,616 360,882 202,428
Stockholders' equity(4)................ 541,672 421,202 366,797 349,168 216,165
(1) We sold Denbury Offshore, Inc. in July 2004. We acquired Matrix Oil and Gas Inc. in July 2001.
(2) In 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS No. 143, "Accounting
for Asset Retirement Obligations." The adoption of SFAS No. 143 increased basic and diluted net income per
common share by $0.05.
(3) In 2000, we recorded a deferred income tax benefit of $67.9 million related to the reversal of the valuation
allowance on our net deferred tax assets.
(4) We have never paid any dividends on our common stock.
25
Denbury Resources Inc.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- -------------------------------------------------------------------------------
OF OPERATIONS
- -------------
We are a growing independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi, own the largest reserves of
carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi
River, and hold significant operating acreage onshore Louisiana and in the
Barnett Shale play in Texas. Our goal is to increase the value of acquired
properties through a combination of exploitation, drilling, and proven
engineering extraction processes, including secondary and tertiary recovery
operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas),
and we have two primary field offices located in Houma, Louisiana, and Laurel,
Mississippi.
OVERVIEW
CONTINUED EXPANSION OF OUR TERTIARY OPERATIONS. Since we acquired our first
carbon dioxide tertiary flood in Mississippi over five years ago, we have
gradually increased our emphasis on these types of operations. We particularly
like this play because of its risk profile, rate of return and lack of
competition in our operating area. Generally, from East Texas to Florida, there
are no known significant natural sources of carbon dioxide except our own, and
these large volumes of CO2 that we own drive the play. Please refer to the
section entitled "CO2 Operations" for further information regarding these
operations, their potential, and the ramifications of this change in focus.
During the last few years, we have gradually increased the percentage of
our spending dedicated to CO2 and tertiary related operations. During 2002 and
2003, we spent around 25% of our capital budget on tertiary related items, spent
approximately 46% during 2004, and we further emphasized this part of our
business by budgeting over 60% of our initial 2005 capital budget for tertiary
operations. We plan to spend approximately $190 million during 2005 on tertiary
operations, including an estimated $45 million for an 84-mile pipeline to
transport CO2 from our CO2 source fields located near Jackson, Mississippi to
our planned tertiary recovery operations in East Mississippi, an expenditure
that may ultimately be financed with sources other than our cash flow. We
anticipate that the pipeline will be ready for use during the first half of 2006
to commence what we call Phase II (operations in East Mississippi) of our
tertiary recovery program (see "CO2 Operations"). Phase II will initially
consist of tertiary recovery operations at six oil fields in that region, but we
ultimately plan to expand these operations to several other oil fields in the
area, which would also be serviced by the new pipeline. Our focus on CO2
tertiary related operations is expected to impact our financial results and
certain operating statistics. See "Results of Operations - CO2 Operations -
Financial Statement Impact of CO2 Operations" below.
During 2004, we drilled four CO2 wells which added an estimated 1.0 Tcf of
proved CO2 reserves, resulting in total proved CO2 reserves at December 31, 2004
of approximately 2.7 Tcf (2.1 Tcf to our net ownership - see "CO2 Operations -
CO2 Resources"). We anticipate that year-end 2004 proved CO2 reserves will be
sufficient to satisfy the projected CO2 requirements for our first two tertiary
operation phases, Phase I, our tertiary operations in Southwest Mississippi, and
Phase II, our recently planned expansion into Eastern Mississippi.
Following the sale of our offshore operations in July 2004, we updated our
development schedule and targeted oil production from these tertiary recovery
operations. Based on our current plans, we anticipate that we can continue to
show significant growth in our oil production from tertiary operations for the
next five to ten years from our planned Phase I and Phase II operations. The
model assumes that the first production from tertiary recovery operations in
Eastern Mississippi will occur in 2007. During 2004, oil production from our
tertiary recovery operations averaged 6,784 BOE/d, averaging 7,242 BOE/d during
the fourth quarter.
SALE OF OFFSHORE OPERATIONS. On July 20, 2004, we closed the sale of
Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200
million (before adjustments) to Newfield Exploration Company. The sale price was
based on the asset value of the offshore assets as of April 1, 2004, which means
that the net operating cash flow (defined as revenue less operating expenses and
capital expenditures) from these properties which we received between April 1st
and closing, as well as expenses of the sale and other contractual adjustments,
reduced the purchase price to approximately $187 million. The purchaser also
received the net working capital of Denbury Offshore as of the closing date,
which primarily consisted of accrued production receivables.
26
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
We excluded two significant items from the sale: (i) a discovery well
drilled at High Island A-6 during 2004 and (ii) certain deep rights at West
Delta 27. The well at High Island A-6 should be on production during the first
half of 2005, and we sold a substantial portion of the deep rights at West Delta
27 during the third quarter of 2004 for $1.8 million but retained a carried
interest in a deep exploratory well.
Our offshore properties made up approximately 12% of our year-end 2003
proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented
approximately 25% (9,114 BOE/d) of our 2004 second quarter production.
OPERATING RESULTS. As a result of the sale of our offshore properties early
in the third quarter of 2004, our total production was significantly reduced,
contributing to a 5% decline in production levels during 2004 as compared to
2003 levels. However, higher commodity prices more than offset the lower
production, resulting in net income of $82.4 million during 2004 as compared to
$56.6 million of net income during 2003. The increase in adjusted cash flow from
operations during 2004 was less significant (5%)