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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%) primarily due to the $21.0
million of income taxes paid relating to the sale of our offshore properties.
See "Results of Operations - Operating Income" for discussion of this non-GAAP
measure versus cash flow from operations, which decreased by 15% between the two
periods. Payments on our commodity hedges continued to be a significant outflow,
totaling $84.6 million for 2004, up from $62.2 million during 2003. Hedge
payments should drop significantly during 2005 as most of our out-of-the-money
hedges expired at December 31, 2004. See "Results of Operations" for a more
thorough discussion of our operating results and "Market Risk Management" for
more information regarding our hedge position at year-end 2004 and our new
method of accounting for hedges for 2005.
CAPITAL RESOURCES AND LIQUIDITY
For 2005, our initial capital budget, excluding any potential acquisitions,
is $305 million, which at commodity futures prices as of the end of February
2005 will be slightly more than anticipated cash flow from operations. That
budget includes an estimated $45 million for a CO2 pipeline being constructed to
East Mississippi (see "Expansion of our tertiary operations" under "Overview"
above), which we may refinance upon completion by entering into some sort of
long-term financing, effectively paying for the cost of the pipeline over time
and recouping the cash spent. We monitor our capital expenditures on a regular
basis, adjusting them up or down depending on commodity prices and the resultant
cash flow. Therefore, during the last few years as commodity prices have
increased, we have often increased our capital budget during the year and would
likely do so again if commodity prices remain strong or increase further.
At year-end 2004, we had approximately $70 million in cash and short-term
investments remaining from the sale of our offshore properties, over and above
our normal month-end cash balances. We plan to invest this remaining cash and
any cash potentially generated from operations in excess of our capital budget
(such amount being highly dependent on commodity prices) over the next one to
two years on property acquisitions, particularly those that have future tertiary
potential. Although we now control most of the fields along our existing CO2
pipeline, there are several fields in East Mississippi that could be acquired to
expand our planned tertiary operations there, plus we are continuing to seek
additional interests in the fields that we currently own. Further, we would like
to add additional phases or areas of tertiary operations by acquiring other old
oil fields in other parts of our region of operations, building a CO2 pipeline
to those areas and initiating additional tertiary floods. We accelerated the
pace and expenditures on our tertiary operations following the offshore sale,
and plan to continue to do so as long as it remains economic and practical. We
also may seek conventional development and exploration projects in our areas of
operations or tertiary operations in other areas of the country. In addition to
our cash and short-term investments which may be used for the potential
aforementioned projects, we have all of our bank credit line available to us if
we were to need additional capital.
At December 31, 2004, we had outstanding $225 million (principal amount) of
7.5% subordinated notes due in 2013, approximately $4 million of capital lease
commitments, no bank debt, and working capital of $90 million. On September 1,
2004, we amended and restated our bank credit agreement which modified the prior
agreement by (i) creating a structure wherein the commitment amount and
borrowing base amount are no longer the same, (ii) improving our credit pricing
by reducing the interest rate chargeable at certain levels of borrowing, (iii)
extending the term by three years to April 30, 2009, (iv) reducing the
collateral requirements, (v) authorizing up to $20 million of possible future
CO2 volumetric production payment transactions with Genesis Energy ($4.8 million
of such transactions occurred in October 2004), and (vi) other minor
modifications and corrections. Under the new agreement, our borrowing base was
initially set at $200 million, a $25 million increase over the prior borrowing
base of $175 million, with an initial commitment amount of $100 million. The
borrowing base represents the amount we can borrow from a credit standpoint
based on our assets, as confirmed by the banks, while the commitment amount is
the amount we have asked the banks to commit to fund pursuant to the terms of
27
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
the credit agreement. The banks have the option to participate in any borrowing
request made by us in excess of the commitment amount, up to the borrowing base
limit, although they are not obligated to fund any amount in excess of $100
million, the commitment amount. The advantage to us is that we will pay
commitment fees on the lower commitment amount, not the higher borrowing base,
thus lowering our overall cost of available credit.
Sources and Uses of Capital Resources
During 2004, we spent $167.0 million on oil and natural gas exploration and
development expenditures, $42.4 million on CO2 exploration and development
expenditures, and approximately $18.9 million on property acquisitions, for
total capital expenditures of approximately $228.3 million. Our exploration and
development expenditures included approximately $138.9 million spent on
drilling, $18.9 million of geological, geophysical and acreage expenditures and
$51.6 million spent on facilities and recompletion costs. We funded these
expenditures with $168.7 million of cash flow from operations, with the balance
funded with net proceeds from the sale of our offshore properties. We paid back
all of our bank debt during the third quarter of 2004 with the offshore sale
proceeds, leaving us with approximately $33.0 million of cash and $57.2 million
of short-term investments as of December 31, 2004. We also raised $4.8 million
during the third quarter of 2004 from the sale of another volumetric production
payment of CO2 to Genesis Energy, L.P. ("Genesis"), along with a related
long-term CO2 supply agreement with an industrial customer. Adjusted cash flow
from operations (a non-GAAP measure defined as cash flow from operations before
changes in assets and liabilities as discussed below under "Results of
Operations-Operating Results") was $200.2 million for 2004, while cash flow from
operations, the GAAP measure, was $168.7 million.
During 2003, we generated approximately $197.6 million of cash flow from
operations and generated an additional $29.4 million of cash from sales of oil
and gas properties. The largest single asset sale was the sale of Laurel Field,
acquired from COHO in August 2002, which netted us approximately $25.9 million.
Later in the year, we also sold a volumetric production payment to Genesis,
which netted us approximately $23.9 million of cash. During 2003, we spent
$146.6 million on oil and natural gas exploration and development expenditures,
$22.7 million on CO2 capital investments and acquisitions, and approximately
$11.8 million on oil and natural gas property acquisitions, for total capital
expenditures of approximately $181.1 million. Our exploration and development
expenditures included approximately $115.3 million spent on drilling, $15.7
million of geological, geophysical and acreage expenditures and $35.2 million
spent on facilities and recompletion costs. In addition, during 2003 we incurred
approximately $15.6 million of costs for our subordinated debt refinancing. The
$147.3 million of net total expenditures (including the $15.6 million of debt
refinancing costs but net of property sales proceeds) was funded by our cash
flow from operations, with the balance used to reduce our total debt by
approximately $50.0 million.
During 2002, we spent approximately $99.3 million on exploration and
development activities, approximately $56.4 million on acquisitions (the largest
being the $48.2 million acquisition of the COHO properties), and approximately
$16.4 million on CO2 related capital expenditures, for a total of approximately
$172.1 million. Our exploration and development expenditures included
approximately $62.3 million spent on drilling, $17.8 million of geological,
geophysical and acreage expenditures and $19.1 million spent on facilities and
recompletion costs. The exploration and development expenditures were funded by
cash flow from operations, and the acquisitions were primarily funded by cash
flow, supplemented by property dispositions totaling $7.7 million and
incremental bank debt for the year of $9.1 million.
OFF-BALANCE SHEET ARRANGEMENTS
Commitments and Obligations
We have no off-balance sheet arrangements, special purpose entities,
financing partnerships or guarantees, other than as disclosed in this section.
We have no debt or equity triggers based upon our stock or commodity prices. Our
dollar denominated obligations that are not on our balance sheet include our
operating leases, which at year-end 2004 totaled $21.6 million relating
primarily to the lease financing of certain equipment for our CO2 recycling
facilities at our tertiary oil fields. We also have several leases relating to
office space and other minor equipment leases. We also have dollar related
28
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
obligations that are not currently recorded on our balance sheet relating to
various obligations for development and exploratory expenditures that arise from
our normal capital expenditure program or from other transactions common to our
industry. In addition, in order to recover our undeveloped proved reserves, we
must also fund the associated future development costs forecasted in our proved
reserve reports. For a further discussion of our future development costs and
proved reserves, see "Results of Operations - Depletion, Depreciation and
Amortization."
At December 31, 2004, we had a total of $460,000 outstanding in letters of
credit. Genesis Energy, Inc., our 100% owned subsidiary which is the general
partner of Genesis, has guaranteed the bank debt of Genesis, which consists of
$15.3 million of debt and $22.8 million in letters of credit at December 31,
2004. There were no guarantees by Denbury or any of its other subsidiaries of
the debt of Genesis or of Genesis Energy, Inc. at December 31, 2004. We do not
have any material transactions with related parties other than sales of
production and transportation arrangements with Genesis made in the ordinary
course of business, and volumetric production payments of CO2 ("VPP") sold to
Genesis as discussed in Note 3 to our Consolidated Financial Statements.
A summary of our obligations is presented in the following table:
Payments Due by Period
- ----------------------------------------------------------------------------------------------------------------------------
Amounts in Thousands Total 2005 2006 2007 2008 2009 Thereafter
- ----------------------------------------------------------------------------------------------------------------------------
Contractual Obligations:
- -----------------------
Subordinated debt (a)................. $ 225,000 $ - $ - $ - $ - $ - $ 225,000
Estimated interest payments on
Subordinated debt................... 143,438 16,875 16,875 16,875 16,875 16,875 59,063
Operating lease obligations........... 21,582 3,977 3,967 3,954 3,807 3,064 2,813
Capital lease obligations (b)......... 6,807 806 806 806 806 806 2,777
Capital expenditure obligations (c)... 23,752 23,752 - - - - -
Other long-term liabilities reflected
in our Consolidated Balance Sheet:
Derivative liabilities (d) ......... 4,196 4,196 - - - - -
Other Cash Commitments:
- -----------------------
Future development costs on proved
reserves, net of capital obligations (e) 320,988 110,491 84,686 48,809 36,313 14,629 26,060
Asset retirement obligations (f)..... 52,073 2,197 3,016 958 1,593 398 43,911
- ----------------------------------------------------------------------------------------------------------------------------
Total............................... $ 797,836 $ 162,294 $109,350 $ 71,402 $ 59,394 $ 35,772 $ 359,624
============================================================================================================================
(a) These long-term borrowings and related interest payments are further discussed in Note 6 to the Consolidated
Financial Statements. The table assumes that our long-term debt is held until maturity.
(b) Represents future minimum cash commitments under capital leases in place at December 31, 2004, primarily for
transportation of crude oil and CO2. Agreements are with Genesis. Approximately $2.2 million of these payments
represents interest.
(c) Represents future minimum cash commitments under contracts in place as of December 31, 2004, primarily for
drilling rig services and well related costs. As is common in our industry, we commit to make certain
expenditures on a regular basis as part of our ongoing development and exploration program. These commitments
generally relate to projects that occur during the subsequent several months and are usually part of our
normal operating expenses or part of our capital budget, which for 2005 is currently set at $305 million
(including the CO2 pipeline). In addition, we have recurring expenditures for such things as accounting,
engineering and legal fees, software maintenance, subscriptions, and other overhead type items. Normally these
expenditures do not change materially on an aggregate basis from year to year and are part of our general and
administrative expenses. We have not attempted to estimate these types of expenditures in this table as most
could be quickly cancelled with regard to any specific vendor, even though the expense itself may be required
for ongoing normal operations of the Company.
(d) Represents the estimated future payments under our derivative obligations based on the futures market prices
as of December 31, 2004. These amounts will change as oil and natural gas commodity prices change. The
estimated fair market value of our oil and natural gas commodity derivatives at December 31, 2004 was a $4.9
million liability. See further discussion of our derivative contracts in "Market Risk Management" contained in
this Management's Discussion and Analysis of Financial Condition and in Note 9 to the Consolidated Financial
Statements.
(e) Represents projected capital costs as scheduled in our December 31, 2004 proved reserve report that are
necessary in order to recover our proved undeveloped reserves, but these are not current contractual
commitments. Amount is net of capital obligations shown above.
29
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
(f) Represents the estimated future asset retirement obligations on an undiscounted basis. The discounted asset
retirement obligation of $21.5 million, as determined under SFAS No. 143, is further discussed in Note 4 to
the Consolidated Financial Statements.
Long-term contracts require us to deliver CO2 to our industrial CO2
customers at various contracted prices, plus we have a CO2 delivery obligation
to Genesis pursuant to two volumetric production payments ("VPP") contracts
entered into during 2003 and 2004. Based upon the maximum amounts deliverable as
stated in the contracts and the volumetric production payment, we estimate that
we may be obligated to deliver up to 398 Bcf of CO2 to these customers over the
next 17 years; however, since the group as a whole has historically taken less
CO2 than the maximum allowed in their contracts, based on the current level of
deliveries we project that our commitment would likely be reduced to
approximately 332 Bcf. The maximum volume required in any given year is
approximately 101 MMcf/d, although based on our current level of deliveries;
this would likely be reduced to approximately 78 MMcf/d. Given the size of our
proven CO2 reserves at December 31, 2004 (approximately 2.7 Tcf before deducting
approximately 178.7 Bcf for the two VPPs), our current production capabilities
and our projected levels of CO2 usage for our own tertiary flooding program, we
believe that we will be able to meet these delivery obligations.
RESULTS OF OPERATIONS
CO2 Operations
OVERVIEW. Over five years ago we began our focus upon tertiary operations
with the purchase of Little Creek Field, a tertiary recovery operation that was
already underway. Subsequently, we have greatly expanded this program in
Southwest Mississippi (Phase I of our tertiary operations), acquiring several
more oil fields and most importantly the CO2 resources used to flood these
fields (see "CO2 Resources" below). The focus has increased to the point that
approximately 60% of our 2005 capital budget is dedicated to tertiary related
operations, including the CO2 pipeline currently under construction to East
Mississippi (the area where we will conduct Phase II of our tertiary
operations). We particularly like this 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 (down to
prices in the low twenties per Bbl in Phase I of our tertiary operations in
Southwest Mississippi), and (iii) we have virtually no competition for this type
of activity in our geographic 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.
CO2 RESOURCES. In February 2001, we acquired the sources of CO2 located
near Jackson, Mississippi, and a pipeline to transport it to our oil fields.
Since February 2001, we have acquired two producing wells and drilled seven CO2
producing wells, tripling our initial proven CO2 reserves to 2.7 Tcf as of
December 31, 2004 (including the 178.7 Bcf of reserves dedicated to two VPPs
with Genesis). The estimate of 2.7 Tcf of proved CO2 reserves is based on total
CO2 reserves in the fields, of which Denbury's net ownership is approximately
2.1 Tcf and is included in the evaluation of proven CO2 reserves by DeGolyer &
MacNaughton included as Exhibit 99. In discussing the available CO2 reserves, we
make reference to the gross amount of proved reserves as that 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 we are responsible for
distributing the entire CO2 production stream for both of these purposes. We
currently estimate that it will take approximately 711 Bcf of CO2 to develop and
produce the proved tertiary recovery reserves we have recorded at December 31,
2004.
Today, we own every known producing CO2 well in the region, providing us a
significant strategic advantage in the acquisition of other properties in
Mississippi and Louisiana that could be further exploited through tertiary
recovery. As of January 2005, we are capable of producing approximately 350
MMcf/d of CO2, about four times the production capacity at the time of our
initial acquisition of the Jackson Dome field. We continue to drill additional
CO2 wells, with four more wells planned for 2005, which are expected to further
increase our production capacity and potentially increase our proven CO2
reserves. We believe we have sufficient CO2 reserves for our first two phases of
tertiary operations in Western Mississippi and Eastern Mississippi, but would
like to add additional reserves for future phases, plus we need to further
increase our production capacity as our current model for phases I and II
requires almost 700 MMcf/d of CO2 production by 2009. Although we believe that
our plans and projections are reasonable and achievable, there could be delays
or unforeseen problems in the future which could delay our overall tertiary
development program. We believe that such delays, if any, should only be
temporary.
In addition to using CO2 for our tertiary operations, we sell CO2 to third
party industrial users under long-term contracts. Our net operating margin from
30
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
these sales was $6.2 million during 2002, $6.5 million during 2003, and $4.9
million during 2004. Our average CO2 production during 2002, 2003 and 2004 was
approximately 104 million, 170 million, and 218 million cubic feet per day, of
which approximately 54% in 2002, 62% in 2003, and 73% in 2004 was used in our
tertiary recovery operations, with the balance sold to third parties for
industrial use.
We spent approximately $0.12 per Mcf to produce our CO2 during 2004,
slightly less than our 2003 annual average of $0.15 per Mcf, primarily due to
the lack of any significant workover expenses like we had in 2003, partially
offset by higher royalty expenses because certain of our royalties are adjusted
based on oil prices. During 2002, we spent approximately $0.13 per Mcf to
produce our CO2. Our estimated total cost per thousand cubic feet of CO2 during
2004 was approximately $0.21, after inclusion of depreciation and amortization
expense related to the CO2 production.
OIL POTENTIAL. Although our oil production from our CO2 tertiary recovery
activities is still relatively modest (approximately 25% of fourth quarter 2004
production), we expect it to be an ever increasing portion of our production. We
currently have tertiary operations on-going at Little Creek, Mallalieu, McComb
and Brookhaven Fields, as well as various smaller adjacent fields. We project
that our oil production from these operations will increase substantially over
the next several years, along with our tentatively scheduled tertiary projects
at other oil fields along our pipeline. As of January 2005, these fields were
producing approximately 8,300 Bbls/d. As of December 31, 2004, we had
approximately 50.5 MMBbls of proven oil reserves related to tertiary operations
in these fields along our CO2 pipeline and have identified and estimated
significant additional potential in fields that we own in this area. In
addition, we have commenced operations to expand this program to East
Mississippi and have commenced the 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. While our current tertiary
operations in the Southwest part of Mississippi are economic at NYMEX per barrel
oil prices in the low twenties, due predominately to the lower quality of oil in
East Mississippi, we estimate that it requires a NYMEX oil price in the mid to
upper twenties for the same rate of return in this part of the state. We believe
that this expansion, labeled Phase II, has significant other oil potential well
beyond the first six fields that we have engineered and currently plan to flood.
Combining the production forecast for both of these areas 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 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.
FINANCIAL STATEMENT IMPACT OF CO2 OPERATIONS. The increasing emphasis on
CO2 tertiary recovery projects has made, and will continue to make, an impact on
our financial results and certain operating statistics different from
conventional development activities.
First, there is a significant delay between the initial capital
expenditures and the resulting production increases, as these tertiary
operations require the building of facilities before CO2 flooding can commence
and it usually takes six-to-twelve months before the field responds (i.e. oil
production commences) to the injection of CO2. Further, as we expand to other
areas beyond Phase I, there will be times when we spend significant amounts of
capital before we can recognize any proven reserves as these other areas, for
the most part, will require an oil production response to the CO2 injections
before any oil reserves can be recorded. We plan to spend over $50 million on
Phase II oil fields during 2005, plus an additional $45 million on the CO2
pipeline to East Mississippi.
Secondly, these tertiary projects are more expensive to operate than our
other oil fields because of the cost of injecting and recycling the CO2
(primarily due to the significant energy requirements to re-compress the CO2
back into a liquid state for re-injection purposes). As commodity and energy
prices increase, so does our operating expenses in these fields. As such, our
overall operating expenses on a per BOE basis will likely continue to increase
as these operations constitute an increasingly larger percentage of our
operations. Our operating cost for our tertiary operations during 2004 averaged
$9.90 per BOE, as compared to an estimated cost of around $5 to $7 per BOE for a
more traditional oil property. We allocate the cost to produce and transport the
CO2 between CO2 used in our own oil fields and CO2 sold to commercial users. The
CO2 operating expenses allocated to our oil fields are recorded as lease
operating expenses on those fields.
Third, all of our current CO2 operations are in fields that produce light
sweet oil and receive oil prices close to, and sometimes actually higher than,
NYMEX prices. As this production becomes a larger percentage of our overall
production, the overall average difference between the prices we receive and
published NYMEX prices should decrease, assuming other market conditions do not
31
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
change. While our oil prices have historically averaged between $4.00 and $5.00
below NYMEX prices, our 2002 average was $3.74 below NYMEX and our 2003 average
decreased further to $3.60 below NYMEX. During 2004, the market for sour and
heavy crude oil (predominately our East Mississippi production) deteriorated,
causing our overall average differential to increase to $4.91 per barrel for the
year and to $6.48 per barrel for the fourth quarter of 2004. While we cannot
predict what will happen to the market for heavy and sour crude, we do expect
our light sweet oil production to increase as a percentage of our total oil
production over the next few years. However, this trend could reverse in future
years as the anticipated oil production from Phase II of our tertiary operations
is primarily heavy and sour oil.
2004 CO2 Tertiary Recovery Operating Activities. Our oil production from
our CO2 tertiary recovery activities has steadily increased during the last few
years, from 3,970 Bbls/d in 2002 to 4,671 Bbls/d during 2003, and to 6,784
Bbls/d during 2004, with a fourth quarter 2004 rate of 7,242 Bbls/d. This
represents approximately 37% of our total corporate oil production during the
fourth quarter of 2004 and approximately 25% of our total corporate production
on a BOE basis. We expect that this oil production will continue to increase,
although the increases are not always predictable or consistent.
While we did experience higher energy costs to operate our tertiary
recycling facilities as a result of higher commodity prices, we were able to
lower our operating cost per BOE in our tertiary operations from $11.34 per BOE
in 2003 to $9.90 per BOE during 2004 because of the higher tertiary oil
production levels. In addition to higher energy costs, we experienced general
cost inflation in the industry and also commenced lease payments on certain of
our recycling facilities (see "Commitments and Obligations" above). As a result,
the absolute amount of operating expenses related to tertiary operations
increased from $14.3 million during 2002 to $19.3 million during 2003 and $24.6
million during 2004.
At December 31, 2004, we had proved reserves of 50.5 MMBbls relating to our
tertiary recovery operations. Through December 31, 2004, we had spent a total of
$155.6 million on fields involved in this process, and had received $160.0
million in net cash flow (revenue less operating expenses and capital
expenditures), or net positive cash flow of $4.4 million. The proved oil
reserves in our CO2 fields have a PV-10 Value of $782.9 million, using December
31, 2004 constant NYMEX pricing of $43.45 per Bbl. These amounts do not include
the capital costs or related depreciation and amortization of our CO2 producing
properties. Through December 31, 2004, we have spent a total of $132.8 million
on our CO2 producing properties, received a total of $57.4 million in net cash
flow (revenue less operating expenses and capital expenditures, consisting
solely of sales to industrial customers and Genesis volumetric production
payment receipts), leaving us a balance of approximately $75.4 million of
unrecovered costs for the CO2 assets.
CO2 Related Capital Budget for 2005. Tentatively, we plan to spend
approximately $35 million in 2005 in the Jackson Dome area with the intent 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 related
expenditures to over 60% of our 2005 capital budget.
Operating Income
Cash flow from operations and net income have been strong for the last
three years, primarily because of higher than historical commodity prices.
Production declined slightly (2%) from 2002 to 2003 and approximately 5% from
2003 to 2004, with most of the current year decrease related to the sale of our
offshore properties (see also "Overview"). The higher commodity prices each year
more than offset the production decline, resulting in higher overall net income
and adjusted cash flow from operations each year from 2002 through 2004 (see
discussion below regarding this non-GAAP measure, adjusted cash flow from
operations).
Year Ended December 31,
- ----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------
Net income................................................... $ 82,448 $ 56,553 $ 46,795
Net income per common share:
Basic ..................................................... $ 1.50 $ 1.05 $ 0.88
Diluted ................................................... 1.44 1.02 0.86
- ----------------------------------------------------------------------------------------------------------
Adjusted cash flow from operations........................... $ 200,193 $ 189,802 $ 164,565
Net change in assets and liabilities relating to operations.. (31,541) 7,813 (4,965)
- ----------------------------------------------------------------------------------------------------------
Cash flow from operations (GAAP measure)................... $ 168,652 $ 197,615 $ 159,600
==========================================================================================================
32
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Adjusted cash flow from operations is a non-GAAP measure that represents
cash flow provided by operations before changes in assets and liabilities, as
calculated from our Consolidated Statements of Cash Flows. Cash flow from
operations is the GAAP measure as presented in our Consolidated Statements of
Cash Flows. In our discussion herein, we have elected to discuss these two
components of cash flow provided by operations.
Adjusted cash flow from operations, the non-GAAP measure, measures the cash
flow earned or incurred from operating activities without regard to the
collection or payment of associated receivables or payables. We believe that it
is important to consider adjusted cash flow from operations separately, as we
believe it can often be a better way to discuss changes in operating trends in
our business caused by changes in production, prices, operating costs, and
related operational factors, without regard to whether the earned or incurred
item was collected or paid during that year. We also use this measure because
the collection of our receivables or payment of our obligations has not been a
significant issue for our business, but merely a timing issue from one period to
the next, with fluctuations generally caused by significant changes in commodity
prices or significant changes in drilling activity.
The net change in assets and liabilities relating to operations is also
important as it does require or provide additional cash for use in our business;
however, we prefer to discuss its effect separately. For instance, as noted
above, during 2003, our accounts payable and accrued liabilities increased as a
result of our higher drilling activity level late in the year, particularly
offshore, increasing our available cash from operations. During 2004, we had a
$31.5 million difference between our adjusted cash flow from operations and our
GAAP cash flow from operations. The most significant factor was the transfer of
approximately $12.5 million of accrued production receivables relating to our
offshore properties that existed as of the closing date to the offshore property
purchaser. This reduction in accrued production receivables during 2004 was not
considered a collection of receivables for our GAAP cash flow from operations.
In addition to the effect of transferred receivables, our other accrued
production receivables increased during the year due to the increase in
commodity prices and we reduced our accounts payable and accrued liabilities by
approximately $10.5 million, as a result of less overall activity as of
year-end, both of which contributed to the significant difference between our
2004 adjusted cash flow and GAAP cash flow from operations.
33
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Certain of our operating statistics for the each of last three years are set
forth in the following chart:
Year Ended December 31,
- ----------------------------------------------------------------------------------------------------------
(In Thousands, Except per BOE Amounts) 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION VOLUME
Bbls................................................ 19,247 18,894 18,833
Mcf................................................. 82,224 94,858 100,443
BOE (1)............................................. 32,951 34,704 35,573
OPERATING REVENUES
Oil sales........................................... $ 256,843 $ 189,442 $ 153,705
Natural gas sales................................... 187,934 196,021 121,189
-------------- --------------- --------------
Total oil and natural gas sales................... $ 444,777 $ 385,463 $ 274,894
============== =============== ==============
HEDGE CONTRACTS
Cash gain (loss) on effective hedge contracts $ (70,469) $ (62,210) $ 932
Cash gain (loss) on ineffective hedge contracts (14,088) - -
-------------- --------------- --------------
Total cash gain (loss) (84,557) (62,210) 932
Non-cash hedging adjustments (1,270) 3,578 3,093
-------------- --------------- --------------
Total gain (loss) on derivative contracts $ (85,827) $ (58,632) $ 4,025
============== =============== ==============
OPERATING EXPENSES
Lease operating expenses............................ $ 87,107 $ 89,439 $ 71,188
Production taxes and marketing expenses (3)......... 18,737 14,819 11,902
-------------- --------------- --------------
Total production expenses......................... $ 105,844 $ 104,258 $ 83,090
============== =============== ==============
CO2 sales and transportation fees (4)............... $ 6,276 $ 8,188 $ 7,580
CO2 operating expenses.............................. 1,338 1,710 1,400
-------------- --------------- --------------
CO2 operating margin.............................. $ 4,938 $ 6,478 $ 6,180
============== =============== ==============
UNIT PRICES-INCLUDING IMPACT OF HEDGES (2)
Oil price per Bbl................................... $ 27.36 $ 24.52 $ 22.27
Gas price per Mcf................................... 5.57 4.45 3.35
UNIT PRICES-EXCLUDING IMPACT OF HEDGES (2)
Oil price per Bbl................................... $ 36.46 $ 27.47 $ 22.36
Gas price per Mcf................................... 6.24 5.66 3.31
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1)
Oil and natural gas revenues (including hedge settlements) $ 29.87 $ 25.52 $ 21.24
-------------- --------------- --------------
Lease operating expenses............................ $ 7.22 $ 7.06 $ 5.48
Production taxes and marketing expenses............. 1.55 1.17 0.92
-------------- --------------- --------------
Total production expenses......................... $ 8.77 $ 8.23 $ 6.40
==========================================================================================================
(1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the Company's hedging transactions.
(3) For 2004, includes transportation expenses paid to Genesis of $1.2 million.
(4) For 2004 and 2003, includes deferred revenue of $2,399,000 and $322,000, respectively, associated with
volumetric production payments and transportation income of $2,694,000 and $355,000, respectively, both from
Genesis.
34
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
PRODUCTION. Average daily production by area for 2002, 2003 and 2004, and each
of the quarters of 2004 is listed in the following table (BOE/d).
Average Daily Production (BOE/d)
--------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
Operating Area 2002 2003 2004 2004 2004 2004 2004
- ---------------------------------- --------------------------------------------------------------------------------
Mississippi - non-CO2 floods 13,378 13,638 12,754 13,048 12,969 13,564 13,085
Mississippi - CO2 floods 3,970 4,671 6,318 6,603 6,967 7,242 6,784
Onshore Louisiana 8,050 8,222 8,825 7,492 7,033 7,182 7,630
Barnett Shale and other 200 224 229 345 803 963 587
--------------------------------------------------------------------------------
Total production excl. offshore 25,598 26,755 28,126 27,488 27,772 28,951 28,086
Offshore Gulf of Mexico 9,975 7,949 8,521 9,114 1,885 26 4,865
--------------------------------------------------------------------------------
Total Company 35,573 34,704 36,647 36,602 29,657 28,977 32,951
- ---------------------------------- =================================================================================
As a result of the sale of our offshore properties in July 2004, third and
fourth quarter 2004 production decreased significantly from prior periods as
listed in the above table. Adjusting for the offshore sale, overall production
increased approximately 5% on a BOE/d basis during both 2003 and 2004, anchored
by the increased production from our tertiary operations and Barnett Shale play,
generally offset by overall declines in our onshore natural gas wells in
Louisiana. However, other factors that caused fluctuations between the various
periods should also be noted as outlined below.
The addition of properties acquired from COHO during August 2002
contributed to the majority of the increase in our overall production in the
Mississippi-non-CO2 flood properties from 2002 to 2003, as most of these
pre-existing non-CO2 fields in Mississippi have been on a slow decline as a
result of normal depletion. Heidelberg Field, our single largest field that is
located in this area, has partially offset this decline, as its production
increased each year, from 7,479 BOE/d during 2002 to 7,535 BOE/d during 2003 to
7,775 BOE/d during 2004. Most of this increase at Heidelberg is attributable to
additional natural gas drilling in the Selma Chalk formation as Heidelberg's oil
production has been slowly decreasing. Natural gas production at this field
averaged 7.1 MMcf/d in 2002, 10.3 MMcf/d in 2003 and 13.8 MMcf/d in 2004, making
Heidelberg Field our single largest natural gas producing field during 2004.
As more fully discussed in "CO2 Operations" above, oil production from our
tertiary operations has increased each year.
Production from our offshore properties averaged 1,885 BOE/d in the third
quarter, representing the production during the first 19 days of July prior to
the sale. As evidenced in the above table, production from this area has
fluctuated over the last three years primarily due to the level of activity and
the fluctuations caused by the short-lived nature of these natural gas reserves.
As an example, offshore production increased in early 2004 as a result of 15
well completions made late in the fourth quarter of 2003, four at Brazos A-21,
three at North Padre A-9, three at Chandeleur Sound 69, two at West Cameron 192
and three at West Cameron 427. Some of our natural gas properties in onshore
Louisiana have similar characteristics as is evident by the steep declines
during 2004. While the production from onshore Louisiana only declined 7% on an
annual basis, there was a 19% drop between the first quarter of 2004 and last
quarter of 2004. A significant portion of this decline was at Thornwell Field,
an onshore Louisiana field, which averaged 926 BOE/d during the fourth quarter
of 2004, down from 2,526 BOE/d in the first quarter of 2004 and 2,487 BOE/d
during 2003. Production from this field is in a steep decline due to its
short-lived nature, and is expected to further decline in the future. In spite
of its short remaining life, we have generated a good return on investment at
Thornwell, generating $37.0 million of net positive cash flow (operating
revenues less operating expenses and capital expenditures) through December 31,
2004, with a remaining PV-10 Value of $37.4 million as of December 31, 2004
(based on SEC proved reserve report at year-end 2004 prices).
35
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Production in the Barnett Shale area has just recently begun to increase as
a result of five horizontal wells drilled and completed in this area during the
latter part of 2004. We plan to drill around 25 more wells there in 2005 and
expect production from this area to further increase during 2005.
Our production for 2004 was weighted slightly toward oil (58%), although
the fourth quarter 2004 average was 68% oil following the sale of the offshore
properties in July 2004. It appears that we will remain similarly weighted
toward oil in 2005 due to our increasing emphasis on tertiary operations, unless
we make an acquisition that is predominantly natural gas.
OIL AND NATURAL GAS REVENUES. Our oil and natural gas revenues have
increased for each of the last two years. Two factors cause the change in
pre-hedging revenues: commodity prices and production levels. Between 2003 and
2004, revenues increased by 15%, primarily due to higher commodity prices. The
overall increase in commodity prices contributed $77.8 million in additional
revenues, a 20% increase; partially offset by an overall decrease of $18.5
million (a 5% decrease) related to the 5% lower production volumes. Between 2002
and 2003, revenues increased by 40%, also primarily due to higher commodity
prices. The overall increase in commodity prices contributed $117.3 million in
additional revenues, a 43% increase; partially offset by an overall decrease in
revenues of $6.7 million (a 2% decrease) related to the 2% lower production
volumes.
During 2004, we paid out $64.1 million on our oil hedges ($9.10 per Bbl)
and $20.4 million ($0.68 per Mcf) on our natural gas hedges relating to swaps
and collars we purchased one to two years earlier when commodity prices were
lower. About $30.5 million of the hedge payments related to swaps originally put
in place to protect the rate of return for the COHO acquisition in August 2002.
The payments in 2003 were similar in nature, but slightly less due to lower
overall commodity prices. During 2003, we paid out $20.3 million on our oil
hedges ($2.95 per Bbl) and $41.9 million ($1.21 per Mcf) on our natural gas
hedges on generally the same swaps and collars. During 2002, we had total net
receipts on our hedges of $932,000, paying out $0.6 million ($0.09 per Bbl) on
our oil hedges, but collecting a net $1.5 million ($0.04 per Mcf) on our natural
gas hedges. For 2005, we have hedged a lower percentage of our overall
production, predominately with puts or price floors, so we anticipate that our
hedge payments will be substantially lower than the payments made in 2004. See
"Market Risk Management" for a further discussion of our hedging activities and
position.
Our net oil and natural gas prices have fluctuated as outlined on the prior
table. During 2004, we received the highest weighted average net price per BOE
in our history, netting $29.87 per BOE even after paying out approximately $7.01
per BOE for hedge losses. This resulted from average NYMEX prices of over $41.00
per Bbl and $6.00 per MMBtu during the year. Prices were also strong during
2003, although not quite as high, netting Denbury $25.52 per BOE, net of the
$4.91 per BOE hedge losses. During 2003 we also had one of our best years with
regard to our realized net price relative to NYMEX prices. During 2002, we
received an average discount to NYMEX of $3.74 per Bbl. This improved in 2003 to
an average discount of $3.60 per Bbl. This trend was reversed in 2004 as the
heavy, sour crude market (which predominately applies to our Eastern Mississippi
production) deteriorated significantly, increasing our average oil differentials
for the year to $4.91 per Bbl and $6.48 per Bbl for the fourth quarter of 2004.
If market conditions for the heavy, sour crude remained consistent, we would
expect to gradually improve the overall NYMEX discount as the amount of light
sweet oil production from our tertiary operations is expected to increase,
improving the overall quality of our product mix. However, as evident in 2004,
the oil market can change substantially.
Year over year, there is generally less fluctuation in our natural gas
prices relative to NYMEX. Normally, we are at, or slightly above, the NYMEX
market, primarily because of the high Btu content of our natural gas. For 2004,
we had an average $0.02 premium to NYMEX, a little less than the $0.18 premium
during 2003, but higher than the $0.05 discount in 2002. As we increase our
emphasis on the Barnett Shale area in 2005, the overall price we receive for our
natural gas could decline slightly as our properties in this area have
historically received a price that is $0.50 to $0.75 less than NYMEX prices.
OPERATING EXPENSES. Lease operating expenses increased to $7.22 per BOE in
2004, a 2% increase over the $7.06 per BOE average during 2003, and an increase
of 32% from the $5.48 per BOE average during 2002. During 2004, our workover
expenses decreased as compared to 2003, when we spent $2.8 million on two
individually significant workovers relating to mechanical failures of two
onshore Louisiana wells, plus several smaller workovers. Operating expenses on
our tertiary operations increased from $14.3 million during 2002 to $19.3
million in 2003 to $24.6 million in 2004 as a result of increased activity at
Mallalieu and McComb Fields. However, with the 45% higher production from these
tertiary operations between the same periods, operating expenses for our
tertiary operations on a per BOE basis decreased from $11.34 per BOE in 2003 to
$9.90 per BOE in 2004. Nonetheless, our tertiary operations are steadily
increasing our aggregate dollar costs and our costs per BOE on a total corporate
36
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
basis as our tertiary operations constitute a more significant portion of our
total production and operations. The balance of cost increases during 2004 is
generally attributable to higher energy costs to operate our tertiary recovery
properties, a provision for potential litigation losses, and general cost
inflation in our industry. In general, we expect our operating costs per BOE to
further increase in the future as the operating costs of our tertiary operations
are higher than the costs of our other operations.
Most of the increase from 2002 to 2003 was attributable to the
aforementioned workovers, with several other smaller workovers, including one on
a CO2 well. The growth of our tertiary operations also contributed to an overall
increase, as well as higher lease fuel costs and a full year of expenses on the
properties acquired from COHO, which have typically had higher expenses on a per
BOE basis than our other oil properties due to their age.
Production taxes and marketing expenses generally change in proportion to
commodity prices and therefore, were higher in 2004 along with the record high
commodity prices. The sale of our offshore properties also contributed to the
increase in production taxes and marketing expenses on a per BOE basis during
2004, as most of our offshore properties were tax exempt.
General and Administrative Expenses
During the last three years, general and administrative ("G&A") expenses on
a per BOE basis have increased from $0.96 per BOE during 2002, to $1.20 per BOE
during 2003, to $1.78 per BOE during 2004, increasing even faster than the gross
aggregate dollar increases in G&A expense as production has declined each year
due primarily to property sales.
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE and Employee Data 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------
Gross G&A expense $ 53,658 $ 46,031 $ 40,149
Operator overhead charges (28,048) (26,823) (23,857)
Capitalized exploration expense (5,072) (5,507) (5,325)
- ---------------------------------------------------------------------------------------------------------
20,538 13,701 10,967
State franchise taxes 923 1,488 1,459
- ---------------------------------------------------------------------------------------------------------
Net G&A expense $ 21,461 $ 15,189 $ 12,426
=========================================================================================================
Average G&A expense per BOE $ 1.78 $ 1.20 $ 0.96
Employees as of December 31 380 374 356
- ---------------------------------------------------------------------------------------------------------
Gross G&A expenses increased $7.6 million, or 17%, between 2003 and 2004.
The largest component of the increase was approximately $2.4 million of employee
severance payments for the offshore professional and technical staff terminated
in conjunction with our offshore property sale. We also incurred additional G&A
expenses associated with our corporate restructuring in December 2003,
compliance with the requirements of the Sarbanes-Oxley Act, the sale of stock by
the Texas Pacific Group in March 2004, a provision for potential litigation
losses, restricted stock grants, higher bonus levels for employees than in 2003
due to the strong performance during 2004, and overall increases in most other
categories of G&A due to general cost inflation.
During the third and fourth quarters of 2004, we granted a total of
1,150,000 million shares of restricted stock to our officers and independent
directors, generating deferred compensation expense of approximately $23.3
million, the market value of the shares on the date of grant. A portion of this
restricted stock vests over five years and a smaller portion vests upon
retirement (in addition to vesting upon death, disability or a change of
control). We are amortizing the non-cash $23.3 million of compensation expense
of this restricted stock over the five year vesting period and over the
projected retirement date vesting period, expensing approximately $1.6 million
during 2004. We estimate that amortized compensation expense for the restricted
stock will be approximately $1.0 million per quarter through 2006.
Gross aggregate dollar G&A expenses increased $5.9 million, or 15%, between
2002 and 2003. The largest component of the increase was approximately $1.4
million of expenses spent for consultants hired to help document and test our
system of internal controls, a requirement of the Sarbanes-Oxley Act of 2002.
The second largest source of the increase was approximately $630,000 of legal,
accounting, bank and other fees associated with the conversion to a holding
37
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
company organizational structure during December 2003 which reduced our
franchise taxes by $565,000 between 2003 and 2004. Other factors also
contributed to the increase, the most significant being expenses associated with
the sale of stock by the Texas Pacific Group in the first and last quarters of
2003, higher year-end expenses for engineering and audit fees, and an overall
increase in personnel and associated expenses primarily related to cost of
living salary increases. Partially offsetting these increases was a reduction in
our 2003 bonuses due to less positive operating results during 2003 in certain
areas.
Higher operator overhead recovery charges resulting from the incremental
development activity helped to partially offset the increase in gross G&A,
partially reduced by the impact of the offshore property sale. Our well
operating agreements allow us, when we are the operator, to charge a well with a
specified overhead rate during the drilling phase and also to charge a monthly
fixed overhead rate for each producing well. As a result of the additional
operated wells from acquisitions, additional tertiary operations, and drilling
activity during the past year, the amount we recovered as operator overhead
charges increased by 12% between 2002 and 2003 and 5% between 2003 and 2004.
Capitalized exploration costs increased slightly between 2002 and 2003, along
with increases in employee related costs, but decreased in 2004 as a result of
the personnel reductions in our offshore area as a result of the property sale.
The net effect of the increases in gross G&A expenses, operator overhead
recoveries and capitalized exploration costs was a 41% increase in net G&A
expense between 2003 and 2004 and a 22% increase between 2002 and 2003. The
increase was even higher on a per BOE basis as a result of lower production,
primarily related to the offshore property sale.
Interest and Financing Expenses
Year Ended December 31,
- ----------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2004 2003 2002
- ----------------------------------------------------------------------------------------------
Interest expense $ 19,468 $ 23,201 $ 26,833
Non-cash interest expense (962) (1,251) (2,659)
- ----------------------------------------------------------------------------------------------
Cash interest expense 18,506 21,950 24,174
Interest and other income (2,388) (1,573) (1,746)
- ----------------------------------------------------------------------------------------------
Net cash interest expense $ 16,118 $ 20,377 $ 22,428
==============================================================================================
Average net cash interest expense per BOE $ 1.34 $ 1.61 $ 1.73
Average debt outstanding $ 270,770 $ 341,496 $ 350,556
Average interest rate (1) 6.8% 6.4% 6.9%
- ----------------------------------------------------------------------------------------------
(1) Includes commitment fees but excludes amortization of debt issue costs.
Interest expense for 2004 decreased from 2003 primarily due to lower
average debt levels as a result of our $50 million reduction in debt during 2003
and the payoff of our bank debt in the third quarter of 2004 with the proceeds
from our offshore property sale. Our non-cash interest expense in 2004 decreased
as a result of the subordinated debt refinancing in March 2003, which eliminated
the amortization of discount on our old subordinated debt, which was higher than
the discount and related amortization on our new subordinated debt issue.
Interest and other income increased as a result of the cash generated from the
offshore property sale.
Interest expense for 2003 decreased from levels in the prior year for
similar reasons, (i) lower overall interest rates, resulting from an overall
drop in market interest rates on our bank debt and due to the refinancing of our
subordinated debt, (ii) lower average outstanding debt balance during 2003, as
we reduced debt by $50 million during the year, and (iii) reduced debt issue
cost amortization resulting from the complete amortization of costs associated
with the original maturity of our bank credit line in December 2002 after we
refinanced and extended the bank credit line to April 2006.
38
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Depletion, Depreciation and Amortization ("DD&A")
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------
Amounts in Thousands, Except Per BOE Data 2004 2003 2002
- -------------------------------------------------------------------------------------------------------
Depletion and depreciation of oil and natural gas properties $ 88,505 $ 87,842 $ 87,728
Depletion and depreciation of CO2 assets 4,664 2,542 1,858
Asset retirement obligations 2,408 2,852 2,951
Depreciation of other fixed assets 1,950 1,472 1,699
- -------------------------------------------------------------------------------------------------------
Total DD&A $ 97,527 $ 94,708 $ 94,236
=======================================================================================================
DD&A per BOE:
Oil and natural gas properties $ 7.54 $ 7.16 $ 6.98
CO2 assets and other fixed assets 0.55 0.32 0.28
- -------------------------------------------------------------------------------------------------------
Total DD&A cost per BOE $ 8.09 $ 7.48 $ 7.26
=======================================================================================================
But for the property sales, our total proved reserve quantities would have
increased each of the last three years. Our proved reserves decreased from 130.7
MMBOE as of December 31, 2002, to 128.2 MMBOE as of December 31, 2003 and
increased slightly to 129.4 MMBOE as of December 31, 2004. During 2003 we sold
approximately 8.3 MMBOE of proved reserves and during 2004 sold approximately
16.5 MMBOE of proved reserves, primarily related to the offshore sale. Reserve
quantities and associated production are only one side of the DD&A equation,
with capital expenditures, asset retirement obligations less related salvage
value, and projected future development costs making up the remainder of the
calculation.
In total, our DD&A rate on a per BOE basis increased 8% between 2003 and
2004, primarily due to the higher percentage of expenditures on offshore
properties during 2003 and the first six months of 2004, which have higher
overall finding and development costs, and an increase in certain of our future
development cost estimates to reflect the rising costs in the industry. Although
the 2004 average DD&A rate was similar to the DD&A rate of $8.00 per BOE during
the fourth quarter of 2003, during the year there were significant fluctuations.
Our DD&A rate on a per BOE basis decreased in the third quarter of 2004 to $7.62
per BOE from $8.46 per BOE in the second quarter, primarily as a result of the
sale of our offshore properties, the proceeds of which were credited to the full
cost pool. However, the rate increased in the fourth quarter of 2004 to $7.98
per BOE, primarily to reflect cost inflation in the industry, as we increased
our cost estimates (i.e. future development costs) for certain existing proved
undeveloped reserves. We adjust our DD&A rate each quarter based on any changes
in our estimates of oil and natural gas reserves and costs, and thus our DD&A
rate could change significantly in the future. Our DD&A rate for our CO2 and
other fixed assets increased in 2004 as a result of the additional cost incurred
drilling CO2 wells during the year and higher associated future development
costs, partially offset by an increase in CO2 reserves from 1.6 Tcf as of
December 31, 2003 to 2.7 Tcf as of December 31, 2004 (100% working interest
basis before amounts attributable to Genesis volumetric production payments -
see "CO2 Operations - CO2 Resources").
During 2003, the fourth quarter DD&A rate increased to $8.00 per BOE,
increasing the 2003 annual average to $7.48 per BOE. The higher DD&A was
partially due to the higher percentage of capital expenditures spent on our
offshore properties, 34% during 2003 as compared to approximately 10% during
2002, where we have a higher overall finding cost. The rate was also affected by
less than hoped for drilling results in the Gulf of Mexico and Southern
Louisiana, particularly in the fourth quarter, where some of our larger
exploration potential failed to materialize. In contrast to our offshore
properties, our tertiary operations have yielded a finding and development cost,
including the net change in forecasted future development and abandonment costs,
of just under $6.00 per BOE inception to December 31, 2004, in line with our
long-term expectations, helping to partially offset the higher finding and
development cost of our offshore and other natural gas properties.
Prior to 2003, we provided for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision was included in DD&A expense and
increased each year, along with a general increase in the number of our
properties, especially the acquisition of our offshore properties. Effective
January 1, 2003, we adopted Statement of Financial Accounting Standards ("SFAS")
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred, discounted to its present value
using our credit adjusted risk-free interest rate, and that a corresponding
amount be capitalized by increasing the carrying amount of the related
39
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
long-lived asset. The liability is accreted each period, and the capitalized
cost is depreciated over the useful life of the related asset. If the liability
is settled for an amount other than the recorded amount, the difference is
recorded to the full cost pool, unless significant. As part of this adoption, we
ceased accruing for site reclamation costs, as had been our practice in the
past, and recorded a $41.0 million liability representing the estimated present
value of our retirement obligations, with a $34.4 million increase to oil and
natural gas properties. On an undiscounted basis, we estimated our retirement
obligations as of December 31, 2003 to be $82.7 million, with an estimated
salvage value of $43.3 million, also on an undiscounted basis. As of December
31, 2004, we estimated our retirement obligations to be $52.1 million ($21.5
million present value), with an estimate salvage value of $43.6 million, the
decrease related to the sale of our offshore properties. DD&A is calculated on
the increase to oil and natural gas and CO2 properties, net of estimated salvage
value. We also include the accretion of discount on the asset retirement
obligation in our DD&A expense.
Under full cost accounting rules, we are required each quarter to perform a
ceiling test calculation. We did not have any full cost pool ceiling test write
downs in 2002, 2003 or 2004 and do not expect to have any such write downs in
the foreseeable future at current commodity price levels.
Income Taxes
Year Ended December 31,
- ----------------------------------------------------------------------------------------------------
Amounts in Thousands, Except Per BOE Amounts 2004 2003 2002
- ----------------------------------------------------------------------------------------------------
Current income tax expense (benefit) $ 22,929 $ (91) $ (406)
Defered income tax provision 16,463 26,303 23,926
- ----------------------------------------------------------------------------------------------------
Total income tax provision $ 39,392 $ 26,212 $ 23,520
====================================================================================================
Average income tax provision per BOE $ 3.27 $ 2.07 $ 1.81
Net effective tax rate 32.3% 32.7% 33.4%
Federal tax net operating loss carryforwards $ - $ 94,955 $ 84,891
Total net deferred tax asset (liability) (71,936) (43,539) (21,777)
- ----------------------------------------------------------------------------------------------------
Our income tax provision for 2004 was increased to an estimated statutory
tax rate of 39% to reflect the changes in our state income tax rates resulting
from the sale of our offshore properties. Our tax provision for 2002 and 2003
was based on an estimated statutory rate of 38%. Our net effective tax rate for
all periods was lower than the statutory rates, primarily due to the recognition
of enhanced oil recovery credits which lowered our overall tax rate. The current
income tax expense represents our anticipated alternative minimum cash taxes
that we could not offset with our regular tax net operating loss carryforwards
or our enhanced oil recovery credits. During the third quarter of 2004, we
recognized approximately $21.0 million of current income taxes as a result of
the sale of our offshore properties, which was a gain for income tax purposes.
The taxes on the offshore sale were primarily alternative minimum taxes as we
were able to offset the related regular tax with our net operating loss
carryforwards. As of December 31, 2004, we had utilized all of our federal tax
net operating loss carryforwards, but had an estimated $27.8 million of enhanced
oil recovery credits to carryforward. Since the ability to earn additional
enhanced oil recovery credits is reduced or even eliminated based on the level
of oil prices, our effective tax rate and cash taxes could both increase in the
future if oil prices remain at current levels or increase further.
Our overall current income tax credit for 2002 was the result of a tax law
change that allowed us to offset 100% of our 2001 alternative minimum taxes with
our alternative minimum tax net operating loss carryforwards. Prior to the law
change, we were able to offset only 90% of our alternative minimum taxes with
these carryforwards. This change resulted in a refund of cash taxes paid for
2001 and a reclassification of tax expense between current and deferred taxes,
but did not impact our overall effective tax rate.
40
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations on a per BOE Basis
The following table summarizes the cash flow, DD&A and results of
operations on a per BOE basis for the comparative periods. Each of the
individual components is discussed above.
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------------
Per BOE Data 2004 2003 2002
- --------------------------------------------------------------------------------------------------------------
Oil and natural gas revenues $ 36.88 $ 30.43 $ 21.17
Gain (loss) on settlements of derivative contracts (7.01) (4.91) 0.07
Lease operating expenses (7.22) (7.06) (5.48)
Production taxes and marketing expenses (1.55) (1.17) (0.92)
- --------------------------------------------------------------------------------------------------------------
Production netback 21.10 17.29 14.84
CO2 operating margin relating to industrial sales 0.41 0.51 0.48
General and administrative expenses (1.78) (1.20) (0.96)
Net cash interest expense (1.34) (1.61) (1.73)
Current income taxes and other (1.78) (0.01) 0.04
Changes in assets and liabilities relating to operations (2.63) 0.62 (0.38)
- --------------------------------------------------------------------------------------------------------------
Cash flow from operations 13.98 15.60 12.29
DD&A (8.09) (7.48) (7.26)
Deferred income taxes (1.37) (2.08) (1.84)
Non-cash hedging adjustments (0.11) 0.28 0.24
Changes in assets and liabilities, loss on early retirement of debt,
change in accounting principle and other non-cash items 2.43 (1.86) 0.17
- --------------------------------------------------------------------------------------------------------------
Net income $ 6.84 $ 4.46 $ 3.60
- --------------------------------------------------------------------------------------------------------------
MARKET RISK MANAGEMENT
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. The following table presents the carrying and fair
values of our debt, along with average interest rates. We had no bank debt
outstanding as of December 31, 2004. The fair value of the subordinated debt is
based on quoted market prices. None of our debt has any triggers or covenants
regarding our debt ratings with rating agencies.
Expected Maturity Dates
- --------------------------------------------------------------------------------------------------------------------------
Carrying Fair
Amounts in Thousands 2005 2006 2007 2008 2009 Value Value
- --------------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Subordinated debt, net of discount - - - - - $223,397 $243,000
(The interest rate on the subordinated debt is a fixed rate of 7.5%.)
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. Historically, we have generally attempted to hedge
between 50% and 75% of our anticipated production each year to provide us with a
reasonably certain amount of cash flow to cover most of our budgeted exploration
and development expenditures without incurring significant debt, although our
hedging percentage may vary relative to our debt levels. For 2005 and beyond, we
have hedged significantly less, primarily because of our strong financial
position resulted from our lower levels of debt relative to our cash flow from
operations. When we make a significant acquisition, we generally attempt to
hedge a large percentage, up to 100%, of the forecasted proved production for
the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. Much of our historical
hedging activity has been done with collars, although for the COHO acquisition,
we also used swaps in order to lock in the prices used in our economic
forecasts. For 2005, all of our oil hedges are puts or price floors, allowing us
to retain any price upside, while still providing protection in the event of
lower prices at a fixed and determinable price (i.e. the cost of the put). We
anticipate using more price floors in the future. All of the mark-to-market
valuations used for our financial derivatives are provided by external sources
and are based on prices that are actively quoted. We manage and control market
and counterparty credit risk through established internal control procedures
41
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
that are reviewed on an ongoing basis. We attempt to minimize credit risk
exposure to counterparties through formal credit policies, monitoring
procedures, and diversification. For a full description of our hedging position
at year-end 2004, see Note 9 to the Consolidated Financial Statements.
Upon reaching a verbal agreement with the purchaser (Newfield Exploration
Company) of our offshore properties, subject primarily to their further due
diligence, we entered into natural gas swaps on a total of 23.6 Bcf for the
period of July 2004 through December 2005, covering the anticipated natural gas
production from our offshore properties for that period, with the tacit
understanding with the prospective purchaser that these hedges would be
transferred to them upon closing. These swaps did not qualify for hedge
accounting and during the third quarter of 2004, we assigned them to Newfield.
During the period that we owned them, we recognized approximately $2.5 million
of gain as the hedges appreciated in value before we assigned them to Newfield.
At about the same time, with the expectation that the offshore transaction would
be consummated, we retired, by purchasing offsetting contracts, 20 MMcf/d of our
natural gas hedges for July to December of 2004, at a cost of approximately $3.9
million. This transaction, net of the related gain on the hedges assigned to
Newfield, was the primary reason for the $1.3 million net charge to earnings
during 2004 relating to our derivative contracts that were not part of the
monthly cash settlements on our derivatives contracts.
At December 31, 2004, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $4.9 million, a decrease of
approximately $39.7 million from the $44.6 million fair value liability recorded
as of December 31, 2003. This change is the result of the expiration of most of
our derivative contracts during 2004 due to the passage of time. Effective
January 1, 2005, we have elected to de-designate our existing derivative
contracts as hedges and to account for them as speculative contracts going
forward. This means that any changes in the fair value of these derivative
contracts will be charged to earnings on a quarterly basis instead of charging
the effective portion to other comprehensive income and the balance to earnings.
Information regarding our current hedging positions and historical hedging
results is included in Note 9 to the Consolidated Financial Statements.
Based on NYMEX crude oil futures prices at December 31, 2004, prices were
considerably higher than the floor price of $27.50, so we would not expect to
receive any funds even if oil prices were to drop 10%. Since the oil hedges are
puts or price floors, we do not have to make any payments on the hedges
regardless of how high oil prices would go. Based on NYMEX natural gas futures
prices at December 31, 2004, we would expect to make future cash payments of
$4.2 million on our natural gas commodity hedges. If natural gas futures prices
were to decline by 10%, the amount we would expect to pay under our natural gas
commodity hedges would decrease to $0.8 million, and if futures prices were to
increase by 10% we would expect to pay $7.6 million.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with generally
accepted accounting principles requires that we select certain accounting
policies and make certain estimates and judgments regarding the application of
those policies. Our significant accounting policies are included in Note 1 to
the Consolidated Financial Statements. These policies, along with the underlying
assumptions and judgments by our management in their application, have a
significant impact on our consolidated financial statements. Following is a
discussion of our most critical accounting estimates, judgments and
uncertainties that are inherent in the preparation of our financial statements.
Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural
Gas Reserves
Businesses involved in the production of oil and natural gas are required
to follow accounting rules that are unique to the oil and gas industry. We apply
the full-cost method of accounting for our oil and natural gas properties.
Another acceptable method of accounting for oil and gas production activities is
the successful efforts method of accounting. In general, the primary differences
between the two methods are related to the capitalization of costs and the
evaluation for asset impairment. Under the full-cost method, all geological and
geophysical costs, exploratory dry holes and delay rentals are capitalized to
the full cost pool, whereas under the successful efforts method such costs are
expensed as incurred. In the assessment of impairment of oil and gas properties,
the successful efforts method follows the guidance of SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," under which assets are
measured for impairment against the undiscounted future cash flows using
commodity prices consistent with management expectations. Under the full-cost
method, the full cost pool (net book value of oil and gas properties) is
measured against future cash flows discounted at ten percent using commodity
prices in effect at the end of the reporting period. The financial results for a
42
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
given period could be substantially different depending on the method of
accounting an oil and gas entity applies.
In our application of full cost accounting for our oil and gas producing
activities, we make significant estimates at the end of each period related to
accruals for oil and gas revenues, production, capitalized costs and operating
expenses. We calculate these estimates with our best available data, which
includes among other things, production reports, price posting, information
compiled from daily drilling reports and other internal tracking devices and
analysis of historical results and trends. While management is not aware of any
required revisions to its estimates, there will likely be future adjustments
resulting from such things as changes in ownership interests, payouts, joint
venture audits, re-allocations by the purchaser/pipeline, or other corrections
and adjustments common in the oil and natural gas industry, many of which will
require retroactive application. These types of adjustments cannot be currently
estimated or determined and will be recorded in the period during which the
adjustment occurs.
Under full cost accounting, the estimated quantities of proved oil and
natural gas reserves used to compute depletion and the related present value of
estimated future net cash flows therefrom used to perform the full-cost ceiling
test have a significant impact on the underlying financial statements. The
process of estimating oil and natural gas reserves is very complex, requiring
significant decisions in the evaluation of all available geological,
geophysical, engineering and economic data. The data for a given field may also
change substantially over time as a result of numerous factors, including
additional development activity, evolving production history and continued
reassessment of the viability of production under varying economic conditions.
As a result, material revisions to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure that the
reported reserve estimates represent the most accurate assessments possible,
including the hiring of independent engineers to prepare the report, the
subjective decisions and variances in available data for various fields make
these estimates generally less precise than other estimates included in our
financial statement disclosures. Over the last four years, Denbury's annual
revisions to its reserve estimates have averaged approximately 3% of the
previous year's estimates and have been both positive and negative.
Changes in commodity prices also affect our reserve quantities. For
instance, between 2001 and 2002, commodity prices rebounded from the prior
year's fall, resulting in an increase to our reserve quantities of approximately
3.5 MMBOE. During 2003 and 2004, the change related to commodity prices was
virtually zero, less than in prior years, as prices were relatively high at
year-end 2002, 2003 and 2004. These changes in quantities affect our DD&A rate
and the combined effect of changes in quantities and commodity prices impacts
our full-cost ceiling test calculation. For example, we estimate that a 5%
increase in our estimate of proved reserves quantities would have lowered our
fourth quarter DD&A rate from $7.98 per Bbl to approximately $7.64 per Bbl and a
5% decrease in our proved reserve quantities would have increased our DD&A rate
to approximately $8.35 per Bbl. Also, reserve quantities and their ultimate
values are the primary factors in determining the borrowing base under our bank
credit facility and are determined solely by our banks.
There can also be significant questions as to whether reserves are
sufficiently supported by technical evidence to be considered proven. In some
cases our proven reserves are less than what we believe to exist because
additional evidence, including production testing, is required in order to
classify the reserves as proven. In other cases, properties such as certain of
our potential tertiary recovery projects may not have proven reserves assigned
to them primarily because we have not yet completed a specific plan for
development or firmly scheduled such development. We have a corporate policy
whereby we generally do not book proved undeveloped reserves unless the project
has been committed to internally, which normally means it is scheduled within
the next one to three years (or at least the commencement of the project is
scheduled in the case of longer-term multi-year projects such as waterfloods and
tertiary recovery projects). Therefore, particularly with regard to potential
reserves from tertiary recovery (our CO2 operations), there is uncertainty as to
whether the reserves should be included as proven or not. We also have a
corporate policy whereby proved undeveloped reserves must be economic at
long-term historical prices, which during the last two years are significantly
less than the year-end prices used in our reserve report. This also can have the
effect of eliminating certain projects being included in our estimates of proved
reserves, which projects would otherwise be included if undeveloped reserves
were determined to be economic solely based on current prices in a high price
environment, as was the case at year-end 2003 and year-end 2004. (See
"Depletion, Depreciation and Amortization" under "Results of Operations" above
for a further discussion.) All of these factors and the decisions made regarding
these issues can have a significant effect on our proven reserves and thus on
our DD&A rate, full-cost ceiling test calculation, borrowing base and financial
statements.
43
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Asset Retirement Obligations
We have significant obligations related to the plugging and abandonment of
our oil and gas wells, and the removal of equipment and facilities from leased
acreage and returning such land to its original condition. SFAS No. 143 requires
that we estimate the future cost of this obligation, discount it to its present
value, and record a corresponding asset and liability in our Consolidated
Balance Sheets. The values ultimately derived are based on many significant
estimates, including the ultimate expected cost of the obligation, the expected
future date of the required cash payment, and interest and inflation rates.
Revisions to these estimates may be required based on changes to cost estimates,
the timing of settlement, and changes in legal requirements. Any such changes
that result in upward or downward revisions in the estimated obligation will
result in an adjustment to the related capitalized asset and corresponding
liability on a prospective basis and an adjustment in our DD&A expense in future
periods. See Note 4 to our Consolidated Financial Statements for further
discussion regarding our asset retirement obligations.
Income Taxes
We make certain estimates and judgments in determining our income tax
expense for financial reporting purposes. These estimates and judgments occur in
the calculation of certain tax assets and liabilities that arise from
differences in the timing and recognition of revenue and expense for tax and
financial reporting purposes. Our federal and state income tax returns are
generally not prepared or filed before the consolidated financial statements are
prepared, therefore we estimate the tax basis of our assets and liabilities at
the end of each period as well as the effects of tax rate changes, tax credits
and prior to year-end 2004, net operating loss carryforwards. Adjustments
related to these estimates are recorded in our tax provision in the period in
which we file our income tax returns. Further, we must assess the likelihood
that we will be able to recover or utilize our deferred tax assets (primarily
our enhanced oil recovery credits). If recovery is not likely, we must record a
valuation allowance against such deferred tax assets for the amount we would not
expect to recover, which would result in an increase to our income tax expense.
As of December 31, 2004, we believe that all of our deferred tax assets recorded
on our Consolidated Balance Sheet will ultimately be recovered. If our estimates
and judgments change regarding our ability to utilize our deferred tax assets,
our tax provision would increase in the period it is determined that recovery is
not probable. A 1% change in our effective tax rate would have increased our
calculated income tax expense by approximately $1,200,000, $800,000, and
$700,000 for the years ended December 31, 2004, 2003 and 2002. See Note 7 to the
Consolidated Financial Statements for further information concerning our income
taxes.
Hedging Activities
We enter into derivative contracts (i.e., hedges) to mitigate our exposure
to commodity price risk associated with future oil and natural gas production.
These contracts have historically consisted of options, in the form of price
floors or collars, and fixed price swaps. With the adoption of SFAS No. 133 in
2001, every derivative instrument was required to be recorded on the balance
sheet as either an asset or a liability measured at its fair value. If the
derivative does not qualify as a hedge or is not designated as a hedge, the
change in fair value of the derivative is recognized currently in earnings. If
the derivative qualifies for cash flow hedge accounting, the change in fair
value of the derivative is recognized in other comprehensive income (equity) to
the extent that the hedge is effective and in the income statement to the extent
it is ineffective. We recognized ineffectiveness on our hedges of $600,000 for
2002, $282,000 for 2003 and $2.7 million for 2004.
With the significant changes in commodity prices over the last two years,
the fair value of our hedges has fluctuated significantly. While most of this
change in value is recorded in other comprehensive income as most of our
historical hedges have qualified for hedge accounting, the dramatic swing in
commodity prices and the corresponding effect on the fair value of our hedges
can cause a dramatic change to our balance sheet. In order to qualify for hedge
accounting the relationship between the hedging instruments and the hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk, both at the inception of the hedge
and on an ongoing basis. We measure and compute hedge effectiveness on a
quarterly basis. If a hedging instrument becomes ineffective, hedge accounting
is discontinued and any deferred gains or losses on the cash flow hedge remain
in accumulated other comprehensive income until the periods during which the
hedges would have otherwise expired. If we determine it probable that a hedged
forecasted transaction will not occur, deferred gains or losses on the hedging
instrument are recognized in earnings immediately.
Most our current derivative hedging instruments qualify for hedge
accounting although we plan to abandon hedge accounting as of January 1, 2005.
This means that any changes in the future fair value of these derivative
contracts will be charged to earnings on a quarterly basis instead of charging
44
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
the effective portion to other comprehensive income and the balance to earnings.
For our three most recently completed fiscal years, if we had not chosen to
designate hedge accounting treatment to our oil and natural gas hedge contracts,
or if none of our derivative contracts had qualified for hedge accounting
treatment, we estimate that our net income would have increased or (decreased)
for 2004, 2003 and 2002 by the following amounts: $25.0 million, $(7.8) million
and $(38.5) million.
The preparation of financial statements requires us to make other estimates
and assumptions that affect the reported amounts of certain assets, liabilities,
revenues and expenses during each reporting period. We believe that our
estimates and assumptions are reasonable and reliable and believe that the
ultimate actual results will not differ significantly from those reported;
however, such estimates and assumptions are subject to a number of risks and
uncertainties and such risks and uncertainties could cause the actual results to
differ materially from our estimates.
RECENT ACCOUNTING PRONOUNCEMENTS
On December 16, 2004, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R)
supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally,
the approach in SFAS No. 123(R) is similar to the approach described in SFAS No.
123. However, SFAS No. 123(R) will require all share-based payments to
employees, including grants of employee stock options, to be recognized in our
Consolidated Statements of Operations based on their estimated fair values. Pro
forma disclosure is no longer an alternative.
SFAS No. 123(R) must be adopted no later that July 1, 2005 and permits
public companies to adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is
recognized based on the requirements of SFAS No. 123(R) for all
share-based payments granted prior to the effective date of SFAS No.
123(R) that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of
the modified prospective method described above, but also permits
entities to restate either all prior periods presented or prior
interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
As permitted by SFAS No. 123, we currently account for share-based payments
to employees using the intrinsic value method prescribed by APB 25 and related
interpretations. As such, we generally do not recognize compensation expense
associated with employee stock options. Accordingly, the adoption of SFAS No.
123(R)'s fair value method could have a significant impact on Denbury's future
results of operations, although it will have no impact on our overall financial
position. Had the Company adopted SFAS No 123(R) in prior periods, the impact
would have approximated the impact of SFAS No. 123 as described in the pro forma
net income and earnings per share disclosures above. The adoption of SFAS No.
123 (R) will have no effect on the Company's unvested outstanding restricted
stock awards. We currently plan to adopt the provisions of SFAS No. 123(R) on
July 1, 2005 using the modified prospective method. Although we have not
completed evaluating the impact the adoption of SFAS No. 123(R) will have on our
future results of operations, we currently estimate the impact on an annual
basis will be similar to our pro forma disclosures for SFAS No. 123 in Note 1 to
the Consolidated Financial Statements.
SFAS No. 123(R) also requires the tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce the Denbury's future cash provided by operating activities and
increase future cash provided by financing activities, to the extent of
associated tax benefits that may be realized in the future. While we cannot
estimate what those amounts will be in the future (because they depend, among
other things, when employees exercise stock options), the amount of operating
cash flows recognized in prior periods for such excess tax deductions were $4.8
million, $1.3 million and $0.7 million during the years ended December 31, 2004,
2003, and 2002, respectively.
In July 2004, the Emerging Issues Task Force of the FASB issued EITF 04-05,
"Investor's Accounting for an Investment in a Limited Partnership When the
Investor is the Sole General Partner and the Limited Partners Have Certain
Rights." In question is what rights held by the limited partners preclude
consolidation of the limited partnership by the sole general partner. The Task
Force noted that in practice differing views have evolved concerning this issue
and it has asked the FASB staff to develop this issue for discussion at a future
date. Denbury is the general partner of Genesis Energy, L.P. ("Genesis") and
currently does not consolidate Genesis in its financial results based primarily
on certain rights of the limited partner. This EITF has been issued for comment,
with the comment period ending in February 2005. Based on our initial review of
the proposed EITF, we currently do not believe that it will impact our
consolidation treatment of Genesis; however, this determination is subject to
further review and evaluation of the final rules. See Note 3, "Related Party
Transactions - Genesis" for further information regarding Denbury's accounting
for its investment in Genesis.
45
Denbury Resources Inc.
Management's Discussion and Analysis of
Financial Condition and Results of Operations
FORWARD-LOOKING INFORMATION
The statements contained in this Annual Report on Form 10-K that are not
historical facts, including, but not limited to, statements found in this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, are forward-looking statements, as that term is defined in Section
21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward-looking statements may be or may
concern, among other things, forecasted capital expenditures, drilling activity
or methods, acquisition plans and proposals and dispositions, development
activities, cost savings, production rates and volumes, hydrocarbon reserves,
hydrocarbon prices, liquidity, regulatory matters, mark-to-market values,
competition and long-term forecasts of production, finding cost, rates of
return, estimated costs, future capital expenditures and overall economics and
other variables surrounding our tertiary operations and future plans. Such
forward-looking statements generally are accompanied by words such as "plan,"
"estimate," "expect," "predict," "anticipate," "projected," "should," "assume,"
"believe", "target" or other words that convey the uncertainty of future events
or outcomes. Such forward-looking information is based upon management's current
plans, expectations, estimates and assumptions and is subject to a number of
risks and uncertainties that could significantly affect current plans,
anticipated actions, the timing of such actions and the Company's financial
condition and results of operations. As a consequence, actual results may differ
materially from expectations, estimates or assumptions expressed in or implied
by any forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas,
inaccurate cost estimates, fluctuations in the prices of goods and services, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital or its availability, general
economic conditions, competition and government regulations, unexpected delays,
as well as the risks and uncertainties inherent in oil and gas drilling and
production activities or which are otherwise discussed in this annual report,
including, without limitation, the portions referenced above, and the
uncertainties set forth from time to time in the Company's other public reports,
filings and public statements.
This Annual Report is not deemed to be "soliciting material" or to be
"filed" with the Securities and Exchange Commission or subject to the
liabilities of Section 18 of the Securities Act of 1934.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------
The information required by Item 7A is set forth under "Market Risk
Management" in "Management's Discussion and Analysis of Financial Condition and
Results of Operations," appearing on pages 41 through 42.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ---------------------------------------------------
Page
----
Management's Report on Internal Control over Financial Reporting....... 47
Reports of Independent Registered Public Accounting Firms.............. 48-49
Consolidated Balance Sheets............................................ 50
Consolidated Statements of Operations.................................. 51
Consolidated Statements of Cash Flows.................................. 52
Consolidated Statements of Stockholders' Equity........................ 53
Consolidated Statements of Comprehensive Income........................ 54
Notes to Consolidated Financial Statements............................. 55-85
Supplemental Oil and Natural Gas Disclosures (Unaudited)............... 81
Quarterly Financial Information (Unaudited)............................ 85
46
MANAGEMENT'S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
Our management, including the Chief Executive Officer and the Chief
Financial Officer, is responsible for establishing and maintaining adequate
internal controls over financial reporting, as defined in Rules 13a-15(f) and
15d-15(f) of the Securities Exchange Act of 1934, as amended. Our system of
internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. Our internal control over financial
reporting includes those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the Company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the Company are
being made only in accordance with authorizations of management and directors of
the Company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
Company's assets that could have a material effect on the financial statements.
Internal control over financial reporting cannot provide absolute assurance
of achieving financial reporting objectives because of its inherent limitations.
Internal control over financial reporting is a process that involves human
diligence and compliance and is subject to lapses in judgment and breakdowns
resulting from human failures. Internal control over financial reporting also
can be circumvented by collusion or improper management override. Because of
such limitations, there is a risk that material misstatements may not be
prevented or detected on a timely basis by internal control over financial
reporting. However, these inherent limitations are known features of the
financial reporting process. Therefore, it is possible to design into the
process safeguards to reduce, though not eliminate, this risk.
Our management assessed the effectiveness of our internal control over
financial reporting as of December 31, 2004. In making this assessment, our
management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in INTERNAL CONTROL-INTEGRATED
FRAMEWORK. Based on our management's assessment, we have concluded that our
internal control over financial reporting was effective as of December 31, 2004
based on those criteria.
Our management's assessment of the effectiveness of the Company's internal
control over financial reporting as of December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their audit report which appears herein.
47
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Denbury Resources Inc.:
We have completed an integrated audit of Denbury Resources Inc.'s 2004
consolidated financial statements and of its internal control over financial
reporting as of December 31, 2004 in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Our opinions, based on our
audit, are presented below.
Consolidated financial statements
- ---------------------------------
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
Denbury Resources Inc. and its subsidiaries (the "Company") at December 31,
2004, and the results of their operations and their cash flows for the year
ended December 31, 2004 in conformity with accounting principles generally
accepted in the United States of America. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit. We conducted our audit
of these statements in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit of financial statements
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
Internal control over financial reporting
- -----------------------------------------
Also, in our opinion, management's assessment, included in the accompanying
"Management's Report on Internal Control over Financial Reporting," that the
Company maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), is fairly stated, in all material respects, based on those
criteria. Furthermore, in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2004, based on criteria established in Internal Control - Integrated Framework
issued by the COSO. The Company's management is responsible for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting. Our
responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit. We conducted our audit of internal control over financial
reporting in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PRICEWATERHOUSECOOPERS LLP
- ------------------------------
Dallas, Texas
March 14, 2005
48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders of Denbury Resources Inc.
We have audited the accompanying consolidated balance sheet of Denbury Resources
Inc. and Subsidiaries (the "Company") as of December 31, 2003, and the related
consolidated statements of operations, cash flows, stockholders' equity and
comprehensive income for each of the two years in the period ended December 31,
2003. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2003, and the
results of its operations and its cash flows for each of the two years in the
period ended December 31, 2003 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 to the financial statements under the caption "Asset
Retirement Obligations", the Company changed its method of accounting for asset
retirement obligations in 2003 as required by Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations".
/s/ Deloitte & Touche LLP
- -------------------------
Dallas, Texas
March 8, 2004
49
Denbury Resources Inc.
Consolidated Balance Sheets
(In Thousands, Except Shares) December 31,
- -------------------------------------------------------------------------------------------------------
Assets 2004 2003
--------------- ---------------
Current Assets
Cash and cash equivalents...................................... $ 33,039 $ 24,188
Short-term investments......................................... 57,171 -
Accrued production receivable.................................. 44,790 33,944
Related party receivable - Genesis............................. 745 6,927
Trade and other receivables, net of allowance of $236 and $238. 10,963 18,080
Deferred tax asset............................................. 25,189 25,016
Derivative assets.............................................. 949 -
--------------- ---------------
Total current assets......................................... 172,846 108,155
--------------- ---------------
Property and Equipment
Oil and natural gas properties (using full cost accounting)
Proved....................................................... 1,326,401 1,409,579
Unevaluated.................................................. 20,253 46,065
CO2 properties and equipment................................... 132,685 85,467
Other ........................................................ 25,929 16,450
Less accumulated depletion and depreciation.................... (707,906) (705,050)
--------------- ---------------
Net property and equipment................................... 797,362 852,511
--------------- ---------------
Investment in Genesis.......................................... 6,791 7,450
Other assets................................................... 15,707 14,505
--------------- ---------------
Total Assets................................................. $ 992,706 $ 982,621
=============== ===============
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable and accrued liabilities....................... $ 51,860 $ 62,349
Oil and gas production payable................................. 24,856 22,215
Derivative liabilities......................................... 5,815 42,010
Short-term capital lease obligations - Genesis................. 375 -
--------------- ---------------
Total current liabilities.................................... 82,906 126,574
--------------- ---------------
Long-term Liabilities
Capital lease obligations - Genesis............................ 4,184 -
Long-term debt................................................. 223,397 298,203
Asset retirement obligations................................... 18,944 41,711
Derivative liabilities......................................... - 2,603
Deferred revenue - Genesis..................................... 23,378 21,468
Deferred tax liability......................................... 97,125 68,555
Other.......................................................... 1,100 2,305
--------------- ---------------
Total long-term liabilities.................................. 368,128 434,845
--------------- ---------------
Commitments and Contingencies (Note 10)
Stockholders' Equity
Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding ...................................... - -
Common stock, $.001 par value, 100,000,000 shares authorized;
56,607,877, and 54,190,042 shares issued at December 31,
2004 and 2003, respectively.................................. 57 54
Paid-in capital in excess of par............................... 441,023 401,709
Deferred compensation.......................................... (21,678) -
Retained earnings ............................................. 129,104 46,656
Accumulated other comprehensive loss........................... (4,788) (27,113)
Treasury stock, at cost, 93,072 and 8,162 shares at December 31, 2004
and 2003, respectively....................................... (2,046) (104)
--------------- ---------------
Total stockholders' equity................................... 541,672 421,202
--------------- ---------------
Total Liabilities and Stockholders' Equity................... $ 992,706 $ 982,621
=============== ===============
See Notes to Consolidated Financial Statements.
50
Denbury Resources Inc.
Consolidated Statements of Operations
(In Thousands, Except Per Share Data) Year Ended December 31,
- --------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------- ------------ -------------
Revenues
Oil, natural gas and related product sales
Unrelated parties............................................ $ 381,253 $ 336,521 $ 251,972
Related party - Genesis...................................... 63,524 48,942 22,922
CO2 sales and transportation fees
Unrelated parties............................................ 1,183 7,512 7,580
Related party - Genesis...................................... 5,093 676 -
Gain (loss) on effective hedge contracts....................... (70,469) (62,210) 932
Interest income and other...................................... 2,388 1,573 1,746
------------- ------------ -------------
Total revenues............................................... 382,972 333,014 285,152
------------- ------------ -------------
Expenses
Lease operating expenses....................................... 87,107 89,439 71,188
Production taxes and marketing expenses........................ 17,569 14,819 11,902
Transportation expense - Genesis............................... 1,168 - -
CO2 operating expenses......................................... 1,338 1,710 1,400
General and administrative..................................... 21,461 15,189 12,426
Interest....................................................... 19,468 23,201 26,833
Loss on early retirement of debt............................... - 17,629 -
Depletion, depreciation and accretion.......................... 97,527 94,708 94,236
(Gain) loss on ineffective hedge contracts..................... 15,358 (3,578) (3,093)
------------- ------------ -------------
Total expenses............................................... 260,996 253,117 214,892
------------- ------------ -------------
Equity in net income (loss) of Genesis........................... (136) 256 55
------------- ------------ -------------
Income before income taxes....................................... 121,840 80,153 70,315
Income tax provision (benefit)
Current income taxes........................................... 22,929 (91) (406)
Deferred income taxes.......................................... 16,463 26,303 23,926
------------- ------------ -------------
Income before cumulative effect of change in accounting principle 82,448 53,941 46,795
Cumulative effect of change in accounting principle, net of income
taxes of $1,600................................................ - 2,612 -
------------- ------------ -------------
Net income....................................................... $ 82,448 $ 56,553 $ 46,795
============= ============ =============
Net income per share - basic
Income before cumulative effect of change in accounting principle $ 1.50 $ 1.00 $ 0.88
Cumulative effect of change in accounting principle............ - 0.05 -
------------- ------------ -------------
Net income per common share - basic............................ $ 1.50 $ 1.05 $ 0.88
============= ============ =============
Net income per share - diluted
Income before cumulative effect of change in accounting principle $ 1.44 $ 0.97 $ 0.86
Cumulative effect of change in accounting principle............ - 0.05 -
------------- ------------ -------------
Net income per common share - diluted.......................... $ 1.44 $ 1.02 $ 0.86
============= ============ =============
Weighted average common shares outstanding
Basic.......................................................... 54,871 53,881 53,243
Diluted........................................................ 57,301 55,464 54,365
See Notes to Consolidated Financial Statements.
51
Denbury Resources Inc.
Consolidated Statements of Cash Flows
(In Thousands) Year Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------
2004 2003 2002
-------------- ------------- ------------
Cash Flow from Operating Activities:
Net income...................................................... $ 82,448 $ 56,553 $ 46,795
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and accretion........................ 97,527 94,708 94,236
Deferred income taxes........................................ 16,463 26,303 23,926
Deferred revenue - Genesis................................... (2,399) (322) -
Deferred compensation - restricted stock..................... 1,601 - -
Loss on early retirement of debt............................. - 17,629 -
Non-cash hedging adjustments................................. 1,270 (3,578) (3,093)
Amortization of debt issue costs and other................... 3,283 1,121 2,701
Cumulative effect of change in accounting principle.......... - (2,612) -
Changes in assets and liabilities relating to operations:
Accrued production receivable................................ (19,776) (3,079) (14,381)
Trade and other receivables.................................. 7,475 (1,234) 15,078
Derivative assets and liabilities............................ (7,519) - 8,427
Other assets................................................. (166) 7 133
Accounts payable and accrued liabilities..................... (10,522) 8,862 (17,217)
Oil and gas production payable............................... 2,641 4,906 3,869
Other liabilities............................................ (3,674) (1,649) (874)
-------------- ------------- ------------
Net Cash Provided by Operating Activities........................ 168,652 197,615 159,600
-------------- ------------- ------------
Cash Flow Used for Investing Activities:
Oil and natural gas expenditures............................... (167,001) (146,596) (99,273)
Acquisitions of oil and gas properties......................... (11,069) (11,848) (56,364)
Investment in Genesis.......................................... - (5,026) (2,170)
Acquisition of CO2 assets and capital expenditures............. (50,265) (22,673) (16,445)
Net purchases of other assets.................................. (5,210) (2,192) (3,688)
Deposit on oil and gas property acquisitions................... (4,507) - -
Increase in restricted cash.................................... (542) (848) (909)
Purchases of short-term investments............................ (76,517) - -
Sales of short-term investments................................ 19,350 - -
Net proceeds from CO2 production payment - Genesis............. 4,636 23,895 -
Proceeds from sales of oil and gas properties.................. 10,042 29,410 7,688
Sale of Denbury Offshore, Inc.................................. 187,533 - -
-------------- ------------- ------------
Net Cash Used for Investing Activities........................... (93,550) (135,878) (171,161)
-------------- ------------- ------------
Cash Flow from Financing Activities:
Bank repayments................................................ (88,000) (160,000) (40,000)
Bank borrowings................................................ 13,000 85,000 49,130
Payments on capital lease obligations - Genesis................ (32) - -
Repayment of subordinated debt obligations, including redemption premium - (209,000) -
Issuance of subordinated debt, net of discount................. - 223,054 -
Issuance of common stock....................................... 13,168 5,537 3,594
Purchase of treasury stock..................................... (3,977) (1,268) -
Costs of debt financing........................................ (410) (4,812) (719)
-------------- ------------- ------------
Net Cash Provided by (Used for) Financing Activities............. (66,251) (61,489) 12,005
-------------- ------------- ------------
Net Increase in Cash and Cash Equivalents........................ 8,851 248 444
Cash and cash equivalents at beginning of year................... 24,188 23,940 23,496
-------------- ------------- ------------
Cash and cash equivalents at end of year......................... $ 33,039 $ 24,188 $ 23,940
============== ============= ============
See Notes to Consolidated Financial Statements.
52
Denbury Resources Inc.
Consolidated Statements of Changes in Stockholders' Equity
Paid-In Accumulated Treasury
Common Stock Capital Restricted Retained Other Stock
($.001 Par Value) in Stock Earnings Comprehensive (at cost) Total
------------------- Excess Deferred (Accumulated Income -------------- Stockholders'
(Dollar amounts in Thousands) Shares Amount of Par Compensation Deficit) (Loss) Shares Amount Equity
- ---------------------------------------------------------------------------------------------------------------------------------
Balance - December 31, 2001 52,956,825 $ 53 $391,557 $ - $(56,670) $ 14,228 - $ - $349,168
Issued pursuant to employee
stock purchase plan 203,893 - 1,928 - - - - - 1,928
Issued pursuant to employee
stock option plan 370,120 1 1,665 - - - - - 1,666
Issued pursuant to directors'
compensation plan 8,491 - 82 - - - - - 82
Tax benefit from stock options - - 674 - - - - - 674
Derivative contracts, net - - - - - (33,516) - - (33,516)
Net income - - - - 46,795 - - - 46,795
----------------------------------------------------------------------------------------------------
Balance - December 31, 2002 53,539,329 54 395,906 - (9,875) (19,288) - - 366,797
---------------------------------------------------------------------------------------------------
Repurchase of common stock - - - - - - 100,000 (1,276) (1,276)
Issued pursuant to employee
stock purchase plan 94,968 - 1,174 - (22) - (91,838) 1,172 2,324
Issued pursuant to employee
stock option plan 550,090 - 3,213 - - - - - 3,213
Issued pursuant to directors'
compensation plan 5,655 - 69 - - - - - 69
Tax benefit from stock options - - 1,347 - - - - - 1,347
Derivative contracts, net - - - - - (7,825) - - (7,825)
Net income - - - - 56,553 - - - 56,553
---------------------------------------------------------------------------------------------------
Balance - December 31, 2003 54,190,042 54 401,709 - 46,656 (27,113) 8,162 (104) 421,202
----------------------------------------------------------------------------------------------------
Repurchase of common stock - - - - - - 200,000 (3,977) (3,977)
Issued pursuant to employee
stock purchase plan - - 396 - - - (115,090) 2,035 2,431
Issued pursuant to employee
stock option plan 1,264,284 2 10,737 - - - - - 10,739
Issued pursuant to directors'
compensation plan 3,551 - 82 - - - - - 82
Restricted stock grants 1,150,000 1 23,278 (23,279) - - - - -
Amortization of deferred
compensation - - - 1,601 - - - - 1,601
Tax benefit from stock options - - 4,821 - - - - - 4,821
Derivative contracts, net - - - - - 22,349 - - 22,349
Unrealized loss on available-
for-sale securities - - - - - (24) - - (24)
Net income - - - - 82,448 - - - 82,448
----------------------------------------------------------------------------------------------------
Balance - December 31, 2004 56,607,877 $ 57 $441,023 $ (21,678) $ 129,104 $(4,788) 93,072 $(2,046) $541,672
====================================================================================================
See Notes to Consolidated Financial Statements.
53
Denbury Resources Inc.
Consolidated Statements of Comprehensive Income
(In Thousands) Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------- ------------- -------------
Net Income......................................................... $ 82,448 $ 56,553 $ 46,795
Other comprehensive income (loss), net of tax:
Change in fair value of derivative contracts, net of tax of
($19,328), ($26,969) and ($18,784), respectively............... (31,535) (44,002) (30,648)
Reclassification adjustments related to settlements of derivative
contracts, net of tax of $33,025, $22,173 and ($1,758), respectively 53,884 36,177 (2,868)
Unrealized loss on securities available for sale, net of tax of ($15) (24) - -
------------- ------------- -------------
Comprehensive Income............................................... $ 104,773 $ 48,728 $ 13,279
============= ============= =============
See Notes to Consolidated Financial Statements.
54
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
Denbury Resources Inc. is a Delaware corporation, organized under Delaware
General Corporation Law, engaged in the acquisition, development, operation and
exploration of oil and natural gas properties. Denbury has one primary business
segment, which is the exploration, development and production of oil and natural
gas in the U.S. Gulf Coast region. We also own the rights to a natural source of
carbon dioxide ("CO2") reserves that we use for injection in our tertiary oil
recovery operations. We also sell some of the CO2 we produce to third parties
for various industrial uses.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in
accordance with generally accepted accounting principles ("GAAP") and include
the accounts of Denbury and its subsidiaries, all of which are wholly owned. In
2002, one of our subsidiaries acquired the general partner of Genesis Energy,
L.P. ("Genesis"), a publicly traded master limited partnership. During 2003, we
acquired additional Genesis limited partnership units, increasing our ownership
interest in Genesis from 2% to 9.25%. We account for our ownership interest in
Genesis under the equity method of accounting. Even though we have significant
influence over the limited partnership in our role as general partner, because
our control is limited by the general partnership agreement we do not
consolidate Genesis. See Note 3 for more information regarding our related party
transactions with Genesis and summary financial information. All material
intercompany balances and transactions have been eliminated. We have evaluated
our consolidation of variable interest entities in accordance with FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities," and have
concluded that we do not have any variable interest entities that would require
consolidation.
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 remained 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.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS. We follow the full-cost method of accounting for oil
and natural gas properties. Under this method, all costs related to
acquisitions, exploration and development of oil and natural gas reserves are
capitalized and accumulated in a single cost center representing our activities,
which are undertaken exclusively in the United States. Such costs include lease
acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and non-productive
wells and general and administrative expenses directly related to exploration
and development activities and do not include any costs related to production,
general corporate overhead or similar activities. Proceeds received from
disposals are credited against accumulated costs except when the sale represents
a significant disposal of reserves, in which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION. The costs capitalized, including production
equipment, are depleted or depreciated on the unit-of-production method, based
55
Denbury Resources Inc.
Notes to Consolidated Financial Statements
on proved oil and natural gas reserves as determined by independent petroleum
engineers. Oil and natural gas reserves are converted to equivalent units based
upon the relative energy content which is six thousand cubic feet of natural gas
to one barrel of crude oil.
C) ASSET RETIREMENT OBLIGATIONS. On January 1, 2003, we adopted the
provisions of Statement of Financial Accounting Standards ("SFAS") No. 143,
"Accounting for Asset Retirement Obligations." In general, our future asset
retirement obligations relate to future costs associated with plugging and
abandonment of our oil and natural gas wells, removal of equipment and
facilities from leased acreage and returning such land to its original
condition. SFAS No. 143 requires that the fair value of a liability for an asset
retirement obligation be recorded in the period in which it is incurred,
discounted to its present value using our credit adjusted risk-free interest
rate, and a corresponding amount capitalized by increasing the carrying amount
of the related long-lived asset. The liability is accreted each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Revisions to estimated retirement obligations will result in an adjustment to
the related capitalized asset and corresponding liability. If the liability is
settled for an amount other than the recorded amount, the difference is recorded
to the full cost pool, unless significant. Prior to the adoption of this new
standard, we recognized a provision for our asset retirement obligations each
period as part of our depletion and depreciation calculation, based on the
unit-of-production method. See Note 4 for more information regarding our change
in accounting related to the adoption of SFAS No. 143.
D) CEILING TEST. The net capitalized costs of oil and natural gas
properties are limited to the lower of unamortized cost or the cost center
ceiling. The cost center ceiling is defined as the sum of (i) the present value
of estimated future net revenues from proved reserves before future abandonment
costs (discounted at 10%), based on unescalated period-end oil and natural gas
prices; (ii) plus the cost of properties not being amortized; (iii) plus the
lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any; (iv) less related income tax effects. The cost
center ceiling test is prepared quarterly.
E) JOINT INTEREST OPERATIONS. Substantially all of our oil and natural gas
exploration and production activities are conducted jointly with others. These
financial statements reflect only Denbury's proportionate interest in such
activities and any amounts due from other partners are included in trade
receivables.
F) PROVED RESERVES. See Note 13 for information on our proved oil and
natural gas reserves and the basis on which they are recorded.
Property and equipment - Other
Other property and equipment, which includes furniture and fixtures,
vehicles, computer equipment and software, and capitalized leases, are
depreciated principally on a straight-line basis over estimated useful lives.
Estimated useful lives are generally as follows: furniture and fixtures and
vehicles 5 to 10 years; and computer equipment and software 3 to 5 years.
Leased property meeting certain capital lease criteria is capitalized
and the present value of the related lease payments is recorded as a liability.
Amortization of capitalized leased assets is computed using the straight-line
method over the shorter of the estimated useful life or the initial lease term.
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold.
Any amounts due from purchasers of oil and natural gas are included in accrued
production receivables.
We follow the "sales method" of accounting for our oil and natural gas
revenue, whereby we recognize sales revenue on all oil or natural gas sold to
our purchasers regardless of whether the sales are proportionate to our
ownership in the property. A receivable or liability is recognized only to the
56
Denbury Resources Inc.
Notes to Consolidated Financial Statements
extent that we have an imbalance on a specific property greater than the
expected remaining proved reserves. As of December 31, 2004 and 2003, our
aggregate oil and natural gas imbalances were not material to our consolidated
financial statements.
We recognize revenue and expenses of purchased producing properties at the
time we assume effective control, commencing from either the closing or purchase
agreement date, depending on the underlying terms and agreements. We follow the
same methodology in reverse when we sell properties by recognizing revenue and
expenses of the sold properties until either the closing or purchase agreement
date, depending on the underlying terms and agreements.
Derivative Instruments and Hedging Activities
We enter into derivative contracts to mitigate our exposure to commodity
price risk associated with future oil and natural gas production. These
contracts have historically consisted of options, in the form of price floors or
collars, and fixed price swaps. In accordance with SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended, derivative financial
instruments are recorded on the balance sheet as either an asset or a liability
measured at fair value. If the derivative does not qualify as a hedge or is not
designated as a hedge, the change in fair value of the derivative is recognized
currently in earnings. If the derivative qualifies for hedge accounting, the
change in fair value of the derivative is recognized either currently in
earnings or deferred in other comprehensive income (equity) depending on the
type of hedge and to what extent the hedge is effective. All of our current
derivative instruments that qualify for hedge accounting are cash flow hedges.
In order to qualify for hedge accounting the relationship between the
hedging instruments and the hedged items must be highly effective in achieving
the offset of changes in fair values or cash flows attributable to the hedged
risk, both at the inception of the hedge and on an ongoing basis. We measure
hedge effectiveness on a quarterly basis. Hedge accounting is discontinued
prospectively when a hedging instrument becomes ineffective. We assess hedge
effectiveness based on total changes in the fair value of options used in cash
flow hedges rather than changes of intrinsic value only. As a result, changes in
the entire fair value of option contracts are deferred in accumulated other
comprehensive income, to the extent they are effective, until the hedged
transaction is completed. If a hedge becomes ineffective, any deferred gains or
losses on the cash flow hedge remain in accumulated other comprehensive income
until the underlying production related to the derivative hedge has been
delivered. If it is determined probable that a hedged forecasted transaction
will not occur, and the hedge is not re-designated, deferred gains or losses on
the hedging instrument are recognized in earnings immediately.
Receipts and payments resulting from settlements of derivative hedging
instruments qualifying for hedge accounting are recorded in "Gain (loss) on
effective hedge contracts" included in revenues in the Consolidated Statements
of Operations. We apply Derivative Implementation Group Issue G20 in accounting
for our net purchased puts and collars, which allows the amortization of the
cost of net purchased options over the period of the hedge. We record this
amortization and any gains or losses resulting from hedge ineffectiveness in
"Gain (loss) on ineffective hedge contracts" under expenses in the Consolidated
Statements of Operations. Denbury's hedging activities are further discussed in
Note 9.
Effective January 1, 2005, we have decided to de-designate from hedge
accounting treatment our existing derivative hedging instruments. As such, we
will account for our derivative instruments in future periods as speculative
contracts and future changes in the fair value of these instruments will be
recognized in the income statement in the period of change. While this change
may result in more volatility in our income in future periods, we believe that
the benefits associated with applying hedge accounting do not outweigh the cost,
time and effort required to apply hedge accounting.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit
Risk
Our financial instruments that are exposed to concentrations of credit risk
consist primarily of cash equivalents, short-term investments, trade and accrued
production receivables and the derivative hedging instruments discussed above.
Our cash equivalents and short-term investments represent high-quality
securities placed with various investment grade institutions. This investment
practice limits our exposure to concentrations of credit risk. Our trade and
accrued production receivables are dispersed among various customers and
purchasers; therefore, concentrations of credit risk are limited. Also, most of
our significant purchasers are large companies with excellent credit ratings. If
customers are considered a credit risk, letters of credit are the primary
57
Denbury Resources Inc.
Notes to Consolidated Financial Statements
security obtained to support lines of credit. We attempt to minimize our credit
risk exposure to the counterparties of our derivative hedging contracts through
formal credit policies, monitoring procedures and diversification. There are no
margin requirements with the counterparties of our derivative contracts.
CO2 Operations
We own and produce CO2 reserves that are used for our own tertiary oil
recovery operations, and in addition, we sell a portion to Genesis and to other
third party industrial users. We record revenue from our sales of CO2 to third
parties when it is produced and sold. CO2 used for our own tertiary oil recovery
operations is not recorded as revenue in the Consolidated Statements of
Operations. Expenses related to the production of CO2 are allocated between
volumes sold to third parties and volumes used for our own use. The expenses
related to third party sales are recorded in "CO2 operating expenses" and the
expenses related to our own uses are recorded in "Lease operating expenses" in
the Consolidated Statements of Operations. We capitalize acquisitions and the
costs of exploring and developing CO2 reserves. The costs capitalized are
depleted or depreciated on the unit-of-production method, based on proved CO2
reserves as determined by independent engineers. We evaluate our CO2 assets for
impairment by comparing our expected future revenues from these assets to their
net carrying value.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they
have maturities of three months or less at the date of purchase.
Short-term Investments
Our short-term investments consist primarily of investment grade debt
securities that are classified as "available-for-sale" in accordance with the
provisions of SFAS No. 115, "Accounting for Certain Investments in Debt and
Equity Securities." Available-for-sale securities are stated at fair value,
based on quoted market prices, with the unrealized gain or loss, net of tax,
reported in other comprehensive income. Premiums and discounts are amortized or
accreted into earnings over the life of the related security. Dividend and
interest income is recognized when earned. We have no investments that are
considered to be trading securities.
The following is a summary of current available-for-sale marketable
securities at December 31, 2004:
(In Thousands) December 31, 2004
- ---------------------------------------------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
-----------------------------------------------------
Certificate of deposits....................... $ 2,000 $ - $ - $ 2,000
Government and agency obligations............. 17,470 - (14) 17,456
Other debt securities......................... 37,739 4 (28) 37,715
------------- ------------ ------------- ------------
Total current available-for-sale securities $ 57,209 $ 4 $ (42) $ 57,171
============= ============ ============= ============
Restricted Cash and Investments
At December 31, 2004 and 2003, we had approximately $6.4 million and $9.5
million, respectively, of restricted cash and investments held in escrow
accounts for future site reclamation costs. These balances are recorded at
amortized cost and are included in "Other Assets" in the Consolidated Balance
Sheets. The estimated fair market value of these investments at December 31,
2004 and 2003 was the same as amortized cost.
58
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income
attributable to common stockholders by the weighted average number of shares of
common stock outstanding during the period. Diluted net income per common share
is calculated in the same manner, but also considers the impact to net income
and common shares for the potential dilution from stock options, restricted
stock and any other outstanding convertible securities.
For each of the three years in the period ended December 31, 2004, there
were no adjustments to net income for purposes of calculating basic and diluted
net income per common share. The following is a reconciliation of the weighted
average shares used in the basic and diluted net income per common share
computations:
(In Thousands) Year Ended December 31,
- ---------------------------------------------------------------------------------------------------
2004 2003 2002
------------ ------------- ------------
Weighted average common shares - basic............. 54,871 53,881 53,243
Potentially dilutive securities:
Stock options.................................. 2,413 1,583 1,122
Restricted stock............................... 17 - -
------------ ------------- ------------
Weighted average common shares - diluted........... 57,301 55,464 54,365
============ ============= ============
The weighted average common shares - basic amount in 2004 excludes
1,150,000 shares of non-vested restricted stock granted in 2004 that is subject
to future time vesting requirements. As these restricted shares vest, they will
be included in the shares outstanding used to calculate basic net income per
common share. For purposes of calculating weighted average common shares -
diluted, the non-vested restricted stock is included in the computation using
the treasury stock method, with the proceeds equal to the average unrecognized
compensation during the period, adjusted for any estimated future tax
consequences recognized directly in equity. The restricted shares were issued in
August through December 2004 and have been included in the calculation for the
periods they were outstanding. These shares may result in greater dilution in
future periods, depending on the market price of our common stock during those
periods. We excluded stock options representing 40,000 shares in 2004, 1.0
million shares in 2003 and 1.7 million shares in 2002 from our diluted shares
outstanding because their inclusion would be antidilutive, as their exercise
prices exceeded the average market price of our common stock during the
respective periods.
Stock-Based Compensation
We issue stock options to all of our employees under our stock option
plans, which are described more fully in Note 8. We account for our stock
options utilizing the recognition and measurement principles of Accounting
Principles Board Opinion 25 (APB 25), "Accounting for Stock Issued to
Employees," and its related interpretations. Under these principles, no
stock-based employee compensation expense is reflected in net income as long as
the stock options have an exercise price equal to the underlying common stock on
the date of grant. The following table illustrates the effect on net income and
net income per common share if we had applied the fair value provisions of SFAS
No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148,
in accounting for our stock options.
59
Denbury Resources Inc.
Notes to Consolidated Financial Statements
(In Thousands, Except Per Share Data) Year Ended December 31,
- --------------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------- ------------ -------------
Net income:
Net income, as reported............................................ $ 82,448 $ 56,553 $ 46,795
Add: Stock-based compensation included in reported net income, net of
related tax effects.............................................. 977 - -
Less: Stock-based compensation expense applying fair value
based method, net of related tax effects......................... 3,772 3,101 2,853
------------- ------------ -------------
Pro forma net income............................................... $ 79,653 $ 53,452 $ 43,942
============= ============ =============
Net income per common share
As reported:
Basic............................................................ $ 1.50 $ 1.05 $ 0.88
Diluted.......................................................... 1.44 1.02 0.86
Pro forma:
Basic............................................................ $ 1.45 $ 0.99 $ 0.83
Diluted.......................................................... 1.40 0.98 0.83
The weighted average fair value of options granted using the Black-Scholes
option pricing model and the weighted average assumptions used in determining
those fair values are as follows:
2004 2003 2002
------------- ------------ ------------
Weighted average fair value of options granted... $ 6.44 $ 6.02 $ 4.17
Risk free interest rate.......................... 3.34% 2.94% 4.05%
Expected life.................................... 5 years 5 years 5 years
Expected volatility.............................. 46.8% 59.6% 61.4%
Dividend yield................................... - - -
Income Taxes
Income taxes are accounted for using the liability method under which
deferred income taxes are recognized for the future tax effects of temporary
differences between the financial statement carrying amounts and the tax basis
of existing assets and liabilities using the enacted statutory tax rates in
effect at year-end. The effect on deferred taxes for a change in tax rates is
recognized in income in the period that includes the enactment date. A valuation
allowance for deferred tax assets is recorded when it is more likely than not
that the benefit from the deferred tax asset will not be realized.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make estimates and assumptions that affect the reported amount of
certain assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during each reporting period. Management believes its
estimates and assumptions are reasonable; however, such estimates and
assumptions are subject to a number of risks and uncertainties that may cause
actual results to differ materially from such estimates. Significant estimates
underlying these financial statements include (i) the fair value of financial
derivative instruments, (ii) the estimated quantities of proved oil and natural
gas reserves used to compute depletion of oil and natural gas properties, the
related present value of estimated future net cash flows therefrom and ceiling
test, (iii) accruals related to oil and gas production and revenues, capital
expenditures
60
Denbury Resources Inc.
Notes to Consolidated Financial Statements
and lease operating expenses, (iv) the estimated costs and timing of future
asset retirement obligations, and (v) estimates made in the calculation of
income taxes. While management is not aware of any significant revisions to any
of its estimates, there will likely be future revisions to its estimates
resulting from matters such as changes in ownership interests, payouts, joint
venture audits, re-allocations by purchasers or pipelines, or other corrections
and adjustments common in the oil and gas industry, many of which require
retroactive application. These types of adjustments cannot be currently
estimated and will be recorded in the period during which the adjustment occurs.
Reclassifications
Certain prior period amounts have been reclassified to conform with the
current year presentation. Such reclassifications had no impact on our reported
net income, current assets, total assets, current liabilities, total liabilities
or stockholders' equity.
Recent Accounting Pronouncements
On December 16, 2004, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R)
supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally,
the approach in SFAS No. 123(R) is similar to the approach described in SFAS No.
123. However, SFAS No. 123(R) will require all share-based payments to
employees, including grants of employee stock options, to be recognized in our
Consolidated Statements of Operations based on their estimated fair values. Pro
forma disclosure is no longer an alternative.
SFAS No. 123(R) must be adopted no later that July 1, 2005 and permits
public companies to adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is
recognized based on the requirements of SFAS No. 123(R) for all
share-based payments granted prior to the effective date of SFAS No.
123(R) that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of
the modified prospective method described above, but also permits
entities to restate either all prior periods presented or prior
interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
As permitted by SFAS No. 123, we currently account for share-based payments
to employees using the intrinsic value method prescribed by APB 25 and related
interpretations. As such, we generally do not recognize compensation expense
associated with employee stock options. Accordingly, the adoption of SFAS No.
123(R)'s fair value method could have a significant impact on Denbury's future
results of operations, although it will have no impact on our overall financial
position. Had the Company adopted SFAS No 123(R) in prior periods, the impact
would have approximated the impact of SFAS No. 123 as described in the pro forma
net income and earnings per share disclosures above. The adoption of SFAS No.
123(R) will have no effect on the Company's unvested outstanding restricted
stock awards. We currently plan to adopt the provisions of SFAS No. 123(R).
Although we have not completed evaluating the impact the adoption of SFAS No.
123(R) will have on our future results of operations, we currently estimate the
impact on an annual basis will be similar to our pro forma disclosures for SFAS
No. 123 above.
SFAS No. 123(R) also requires the tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce the Denbury's future cash provided by operating activities and
increase future cash provided by financing activities, to the extent of
associated tax benefits that may be realized in the future. While we cannot
estimate what those amounts will be in the future (because they depend, among
other things, when employees exercise stock options), the amount of operating
cash flows recognized in prior periods for such excess tax deductions were $4.8
million, $1.3 million and $0.7 million during the years ended December 31, 2004,
2003, and 2002, respectively.
In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB
106), which clarifies the calculation of the full cost ceiling and depreciation,
depletion, and amortization ("DD&A") of oil and gas properties in conjunction
with accounting for asset retirement obligations under SFAS No. 143. The
guidance in SAB 106 had no impact on our consolidated financial statements.
61
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 2. ACQUISITIONS AND DIVESTITURES
Sale of Denbury Offshore, Inc.
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. We excluded from the sale a discovery well
drilled at High Island A-6 during 2004, and certain deep rights at West Delta 27
that we sold for $1.8 million in December 2004, but retained a carried interest
in a deep exploratory well.
Our financial results for 2004 include production, revenues, operating
expenses, and capital expenditures of the offshore properties through July 19,
2004. Revenues of Denbury Offshore, Inc. included in our 2004 results were $62.6
million. We recorded the proceeds from the sale as a reduction to our full cost
pool. We paid approximately $21 million of current income taxes relating to the
sale and paid approximately $2.4 million of employee severance costs in 2004. We
used $85 million of the sales proceeds to retire our bank debt.
Our offshore properties made up approximately 12.5% of our year-end 2003
proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented
approximately 25% of our 2004 second quarter production (9,114 BOE/d).
COHO Gulf Coast Properties
In August 2002, we acquired the Gulf Coast properties of COHO Energy, Inc.,
auctioned in the U.S. Bankruptcy Court in Dallas, Texas. Our net purchase price
was $48.2 million and included nine fields, eight of which are located in
Mississippi and one in Texas. At December 31, 2002, these properties had
reserves of approximately 15.1 million barrels of oil and net production of
approximately 4,000 barrels of oil per day. The Mississippi fields included
interests in the Brookhaven, Laurel, Martinville, Soso and Summerland Fields,
with such interests representing operational control with working interests in
excess of 90%, plus interests in the smaller Bentonia, Cranfield and Glazier
Fields.
In February 2003, we sold Laurel Field, acquired in the COHO acquisition,
for $25.9 million and other consideration which included an interest in
Atchafalaya Bay Field (where we already owned an interest) and seismic over that
area. At December 31, 2002, Laurel Field had approximately 7.4 MMBbls of proved
reserves. In March 2003, we sold the Bentonia and Glazier fields for
approximately $1.6 million. The proceeds from the sale of Laurel Field were used
to reduce our bank debt.
62
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 3. RELATED PARTY TRANSACTIONS - GENESIS
On May 14, 2002, a newly formed subsidiary of Denbury acquired Genesis
Energy, L.L.C. (which was susequently converted to Genesis Energy, Inc.), the
general partner of Genesis, a publicly traded master limited partnership, for
total consideration, including expenses and commissions, of approximately $2.2
million. Genesis has two primary lines of business: crude oil gathering and
marketing and pipeline transportation, primarily in Mississippi, Texas, Alabama
and Florida. In November 2003, through our subsidiary general partner, we
purchased an additional 689,000 partnership common units and 14,000 general
partner units of Genesis for $7.15 per unit, with an aggregate purchase price of
approximately $5.0 million. With these additional units, our ownership interest
increased to approximately 9.25% (2.0% general partner ownership and 7.25%
limited partner ownership).
We are accounting for our 9.25% ownership in Genesis under the equity
method of accounting as we have significant influence over the limited
partnership; however, our control is limited under the limited partnership
agreement and therefore, we do not consolidate Genesis. Our equity in Genesis'
net income (loss) for 2004 was ($136,000), for 2003 was $256,000 and for 2002
was $55,000, representing 2% of Genesis' net income (loss) for the periods from
May 14, 2002 through October 31, 2003 and 9.25% of Genesis' net income (loss)
for the periods from November 1, 2003 through December 31, 2004. Genesis Energy,
Inc., the general partner of which we own 100%, has guaranteed the bank debt of
Genesis, which consisted of $15.3 million of debt and $22.8 million in letters
of credit at December 31, 2004. There are no guarantees by Denbury or any of its
other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. Our
investment in Genesis of $7.2 million exceeded our percentage of net equity in
the limited partnership at the time of acquisition by approximately $2.2
million, which represents goodwill and is not subject to amortization. The fair
value of our investment in Genesis was $11.1 million at December 31, 2004, based
on quoted market values.
Over the past several years, including the period prior to our investment
in Genesis, we sold certain of our oil production to Genesis. Beginning in
September 2004, we elected to sell our own crude oil to independent third
parties rather than to Genesis. As such, we discontinued our direct sales to
Genesis and began to transport our crude oil to our sales point using Genesis'
common carrier pipeline. For these transportation services, we pay Genesis a fee
for the use of their pipeline and trucking services. For 2004, we expensed $1.2
million for these transportation services. At December 31, 2004, we had a
receivable from Genesis of $0.7 million and $6.9 million at December 31, 2003.
We recorded oil sales to Genesis of $63.5 million, $48.9 million and $22.9
million for the years ended December 31, 2004, 2003, and 2002, respectively.
Denbury received other miscellaneous payments from Genesis, including $120,000
in both 2004 and 2003 in director fees for certain executive officers of Denbury
that are board members of Genesis, and $508,000 in 2004 and $57,000 in 2003 of
pro rata dividend distributions from Genesis.
Transportation Leases
During 2004, we requested that Genesis build two pipelines for our benefit.
The pipelines were to transport our crude oil from Olive and McComb Fields in
Southwest Mississippi to Genesis' main crude oil pipeline to improve our ability
to market our crude oil, and to transport CO2 from our main CO2 pipeline to
Brookhaven Field for our tertiary operations. As part of these arrangements, we
entered into two transportation agreements. The first agreement, entered into in
November, was to transport crude oil from Olive Field. This agreement is for 10
years and has a minimum payment of approximately $18,000 per month. This minimum
monthly charge will increase for any volumes transported in excess of a stated
monthly volume. In December, we entered into the second transportation agreement
to transport CO2 to Brookhaven Field in Southwest Mississippi. This agreement is
for an eight-year period and has minimum payments of approximately $49,000 per
month. This minimum monthly payment will increase for any volumes transported in
excess of a stated monthly volume. Genesis will operate and maintain these
pipelines at its own expense.
We have accounted for these agreements as capital leases. The pipelines
held under these capital leases are classified as property and equipment and are
amortized using the straight-line method over the lease terms. Lease
amortization is included in depreciation expense. The related obligations are
recorded as debt. At December 31, 2004, we had $4.6 million recorded as debt, of
which $375,000 was current.
63
Denbury Resources Inc.
Notes to Consolidated Financial Statements
CO2 Volumetric Production Payment
In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million
($23.9 million as adjusted for interim cash flows from the September 1, 2003
effective date and for transaction costs) under a volumetric production payment
("VPP"), and assigned to Genesis three of our existing long-term commercial CO2
supply agreements with our industrial customers. These industrial contracts
represented approximately 60% of our then current industrial CO2 sales volumes.
Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO2 through 2009,
43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term.
On August 26, 2004, we closed on another transaction with Genesis, selling
to them a 33.0 Bcf volumetric production payment ("VPPII") of CO2 for $4.8
million ($4.6 million as adjusted for interim cash flows from the July 1
effective date and for transaction costs) along with a related long-term supply
agreement with an industrial customer. Pursuant to the VPPII, Genesis may take
up to 9 MMcf/d of CO2 to the end of the contract term.
We have recorded the net proceeds of these volumetric production payment
sales as deferred revenue and will recognize such revenue as CO2 is delivered
during the term of the two volumetric production payments. At December 31, 2004
and 2003, $25.8 million and $23.6 million, respectively, was recorded as
deferred revenue of which $2.4 million and $2.1 million was included in current
liabilities at December 31, 2004 and 2003, respectively. During 2004 and 2003,
we recognized deferred revenue of $2.4 million and $0.3 million, respectively,
for deliveries under the VPP and VPPII. 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, which resulted in $2.7 million and $0.4 million in revenue to Denbury
for the years ended December 31, 2004 and 2003, respectively.
Summarized financial information of Genesis Energy, L.P.
(In Thousands) Year Ended December 31,
- ---------------------------------------------------------------------------------
2004 2003
------------------- -----------------
Revenues................................. $ 927,143 $ 657,897
Cost of sales............................ 908,804 644,157
Other expenses........................... 19,288 14,159
Income (loss) from discontinued operations (463) 13,741
------------------- -----------------
Net income (loss)...................... $ (1,412) $ 13,322
=================== =================
December 31, December 31,
2004 2003
------------------- -----------------
Current assets........................... $ 77,396 $ 88,211
Non-current assets....................... 65,758 58,904
------------------- -----------------
Total assets........................... $ 143,154 $ 147,115
=================== =================
Current liabilities...................... $ 81,938 $ 87,244
Non-current liabilities.................. 15,460 7,000
Partners' capital........................ 45,756 52,871
------------------- -----------------
Total liabilities and partners' capital $ 143,154 $ 147,115
=================== =================
NOTE 4. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting
for Asset Retirement Obligations." In general, our future asset retirement
obligations relate to future costs associated with plugging and abandonment of
our oil and natural gas wells, removal of equipment and facilities from leased
64
Denbury Resources Inc.
Notes to Consolidated Financial Statements
acreage and returning such land to its original condition. SFAS 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred, discounted to its present value
using our credit adjusted risk-free interest rate, and a corresponding amount
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted each period, and the capitalized cost is depreciated
over the useful life of the related asset. Prior to the adoption of this new
standard, we recognized a provision for our asset retirement obligations each
period as part of our depletion and depreciation calculation, based on the
unit-of-production method.
The adoption of SFAS No. 143 on January 1, 2003, required us to record (i)
a $41.0 million liability for our future asset retirement obligations (an
increase of $34.1 million in our liability for asset retirement obligations that
we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and
natural gas properties, (iii) a $3.9 million decrease in accumulated
depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect
adjustment of a change in accounting principle, net of taxes.
The following pro forma data summarizes Denbury's net income and net income
per common share as if we had applied the provisions of SFAS No. 143 in prior
periods, and as if we had removed the first quarter 2003 cumulative effect
adjustment for the adoption of SFAS No. 143:
(In Thousands, except per share data) Year Ended December 31,
- ---------------------------------------------------------------------------------------------------
2003 2002
------------ ---------------
Net income, as reported.......................................... $ 56,553 $ 46,795
Pro forma adjustments to reflect retroactive adoption
of SFAS 143.................................................... (2,612) 473
------------ ---------------
Pro forma net income ............................................ $ 53,941 $ 47,268
============ ===============
Net income per common share:
As reported:
Basic.......................................................... $ 1.05 $ 0.88
Diluted........................................................ 1.02 0.86
Pro forma:
Basic.......................................................... $ 1.00 $ 0.89
Diluted........................................................ 0.97 0.87
The following table summarizes the changes in our asset retirement
obligations for the years ended December 31, 2004 and 2003.
(In Thousands) Year Ended December 31,
- -------------------------------------------------------------------------------------------------------------
2004 2003
----------------- ---------------
Beginning asset retirement obligation............................... $ 43,812 $ 6,845
Cumulative effect adjustment for SFAS No. 143, January 1, 2003.... - 34,110
Liabilities incurred during period................................ 3,206 3,405
Liabilities settled during period................................. (2,549) (1,007)
Liabilities sold during period.................................... (25,337) (2,393)
Accretion expense................................................. 2,408 2,852
----------------- ----------------
Ending asset retirement obligation.................................. $ 21,540 $ 43,812
================= ================
Liabilities sold during the period primarily represent the asset retirement
obligations previously associated with our offshore assets held by Denbury
Offshore, Inc., which we sold in July 2004. At December 31, 2004 and 2003, $2.6
million and $2.1 million of our asset retirement obligation was classified in
"Accounts payable and accrued liabilities" under current liabilities in our
Consolidated Balance Sheets. We have escrow accounts that are legally restricted
for certain of our asset retirement obligations. The balances of these escrow
accounts were $6.4 million at December 31, 2004, and $9.5 million at December
31, 2003, and are included in "Other Assets" in our Consolidated Balance Sheets.
65
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 5. PROPERTY AND EQUIPMENT
(In Thousands) December 31,
- ------------------------------------------------------------------------------
2004 2003
-------------- --------------
Oil and natural gas properties:
Proved properties........................ $ 1,326,401 $ 1,409,579
Unevaluated properties................... 20,253 46,065
-------------- --------------
Total.................................. 1,346,654 1,455,644
Accumulated depletion and depreciation..... (686,799) (690,395)
-------------- --------------
Net oil and natural gas properties....... 659,855 765,249
-------------- --------------
CO2 properties............................. 132,685 85,467
Accumulated depletion and depreciation..... (10,636) (5,971)
-------------- --------------
Net CO2 properties....................... 122,049 79,496
-------------- --------------
Other ..................................... 25,929 16,450
Accumulated depletion and depreciation..... (10,471) (8,684)
-------------- --------------
Net other................................ 15,458 7,766
-------------- --------------
Net property, equipment and other........ $ 797,362 $ 852,511
============== ==============
Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, we may exclude certain unevaluated costs from
the amortization base pending determination of whether proved reserves can be
assigned to such properties. A summary of the unevaluated properties excluded
from oil and natural gas properties being amortized at December 31, 2004 and
2003 and the year in which they were incurred follows:
(In Thousands) December 31, 2004 December 31, 2003
- ------------------------------------------------------------------------------------- --------------------------------------------
Costs Incurred During: Costs Incurred During:
-------------------------------------------- ---------------------------------
2004 2003 2002 2001 Total 2003 2002 2001 Total
------------------------------------------------------ --------------------------------------------
Property acquisition costs.. $ 3,400 $ 2,519 $ 1,207 $ 1,798 $ 8,924 $ 3,640 $ 6,301 $ 21,169 $ 31,110
Exploration costs........... 3,787 2,771 3,550 1,221 11,329 6,528 5,291 3,136 14,955
------------------------------------------------------ --------------------------------------------
Total....................... $ 7,187 $ 5,290 $ 4,757 $ 3,019 $ 20,253 $ 10,168 $ 11,592 $ 24,305 $ 46,065
====================================================== ============================================
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
We review the excluded properties for impairment at least annually. We currently
estimate that evaluation of most of these properties and the inclusion of their
costs in the amortization base is expected to be completed within five years.
Until we are able to determine whether there are any proved reserves
attributable to the above costs, we are not able to assess the future impact on
the amortization rate.
66
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 6. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
(In Thousands) December 31,
- -------------------------------------------------------------------------------
2004 2003
------------- ------------
7.5% Senior Subordinated Notes due 2013............ $ 225,000 $ 225,000
Discount on Senior Subordinated Notes.............. (1,603) (1,797)
Capital lease obligations - Genesis................ 4,559 -
Senior bank loan................................... - 75,000
------------- ------------
Total............................................ 227,956 298,203
Less current obligations........................... 375 -
------------- ------------
Long-term debt and capital lease obligations.... $ 227,581 $ 298,203
============= ============
Senior Bank Loan
On September 1, 2004, we entered into a new bank credit agreement which
modified the prior agreement by (i) creating a structure wherein the commitment
amount and borrowing base amount are no longer the same, (ii) improving our
credit pricing by reducing the interest rate chargeable at certain levels of
borrowing, (iii) extending the term by three years to April 30, 2009, (iv)
reducing the collateral requirements, (v) authorizing up to $20 million of
possible future CO2 volumetric production payment transactions with Genesis
Energy, and (vi) other minor modifications and corrections. Under the new
agreement, our borrowing base is currently set at $200 million, with an initial
commitment amount of $100 million. The borrowing base represents the amount we
can borrow from a credit standpoint based on our assets, as confirmed by the
banks, while the commitment amount is the amount we asked the banks to commit to
fund pursuant to the terms of the credit agreement. The banks have the option to
participate in any borrowing request made by us in excess of the commitment
amount, up to the borrowing base limit, although they are not obligated to fund
any amount in excess of $100 million, the commitment amount. The advantage to us
is that we will pay commitment fees on the commitment amount, not the borrowing
base, thus lowering our overall cost of available credit.
The bank credit facility is secured by substantially all of our producing
oil and natural gas properties and contains several restrictions including,
among others: (i) a prohibition on the payment of dividends, (ii) a requirement
for a minimum equity balance, (iii) a requirement to maintain positive working
capital, as defined, (iv) a minimum interest coverage test and (v) a prohibition
of most debt and corporate guarantees. We were in compliance with all of our
bank covenants as of December 31, 2004. Our bank credit facility provides for a
semi-annual re-determination of the borrowing base on April 1 and October 1.
Borrowings under the credit facility are generally in tranches that can have
maturities up to one year. Interest on any borrowings are based on the Prime
Rate or LIBOR rate plus an applicable margin as determined by the borrowings
outstanding. The facility matures in April 2009.
As of December 31, 2004, we had no outstanding borrowings under the
facility and $460,000 in letters of credit secured by the facility. The next
scheduled re-determination of the borrowing base will be as of April 1, 2005,
based on December 31, 2004 assets and proved reserves.
Subordinated Debt Issuance of 7.5% Senior Subordinated Notes due 2013
On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes
due 2013. The notes were priced at 99.135% of par and we used most of our $218.4
million of net proceeds from the offering, after underwriting and issuance
costs, to retire our existing $200 million of 9% Senior Subordinated Notes due
2008, including the Series B notes (see "Redemption of 9% Senior Subordinated
Notes due 2008 (Including Series B Notes)" below).
67
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The notes mature on April 1, 2013 and interest on the notes is payable each
April 1 and October 1. We may redeem the notes at our option beginning April 1,
2008 at the following redemption prices: 103.75% after April 1, 2008, 102.5%
after April 1, 2009, 101.25% after April 1, 2010, and 100% after April 1, 2011
and thereafter. In addition, prior to April 1, 2006, we may redeem up to 35% of
the notes at a redemption price of 107.5% with net cash proceeds from a stock
offering. The indenture under which the notes were issued is essentially the
same as the indenture covering our previously outstanding 9% notes. The
indenture contains certain restrictions on our ability to incur additional debt,
pay dividends on our common stock, make investments, create liens on our assets,
engage in transactions with our affiliates, transfer or sell assets, consolidate
or merge, or sell substantially all of our assets. The notes are not subject to
any sinking fund requirements. All of our significant subsidiaries fully and
unconditionally guarantee this debt.
In connection with our internal reorganization to a
holding-company-organizational structure (see Note 1), we entered into a First
Supplemental Indenture dated December 29, 2003, which did not require the
consent of the holders of the 7.5% Senior Subordinated Notes due 2013. The
supplemental indenture made Denbury Resources Inc. and Denbury Onshore, LLC,
co-obligors of this debt. All of our significant subsidiaries continue to fully
and unconditionally guarantee this debt. There were no other significant changes
as part of the amendment.
Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes)
On April 16, 2003, we redeemed our $200 million of 9% Senior Subordinated
Notes due 2008 at an aggregate cost of $209.0 million, including a $9.0 million
call premium. As a result of this early redemption, we recorded a before-tax
charge to earnings in the second quarter of 2003 of $17.6 million ($11.5 million
after income tax), which included the $9.0 million call premium and the
write-off of the remaining discount and debt issuance costs associated with
these notes.
Indebtedness Repayment Schedule
As of December 31, 2004, our indebtedness, excluding the discount on our
senior subordinated debt, is repayable over the next five years and thereafter
as follows:
(In Thousands)
- -----------------------------------------------
2005............................. $ 375
2006............................. 412
2007............................. 451
2008............................. 496
2009............................. 545
Thereafter....................... 227,280
------------
Total indebtedness............. $ 229,559
============
68
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 7. INCOME TAXES
Our income tax provision (benefit) is as follows:
(In Thousands) Year Ended December 31,
- ------------------------------------------------------------------------------------------
2004 2003 2002
------------ ------------ ------------
Current income tax expense (benefit):
Federal....................................... $ 22,166 $ (91) $ (419)
State......................................... 763 - 13
------------ ------------ ------------
Total current income tax expense (benefit).... 22,929 (91) (406)
------------ ------------ ------------
Deferred income tax expense:
Federal....................................... 12,352 23,864 21,822
State......................................... 4,111 2,439 2,104
------------ ------------ ------------
Total deferred income tax expense........... 16,463 26,303 23,926
------------ ------------ ------------
Total income tax expense.................. $ 39,392 $ 26,212 $ 23,520
============ ============ ============
In conjunction with the sale of Denbury Offshore, Inc. in 2004, we utilized
all of our federal tax net operating loss carryforwards and paid alternative
minimum taxes of approximately $21 million. Our current income tax benefit in
2002 is primarily related to tax law changes in 2002 that allowed us to receive
a refund of our alternative minimum taxes paid for 2001. At December 31, 2004,
we have approximately $132.3 million in state net operating loss carryforwards
that begin to expire in 2013. In 2001, we began to recognize a benefit for the
amount of enhanced oil recovery credits earned from our tertiary recovery
projects. The total credits earned to date are approximately $27.8 million.
These credits begin to expire in 2020.
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 2004 and 2003 balance sheet dates.
We believe that we will be able to utilize all of our deferred tax assets at
December 31, 2004, and therefore have provided no valuation allowance against
our deferred tax assets. At December 31, 2004 and 2003, our deferred tax assets
and liabilities were as follows:
(In Thousands) December 31,
- ----------------------------------------------------------------------------
2004 2003
--------------------------
Deferred tax assets:
Loss carryforwards - federal................ $ - $ 33,234
Loss carryforwards - state................... 5,290 2,764
Tax credit carryover......................... 14,186 978
Enhanced oil recovery credit carryforwards... 27,828 16,578
Derivative hedging contracts................. 2,920 16,617
Other........................................ 318 90
------------ ------------
Total deferred tax assets.................. 50,542 70,261
------------ ------------
Deferred tax liabilities:
Property and equipment....................... (120,038) (112,200)
Asset retirement obligations................. (2,440) (1,600)
------------ ------------
Total deferred tax liabilities............ (122,478) (113,800)
------------ ------------
Total net deferred tax liability........ $ (71,936) $ (43,539)
============ ============
69
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Our income tax provision varies from the amount that would result from
applying the federal statutory income tax rate to income before income taxes as
follows:
(In Thousands) Year Ended December 31,
- --------------------------------------------------------------------------------------
2004 2003 2002
------------ ------------ ------------
Income tax provision calculated using the
federal statutory income tax rate......... $ 42,644 $ 28,054 $ 24,587
State income taxes.......................... 4,874 2,398 2,121
Enhanced oil recovery credits............... (7,986) (4,687) (3,394)
Other....................................... (140) 447 206
------------ ------------ ------------
Total income tax expense.................. $ 39,392 $ 26,212 $ 23,520
============ ============ ============
NOTE 8. STOCKHOLDERS' EQUITY
Authorized
We are authorized to issue 100 million shares of common stock, par value
$.001 per share, and 25 million shares of preferred stock, par value $.001 per
share. The preferred shares may be issued in one or more series with rights and
conditions determined by the board of directors.
Stock Repurchase Plan
Since August 2003, Denbury has had an active stock repurchase plan ("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 (see Employee Stock Purchase Plan below). The Plan provides
for purchases through an independent broker of 50,000 shares of Denbury's common
stock per fiscal quarter over a period of approximately twelve months, or a
total of 200,000 shares per year. 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.
During 2003, we purchased 100,000 shares at an average cost of $12.77 per share
and reissued 91,838 of those shares under Denbury's Employee Stock Purchase
Plan. In 2004, we repurchased into treasury 200,000 shares at an average cost of
$19.89 per share and reissued 115,090 treasury shares under the Employee Stock
Purchase Plan. Our current repurchase program extends through June 2005.
Stock Option Plans
Denbury has two stock option plans in effect at December 31, 2004. The
first plan has been in existence since 1995 (the "1995 Plan") and will expire in
August 2005. The second plan, the 2004 Omnibus Stock and Incentive Plan (the
"2004 Plan"), has a ten year term and was approved by the shareholders in May
2004. At December 31, 2004, we had a total of 8,195,587 shares of common stock
authorized for issuance pursuant to the 1995 Plan, of which 710,291 shares were
available for issuance, and 1,125,000 shares authorized for issuance pursuant to
the 2004 Plan, of which all 1,125,000 were available for issuance. In January
2005, we issued options under the 1995 Plan that utilized substantially all of
the remaining shares under the 1995 Plan and that same month began issuing
options under the 2004 Plan. We do not anticipate issuing any further options
pursuant to the 1995 Plan and all future grants will be made pursuant to the
2004 Plan. Under the terms of these plans, incentive and non-qualified options
may be issued to officers, employees, directors and consultants. Options
generally become exercisable over a four-year vesting period with the specific
terms of vesting determined by the board of directors at the time of grant. The
options expire over terms not to exceed ten years from the date of grant, 90
days after termination of employment or permanent disability or one year after
the death of the optionee. The options are granted at the fair market value at
the time of grant, which is generally defined in the 1995 Plan as the average
closing price of our common stock for the ten trading days prior to issuance, or
in the case of the 2004 Plan, the closing price on the date of grant. These
plans are administered by the Compensation Committee of Denbury's Board of
Directors.
70
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following is a summary of our stock option activity:
Year Ended December 31,
--------------------------------------------------------------------------------------------
2004 2003 2002
------------------------------ ------------------------------ ------------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Options Price of Options Price of Options Price
--------------- -------------- --------------- -------------- --------------- --------------
Outstanding at beginning of year... 5,326,216 $ 9.20 4,996,365 $ 8.46 4,615,223 $ 8.40
Granted............................ 1,009,810 14.35 957,608 11.33 921,341 7.50
Exercised.......................... (1,264,284) 8.49 (550,090) 5.77 (370,120) 4.51
Forfeited.......................... (631,585) 9.77 (77,667) 12.25 (170,079) 10.30
--------------- --------------- ---------------
Outstanding at end of year......... 4,440,157 10.49 5,326,216 9.20 4,996,365 8.46
=============== =============== ===============
Exercisable at end of year......... 1,544,412 $ 9.61 2,263,264 $ 10.11 2,267,230 $ 10.26
=============== ============== =============== ============== =============== ==============
The following is a summary of stock options outstanding at December 31,
2004:
Options Outstanding Options Exercisable
------------------------------------------------------ --------------------------------
Weighted
Number Average Weighted Number Weighted
of Options Remaining Average of Options Average
Outstanding Contractual Exercise Exercisable Exercise
at 12/31/04 Life Price at 12/31/04 Price
------------------- ------------------- -------------- ----------------- --------------
Range of Exercise Prices
- -----------------------------------
$3.77 - 5.50....................... 689,338 4.4 years $ 4.14 689,338 $ 4.14
$5.51 - 8.00....................... 728,514 6.6 years 7.10 81,842 7.13
$8.01 - 11.50...................... 1,459,336 7.1 years 10.37 134,839 9.69
$11.51 - 14.50..................... 1,159,516 7.1 years 13.56 332,448 13.37
$14.51 - 22.50..................... 361,443 4.0 years 18.33 305,945 18.48
$22.51 - 29.50..................... 42,010 9.8 years 25.05 - -
------------------- -----------------
4,440,157 6.4 years 10.49 1,544,412 9.61
=================== =================
Restricted Stock
During August through December 2004, the Board of Directors, based on a
recommendation by the Board's Compensation Committee, awarded the officers of
Denbury a total of 1,100,000 shares of restricted stock and the independent
directors of Denbury a total of 50,000 shares of restricted stock, all granted
under Denbury's 2004 Omnibus Stock and Incentive Plan that was approved by
Denbury's shareholders in May 2004. The holders of these shares have all of the
rights and privileges of owning the shares (including voting rights) except that
the holders are not entitled to delivery of the certificates until certain
requirements are met. With respect to the 1,100,000 shares of restricted stock
granted to officers of Denbury, the vesting restrictions on those shares are as
follows: i) 65% of the awards vest 20% per year over five years and, ii) 35% of
the awards vest upon retirement, as defined in the 2004 Plan. With respect to
the 65% of the awards that vest over five years, on each annual vesting date,
66-2/3% of the vested shares may be delivered to the holder with the remaining
33-1/3% retained and held in escrow until the holder's separation from the
Company. With respect to the 50,000 restricted shares issued to Denbury's
independent board members, the shares vest 20% per year over five years. For
these shares, on each annual vesting date, 40% of such vested shares may be
delivered to the holder with the remaining 60% retained and held in escrow until
71
Denbury Resources Inc.
Notes to Consolidated Financial Statements
the holder's separation from the Company. All restricted shares vest upon death,
disability or a change in control.
Upon issuance of the 1,150,000 shares of restricted stock pursuant to the
2004 Omnibus Stock and Incentive Plan, we recorded deferred compensation expense
of $23.3 million, the market value of the shares on the grant dates, as a
reduction to shareholders' equity. This expense will be amortized over the
applicable five year or retirement date vesting periods. The compensation
expense recorded with respect to the restricted shares for the year ending
December 31, 2004, was $1.6 million.
Employee Stock Purchase Plan
We have a Stock Purchase Plan that is authorized to issue up to 1,750,000
shares of common stock to all full-time employees. As of December 31, 2004,
there are 291,376 authorized shares remaining to be issued under the plan. In
accordance with the plan, employees may contribute up to 10% of their base
salary and Denbury matches 75% of their contribution. The combined funds are
used to purchase previously unissued Denbury common stock or treasury stock
purchased by the Company in the open market for that purpose, in either case,
based on the market value of Denbury's common stock at the end of each quarter.
We recognize compensation expense for the 75% company match portion, which
totaled $1,011,000, $997,000 and $822,000 for the years ended December 31, 2004,
2003 and 2002, respectively. This plan is administered by the Compensation
Committee of Denbury's Board of Directors. This plan currently terminates in
August 2005, although we plan to request that shareholders extend this plan for
another five years at the 2005 Annual Meeting of Shareholders.
401(k) Plan
Denbury offers a 401(k) Plan to which employees may contribute tax deferred
earnings subject to Internal Revenue Service limitations. Up to 3% of an
employee's compensation, as defined by the plan, is matched by Denbury at 100%
and an employee's contribution between 3% and 6% of compensation is matched by
Denbury at 50%. Denbury's match is vested immediately. During 2004, 2003 and
2002, Denbury's matching contributions were approximately $1.0 million, $1.1
million, and $884,000, respectively, to the 401(k) Plan.
NOTE 9. DERIVATIVE HEDGING CONTRACTS
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. Historically, we have generally attempted to hedge
between 50% and 75% of our anticipated production each year to provide us with a
reasonably certain amount of cash flow to cover a majority of our budgeted
exploration and development expenditures without incurring significant debt,
although our hedging percentage may vary relative to our debt levels. When we
make a significant acquisition, we generally attempt to hedge a large
percentage, up to 100%, of the forecasted production for the subsequent one to
three years following the acquisition in order to help provide us with a minimum
return on our investment. Our recent hedging activity has been predominantly
with collars, although for the 2002 COHO acquisition, we also used swaps in
order to lock in the prices used in our economic forecasts. All of the
mark-to-market valuations used for our financial derivatives are provided by
external sources and are based on prices that are actively quoted. We manage and
control market and counterparty credit risk through established internal control
procedures, which are reviewed on an ongoing basis. We attempt to minimize
credit risk exposure to counterparties through formal credit policies,
monitoring procedures, and diversification.
72
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following is a summary of the net gain (loss) on our commodity
contracts that qualify for hedge accounting which are included in "(Gain) loss
on effective hedge contracts" in our Consolidated Statements of Operations:
(In Thousands) Year Ended December 31,
- ----------------------------------------------------------------------------------------------------
2004 2003 2002
------------ ------------ ------------
Settlement of hedge contracts - Oil...................... $ (50,072) $ (20,337) $ (598)
Settlement of hedge contracts - Gas...................... (20,397) (41,873) 1,530
------------ ------------ ------------
Gain (loss) on effective hedge contracts............... $ (70,469) $ (62,210) $ 932
============ ============ ============
The following is a summary of "(Gain) loss on ineffective hedge contracts,"
included in our Consolidated Statements of Operations:
(In Thousands) Year Ended December 31
- ----------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------- ------------ -------------
Settlement of contract not qualifying for hedge accounting.......... $ 14,088 $ - $ -
Hedge ineffectiveness on contracts qualifying for hedge
accounting........................................................ 2,687 282 600
Reclassification of accumulated other comprehensive income
balance and adjustments to fair value associated with termination
of contracts designated to offshore production.................... (955) - -
Adjustments to fair value and amortization of ineffective hedge no
longer qualifying for hedge accounting ........................... 2,086 - -
Adjustment to fair value associated with contracts transferred in
sale of offshore properties....................................... (2,548) -
Amortization of contract premiums................................... - 1,192 9,664
Amortization of terminated Enron-related hedges over the original
contract periods.................................................. - (5,052) (13,357)
------------- ------------ -------------
(Gain) loss on ineffective contracts.............................. $ 15,358 $ (3,578) $ (3,093)
============= ============ =============
Loss on Enron Hedges
In conjunction with the acquisition of Matrix Oil and Gas, Inc. in July
2001, we purchased commodity hedges to protect our investment. These hedges, in
the form of price floors, covered nearly all of the forecasted production from
the acquired properties through the end of 2003 at floor prices ranging from
$3.75 to $4.25 per MMBtu. Due to the falling natural gas prices in the latter
half of 2001, we collected approximately $12.7 million on these hedges. The
price floors relating to 2002 and 2003 were purchased from Enron Corporation,
which filed bankruptcy in December 2001. We sold our bankruptcy claim against
Enron in February 2002 for net proceeds of approximately $9.2 million. In total,
we collected approximately $21.9 million from the price floors relating to the
Matrix acquisition, resulting in a net cash gain of approximately $3.9 million
over the cost of the floors. Because of the rise in natural gas prices after
December 2001, we would not have collected anything on the price floors relating
to 2003, even if Enron had not filed bankruptcy, as the natural gas NYMEX prices
during 2003 were above $3.75 (the floor price for 2003). We calculate that our
total cash loss due to Enron's bankruptcy was approximately $5.4 million,
representing the difference between what we would have collected during 2002 and
the $9.2 million that we obtained from selling the bankruptcy claim.
73
Denbury Resources Inc.
Notes to Consolidated Financial Statements
When Enron filed for bankruptcy during the fourth quarter of 2001, these
Enron hedges ceased to qualify for hedge accounting treatment, which changed the
accounting treatment for those hedges as of that point in time as required by
SFAS No. 133. The result was that any future changes in the current market value
of these assets had to be reflected in the income statement and any remaining
accumulated other comprehensive income at the time of the accounting change had
to be recognized over the original expected life of the hedges. To adjust the
value of the Enron hedges down to the market value at December 31, 2001, which
was determined to be the amount that we received from the sale of our claims in
February 2002, we recorded a pre-tax write-down of $24.4 million in the fourth
quarter of 2001. We also had a claim against Enron for production receivables
relating to November 2001 natural gas production that was also sold in February
2002, which resulted in an overall total pre-tax loss on our Enron related
assets of $25.2 million. The after-tax balance in accumulated other
comprehensive income related to these Enron hedges was approximately $11.6
million at the point they no longer qualified for hedge accounting. Accordingly,
we recognized pre-tax income attributable to the Enron hedges during 2002 of
approximately $13.4 million and recognized pre-tax income during 2003 of
approximately $5.1 million. The three-year total pre-tax net loss on the Enron
hedges was approximately $5.9 million, which approximates the difference between
the amount collected and paid for the Enron portion of the associated price
floors.
Hedging Contracts at December 31, 2004
Crude Oil Contracts: NYMEX Contract Prices Per Bbl
----------------------------------------------------- Estimated
Collar Prices Fair Value at
-------------------------- December 31, 2004
Type of Contract and Period Bbls/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ------------- ------------ ------------ ------------ ---------------------
Floor Contracts
Jan. 2005 - Dec. 2005........... 7,500 $ 27.50 - - $ 949
Natural Gas Contracts: NYMEX Contract Prices Per MMBtu
----------------------------------------------------- Estimated
Collar Prices Fair Value at
-------------------------- December 31, 2004
Type of Contract and Period MMBtu/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ------------- ------------ ------------ ------------ ---------------------
Collar Contracts
Jan. 2005 - Dec. 2005........... 15,000 - $ 3.00 $ 5.50 $ (5,815)
At December 31, 2004, our derivative contracts were recorded at their fair
value, which was a net liability of $4.9 million. To the extent our hedges are
considered effective, this fair value liability, net of income taxes, is
included in Accumulated other comprehensive income (loss) reported under
Stockholders' equity in our Consolidated Balance Sheets. The balance in
accumulated other comprehensive loss of $4.8 million at December 31, 2004,
represents the deficit in the fair market value of our derivative contracts as
compared to the cost of our hedges, net of income taxes. The $4.8 million in
accumulated other comprehensive loss as of December 31, 2004, will expire within
the next 12 months.
We have decided to de-designate from hedge accounting treatment our
existing derivative hedging instruments, effective January 1, 2005. As such, we
will account for our derivative instruments in future periods as speculative
contracts and future changes in the fair value of these instruments will be
recognized in the income statement in the period of change. While this may
result in more volatility in our income statement in future periods, we believe
that the benefits associated with applying hedge accounting do not outweigh the
cost, time and effort required to apply hedge accounting.
NOTE 10. COMMITMENTS AND CONTINGENCIES
We have operating leases for the rental of office space, equipment, and
vehicles that totaled $21.6 million, $16.6 million, and $1.7 million as of
December 31, 2004, 2003,and 2002, respectively. In addition, in 2004 we entered
into two lease financing arrangements totaling $6.9 million for equipment at our
McComb Field and Jackson Dome CO2 Field. These lease terms are for seven years
with monthly payments of approximately $91,000 per month. In August 2003, we
entered into a $6.0 million lease financing arrangement for certain equipment at
our CO2 processing facility at Mallalieu Field. This lease term is for seven
years with monthly payments of approximately $81,000 per month.
74
Denbury Resources Inc.
Notes to Consolidated Financial Statements
In 2004, we entered into two agreements with Genesis to transport crude oil
and CO2. These agreements are accounted for as capital leases and are discussed
in detail in Note 3.
At December 31, 2004, long-term commitments for these items require the
following future minimum rental payments:
Capital Operating
(In Thousands) Leases Leases
- --------------------------------------------------------------- ------------
2005........................................ $ 806 $ 3,977
2006........................................ 806 3,967
2007........................................ 806 3,954
2008........................................ 806 3,807
2009........................................ 806 3,064
Thereafter.................................. 2,777 2,813
------------ ------------
Total minimum lease payments.............. 6,807 $ 21,582
============
Less: Amount representing interest......... (2,248)
------------
Present value of minimum lease payments... $ 4,559
============
Long-term contracts require us to deliver CO2 to our industrial CO2
customers at various contracted prices, plus we have a CO2 delivery obligation
to Genesis related to two CO2 volumetric production payments (see "Genesis
Transactions" above). Based upon the maximum amounts deliverable as stated in
the contracts and the volumetric production payment, we estimate that we may be
obligated to deliver up to 398 Bcf of CO2 to these customers over the next 17
years; however, since the group as a whole has historically purchased less CO2
than the maximum allowed in their contracts, based on the current level of
deliveries, we project that our commitment would likely be reduced to
approximately 332 Bcf. The maximum volume required in any given year is
approximately 101 MMcf/d, although based on our current level of deliveries,
this would likely be reduced to approximately 78 MMcf/d. Given the size of our
proven CO2 reserves at December 31, 2004 (approximately 2.7 Tcf before deducting
approximately 178.7 Bcf for the VPPs), our current production capabilities and
our projected levels of CO2 usage for our own tertiary flooding program, we
believe that we can meet these delivery obligations.
Denbury is subject to various possible contingencies that arise primarily
from interpretation of federal and state laws and regulations affecting the oil
and natural gas industry. Such contingencies include differing interpretations
as to the prices at which oil and natural gas sales may be made, the prices at
which royalty owners may be paid for production from their leases, environmental
issues and other matters. Although management believes that it has complied with
the various laws and regulations, administrative rulings and interpretations
thereof, adjustments could be required as new interpretations and regulations
are issued. In addition, production rates, marketing and environmental matters
are subject to regulation by various federal and state agencies.
Litigation
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
75
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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.
NOTE 11. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under
short-term contracts at the current area market price. The loss of any purchaser
would not be expected to have a material adverse effect upon our operations. For
the year ended December 31, 2004, two purchasers each accounted for 10% or more
of our oil and natural gas revenues: Hunt Refining (21%) and Genesis (14%). For
the year ended December 31, 2003, we had two significant purchasers that each
accounted for 10% or more of our oil and natural gas revenues: Hunt Refining
(15%) and Genesis (12%). For the year ended December 31, 2002, two purchasers
each accounted for 10% or more of our natural gas revenues: Hunt Refining (14%)
and Genesis (11%).
Accounts Payable and Accrued Liabilities
(In Thousands) Year Ended December 31,
- --------------------------------------------------------------------------------------
2004 2003
----------------- -----------------
Accounts payable................................ $ 26,262 $ 33,321
Accrued compensation............................ 5,613 2,806
Accrued exploration and development costs....... 5,439 7,546
Accrued interest ............................... 4,219 4,272
Asset retirement obligations - current.......... 2,596 2,101
Deferred revenues - Genesis..................... 2,431 2,105
Advances payable................................ 76 4,430
Other........................................... 5,224 5,768
----------------- -----------------
Total ........................................ $ 51,860 $ 62,349
================= =================
76
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Supplemental Cash Flow Information
(In Thousands) Year Ended December 31,
- --------------------------------------------------------------------------
2004 2003 2002
------------ ------------ -------------
Interest paid................... $ 18,099 $ 23,525 $ 24,636
Income taxes paid (refunded).... 20,726 184 (1,304)
In 2004, we recorded a non-cash increase to property and debt in the amount
of $4.6 million in connection with two capital leases. In August through
December 2004, the company issued 1,150,000 shares of restricted stock with a
market value of $23.3 million on the date of grant. See Note 8 Stockholders'
Equity-Restricted Stock.
Fair Value of Financial Instruments
(In Thousands) December 31,
- ----------------------------------------------------------------------------------------------------------------------
2004 2003
------------------------------ ------------------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
-------------- --------------- ------------- ---------------
Senior bank debt.................................... $ - $ - $ 75,000 $ 75,000
7.5% Senior Subordinated Notes due 2013............. 223,397 243,000 223,203 232,875
As of December 31, 2003, the carrying value of our bank debt approximated
fair value based on the fact that our bank debt is subject to short-term
floating interest rates that approximated the rates available to us at those
periods. The fair values of our senior subordinated notes are based on quoted
market prices. The fair values of our short-term investments are discussed in
Note 1. We have other financial instruments consisting primarily of cash, cash
equivalents, short-term receivables and payables that approximate fair value due
to the nature of the instrument and the relatively short maturities.
NOTE 12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
On December 29, 2003, we amended the indenture for our 7.5% Senior
Subordinated Notes due 2013 to reflect our new holding company organizational
structure (see Note 1 and Note 6). As part of this restructuring our indenture
was amended so that both Denbury Resources Inc. and Denbury Onshore, LLC became
co-obligors of our subordinated debt. Prior to this restructure, Denbury
Resources Inc. was the sole obligor. Our subordinated debt is fully and
unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries.
Genesis Energy, Inc., the subsidiary that holds the Company's investment in
Genesis Energy, L.P., is not a guarantor of our subordinated debt. The results
of our equity interest in Genesis is reflected through the equity method by one
of our significant subsidiaries, Denbury Gathering & Marketing. The following is
condensed consolidating financial information for Denbury Resources Inc.,
Denbury Onshore, LLC, and significant subsidiaries:
77
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Balance Sheets
(In Thousands) December 31, 2004
- -----------------------------------------------------------------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
---------------- --------------- ------------- ---------------- ----------------
Assets
Current assets.............................. $ 1 $ 171,997 $ 204,709 $ (203,861) $ 172,846
Property and equipment...................... - 796,578 784 - 797,362
Investment in subsidiaries (equity method).. 541,671 - 333,907 (868,787) 6,791
Other assets................................ - 15,707 2,271 (2,271) 15,707
---------------- --------------- ------------- ---------------- ----------------
Total assets.............................. $ 541,672 $ 984,282 $ 541,671 $ (1,074,919) $ 992,706
================ =============== ============= ================ ================
Liabilities and Stockholders' Equity
Current liabilities......................... $ - $ 286,767 $ - $ (203,861) $ 82,906
Long-term liabilities....................... - 370,399 - (2,271) 368,128
Stockholders' equity........................ 541,672 327,116 541,671 (868,787) 541,672
---------------- --------------- ------------- ---------------- ----------------
Total liabilties and stockholders' equity $ 541,672 $ 984,282 $ 541,671 $ (1,074,919) $ 992,706
================ =============== ============= ================ ================
(In Thousands) December 31, 2003
- -----------------------------------------------------------------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
---------------- --------------- ------------- ---------------- ----------------
Assets
Current assets.............................. $ 1 $ 85,109 $ 23,045 $ - $ 108,155
Property and equipment ..................... - 560,038 292,473 - 852,511
Investment in subsidiaries (equity method).. 421,201 - 210,803 (624,554) 7,450
Other assets................................ - 11,186 3,319 - 14,505
---------------- --------------- ------------- ---------------- ----------------
Total assets.............................. $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621
================ =============== ============= ================ ================
Liabilities and Stockholders' Equity
Current liabilities......................... $ - $ 119,364 $ 7,210 $ - $ 126,574
Long-term liabilities....................... - 333,616 101,229 - 434,845
Stockholders' equity........................ 421,202 203,353 421,201 (624,554) 421,202
---------------- ------------------------------ ---------------- ----------------
Total liabilities and stockholders' equity $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621
================ =============== ============= ================ ================
78
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Operations
(In Thousands) Year Ended December 31, 2004
- ----------------------------------------------------------------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
--------------- --------------- -------------- ---------------- ----------------
Revenues..................................... $ - $ 320,328 $ 62,644 $ - $ 382,972
Expenses..................................... 171 222,988 37,837 - 260,996
--------------- --------------- -------------- ---------------- ----------------
Income before the following: (171) 97,340 24,807 - 121,976
Equity in net earnings of subsidiaries..... 82,554 - 67,122 (149,812) (136)
--------------- --------------- -------------- ---------------- ----------------
Income before income taxes .................. 82,383 97,340 91,929 (149,812) 121,840
--------------- --------------- -------------- ---------------- ----------------
Income tax provision......................... (65) 30,082 9,375 - 39,392
--------------- --------------- -------------- ---------------- ----------------
Net income (loss).......................... $ 82,448 $ 67,258 $ 82,554 $ (149,812) $ 82,448
=============== =============== ============== ================ ================
(In Thousands) Year Ended December 31, 2003
- ----------------------------------------------------------------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
--------------- --------------- -------------- ---------------- ----------------
Revenues..................................... $ - $ 238,072 $ 94,942 $ - $ 333,014
Expenses..................................... - 196,392 56,725 - 253,117
--------------- --------------- -------------- ---------------- ----------------
Income before the following: - 41,680 38,217 - 79,897
Equity in net earnings of subsidiaries..... 56,553 - 40,667 (96,964) 256
--------------- --------------- -------------- ---------------- ----------------
Income before income taxes and cumulative
effect of change in accounting principle... 56,553 41,680 78,884 (96,964) 80,153
Income tax provision......................... - 5,250 20,962 - 26,212
--------------- --------------- -------------- ---------------- ----------------
Net income before cumulative effect of change
in accounting principle.................... 56,553 36,430 57,922 (96,964) 53,941
--------------- --------------- -------------- ---------------- ----------------
Cumulative effect of a change in accounting
principle, net of income tax............... - 3,981 (1,369) - 2,612
--------------- --------------- -------------- ---------------- ----------------
Net income (loss).......................... $ 56,553 $ 40,411 $ 56,553 $ (96,964) $ 56,553
=============== =============== ============== ================ ================
(In Thousands) Year Ended December 31, 2002
- -----------------------------------------------------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
--------------- --------------- -------------- ----------------
Revenues..................................... $ 231,147 $ 54,005 $ - $ 285,152
Expenses..................................... 166,805 48,087 - 214,892
--------------- --------------- -------------- ----------------
Income before the following: 64,342 5,918 - 70,260
Equity in net earnings of subsidiaries..... 3,456 55 (3,456) 55
--------------- --------------- -------------- ----------------
Income (loss) before income taxes............ 67,798 5,973 (3,456) 70,315
Income tax provision......................... 21,003 2,517 - 23,520
--------------- --------------- -------------- ----------------
Net income (loss).......................... $ 46,795 $ 3,456 $ (3,456) $ 46,795
=============== =============== ============== ================
79
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flow
(In Thousands) Year Ended December 31, 2004
- ---------------------------------------------------------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
---------------- --------------- -------------- ---------------- ----------------
Cash flow from operations.............. $ (9,192) $ 331,123 $ (153,279) $ - $ 168,652
Cash flow from investing activities.... - (246,973) 153,423 - (93,550)
Cash flow from financing activities.... 9,192 (75,443) - - (66,251)
---------------- --------------- -------------- ---------------- ----------------
Net increase (decrease) in cash flow... - 8,707 144 - 8,851
Cash, beginning of period.............. 1 24,174 13 - 24,188
---------------- --------------- -------------- ---------------- ----------------
Cash, end of period.................... $ 1 $ 32,881 $ 157 $ - $ 33,039
================ =============== ============== ================ ================
(In Thousands) Year Ended December 31, 2003
- ---------------------------------------------------------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
---------------- --------------- -------------- ---------------- ----------------
Cash flow from operations.............. $ $ 146,639 $ 50,976 $ - $ 197,615
Cash flow from investing activities.... - (81,256) (54,622) - (135,878)
Cash flow from financing activities.... 1 (61,490) - - (61,489)
---------------- --------------- -------------- ---------------- ----------------
Net increase (decrease) in cash flow... 1 3,893 (3,646) - 248
Cash, beginning of period.............. - 20,281 3,659 - 23,940
---------------- --------------- -------------- ---------------- ----------------
Cash, end of period.................... $ 1 $ 24,174 $ 13 $ - $ 24,188
================ =============== ============== ================ ================
(In Thousands) Year Ended December 31, 2002
- ----------------------------------------------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
---------------- --------------- -------------- ----------------
Cash flow from operations.............. $ 146,132 $ 13,468 $ - $ 159,600
Cash flow from investing activities.... (154,908) (16,253) - (171,161)
Cash flow from financing activities.... 12,005 - - 12,005
---------------- --------------- -------------- ----------------
Net increase (decrease) in cash flow... 3,229 (2,785) - 444
Cash, beginning of period.............. 17,052 6,444 - 23,496
---------------- --------------- -------------- ----------------
Cash, end of period.................... $ 20,281 $ 3,659 $ - $ 23,940
================ =============== ============== ================
80
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 13. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and
natural gas property acquisition, exploration and development activities.
Property acquisition costs are those costs incurred to purchase, lease, or
otherwise acquire property, including both undeveloped leasehold and the
purchase of reserves in place. Exploration costs include costs of identifying
areas that may warrant examination and examining specific areas that are
considered to have prospects containing oil and natural gas reserves, including
costs of drilling exploratory wells, geological and geophysical costs and
carrying costs on undeveloped properties. Development costs are incurred to
obtain access to proved reserves, including the cost of drilling development
wells, and to provide facilities for extracting, treating, gathering and storing
the oil and natural gas.
Costs incurred in oil and natural gas activities were as follows:
(In Thousands) Year Ended December 31,
- --------------------------------------------------------------------------
2004 2003 2002
------------ ------------ -------------
Property acquisitions:
Proved ....................... $ 22,271 $ 22,307 $ 56,364
Unevaluated................... 3,459 3,955 4,342
Exploration..................... 23,987 34,050 29,985
Development..................... 128,351 98,132 64,946
Asset retirement obligations.... 3,174 3,405 -
------------ ------------ -------------
Total costs incurred (1)...... $ 181,242 $ 161,849 $ 155,637
============ ============ =============
(1) Capitalized general and administrative costs that directly relate to exploration and development activities
were $5.1 million, $5.5 million, $5.3 million for the years ended December 31, 2004, 2003 and 2002,
respectively.
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities,
excluding corporate overhead and interest costs, were as follows:
(In Thousands, Except per BOE data) Year Ended December 31,
- ----------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------- ------------ -------------
Oil, natural gas and related product sales......................... $ 444,777 $ 385,463 $ 274,894
Gain (loss) on effective hedge contracts........................... (70,469) (62,210) 932
------------- ------------ -------------
Total revenues................................................... 374,308 323,253 275,826
------------- ------------ -------------
Lease operating costs.............................................. 87,107 89,439 71,188
Production taxes and marketing expenses............................ 18,737 14,819 11,902
Depletion, depreciation and accretion.............................. 90,913 90,694 90,679
(Gain) loss on ineffective hedge contracts......................... 15,358 (3,578) (3,093)
------------- ------------ -------------
Net operating income............................................. 162,193 131,879 105,150
Income tax provision............................................... 52,437 45,427 36,563
------------- ------------ -------------
Results of operations from oil and natural gas producing activities $ 109,756 $ 86,452 $ 68,587
============= ============ =============
Depletion, depreciation and accretion per BOE...................... $ 7.54 $ 7.16 $ 6.98
============= ============ =============
81
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates for all years presented
were prepared by DeGolyer and MacNaughton, independent petroleum engineers
located in Dallas, Texas. The reserves were prepared in accordance with
guidelines established by the Securities and Exchange Commission and,
accordingly, were based on existing economic and operating conditions. Oil and
natural gas prices in effect as of the reserve report date were used without any
escalation. (See "Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves" below for a
discussion of the effect of the different prices on reserve quantities and
values.) Operating costs, production and ad valorem taxes and future development
costs were based on current costs with no escalation.
We have a corporate policy whereby we do not book proved undeveloped
reserves until we have committed to perform the required development operations,
the majority of which we generally expect to commence within the next year. We
also have a corporate policy whereby proved undeveloped reserves must be
economic at prices significantly lower than the year-end prices used in our
reserve report, at prices closer to historical averages.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of our oil and natural gas reserves
or the costs that would be incurred to obtain equivalent reserves. All of our
reserves are located in the United States.
Estimated Quantities of Reserves
Year Ended December 31,
--------------------------------------------------------------------------------
2004 2003 2002
-------------------------- -------------------------- --------------------------
Oil Gas Oil Gas Oil Gas
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
Balance at beginning of year............ 91,266 221,887 97,203 200,947 76,490 198,277
Revisions of previous estimates......... (3,271) 2,898 2,958 (25,451) (408) (22,975)
Revisions due to price changes.......... 492 25 50 (152) 3,020 2,660
Extensions and discoveries.............. 1,575 61,158 1,059 68,408 2,326 51,819
Improved recovery (1)................... 18,863 - 4,009 - - -
Production.............................. (7,044) (30,094) (6,896) (34,623) (6,874) (36,662)
Acquisition of minerals in place........ 429 5,304 838 14,541 23,383 9,360
Sales of minerals in place.............. (1,023) (92,694) (7,955) (1,783) (734) (1,532)
------------ ------------ ------------- ------------ ------------- ------------
Balance at end of year.................. 101,287 168,484 91,266 221,887 97,203 200,947
============ ============ ============= ============ ============= ============
Proved Developed Reserves:
Balance at beginning of year............ 53,804 144,750 62,398 142,812 54,722 169,897
Balance at end of year.................. 55,998 94,573 53,804 144,750 62,398 142,812
(1) Improved recovery additions result from the application of secondary recovery methods such as water-flooding
or tertiary recovery methods such as CO2 flooding.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure")
does not purport to present the fair market value of our oil and natural gas
properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates. It should be noted that
82
Denbury Resources Inc.
Notes to Consolidated Financial Statements
estimates of reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices to the estimated future production of year-end proved
reserves. The product prices used in calculating these reserves have varied
widely during the three-year period. These prices have a significant impact on
both the quantities and value of the proven reserves as the reduced oil price
causes wells to reach the end of their economic life much sooner and can make
certain proved undeveloped locations uneconomical, both of which reduce the
reserves. The following representative oil and natural gas year-end prices were
used in the Standardized Measure. These prices were adjusted by field to arrive
at the appropriate corporate net price.
December 31,
----------------------------------------
2004 2003 2002
------------- ------------ -------------
Oil (NYMEX)..................... $ 43.45 $ 32.52 $ 31.20
Natural Gas (NYMEX Henry Hub)... 6.15 6.19 4.79
Future cash inflows were reduced by estimated future production,
development and abandonment costs based on year-end costs to determine pre-tax
cash inflows. Future income taxes were computed by applying the statutory tax
rate to the excess of pre-tax cash inflows over our tax basis in the associated
proved oil and natural gas properties. Tax credits and net operating loss
carryforwards were also considered in the future income tax calculation. Future
net cash inflows after income taxes were discounted using a 10% annual discount
rate to arrive at the Standardized Measure.
(In Thousands) December 31,
- ----------------------------------------------------------------------------------------------------------------
2004 2003 2002
--------------- -------------- ---------------
Future cash inflows........................................ $ 4,742,276 $ 4,059,424 $ 3,787,077
Future production costs.................................... (1,509,280) (1,120,741) (1,044,193)
Future development costs................................... (340,879) (300,981) (268,269)
--------------- -------------- ---------------
Future net cash flows before taxes....................... 2,892,117 2,637,702 2,474,615
Future income taxes........................................ (906,221) (748,273) (689,617)
--------------- -------------- ---------------
Future net cash flows.................................... 1,985,896 1,889,429 1,784,998
10% annual discount for estimated timing of cash flows..... (856,700) (765,302) (756,022)
--------------- -------------- ---------------
Standardized measure of discounted future net cash flows $ 1,129,196 $ 1,124,127 $ 1,028,976
=============== ============== ===============
83
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
(In Thousands) Year Ended December 31,
- ------------------------------------------------------------------------------------------------------------------
2004 2003 2002
-------------- -------------- --------------
Beginning of year................................................. $ 1,124,127 $ 1,028,976 $ 505,795
Sales of oil and natural gas produced, net of production costs.... (339,250) (281,205) (191,803)
Net changes in sales prices....................................... 352,830 141,932 694,646
Extensions and discoveries, less applicable future development
and production costs............................................ 151,014 235,228 151,926
Improved recovery (1)............................................. 190,033 40,663 -
Previously estimated development costs incurred................... 55,091 52,874 34,931
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production............. (197,959) (157,989) (50,855)
Accretion of discount............................................. 156,637 142,622 57,433
Acquisition of minerals in place.................................. 9,003 44,856 160,899
Sales of minerals in place........................................ (300,481) (78,830) (5,285)
Net change in income taxes........................................ (71,849) (45,000) (328,711)
-------------- -------------- --------------
End of year....................................................... $ 1,129,196 $ 1,124,127 $ 1,028,976
============== ============== ==============
(1) Improved recovery additions result from the application of secondary recovery methods such as water flooding
or tertiary recovery methods such as CO2 flooding.
CO2 Reserves
Based on engineering reports prepared by DeGolyer and MacNaughton, our CO2
reserves, on a 100% working interest basis, were estimated at approximately 2.7
Tcf at December 31, 2004 (includes 178.7 Bcf of reserves dedicated to two
volumetric production payments with Genesis), 1.6 Tcf at December 31, 2003
(includes 162.6 Bcf of reserves dedicated to a volumetric production payment),
and 1.6 Tcf at December 31, 2002. We make reference to the gross amount of
proved reserves as that 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 we are responsible for distributing the entire CO2 production
stream for both of these purposes.
84
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NOTE 14. UNAUDITED QUARTERLY INFORMATION
- -----------------------------------------------------------------------------------------------------------------
In Thousands, Except Per Share Amounts March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------------------------------------------
2004
- ----
Revenues (1)................................... $ 97,748 $ 106,213 $ 88,029 $ 90,982
Expenses (1)................................... 64,710 77,277 61,886 57,123
Net income (2)................................. 22,304 19,389 18,274 22,481
Net income per share:
Basic ....................................... 0.41 0.35 0.33 0.41
Diluted...................................... 0.40 0.34 0.32 0.39
Cash flow from operations...................... 52,995 53,210 44,766 17,681
Cash flow provided by (used for) investing
activities (2) (3)........................... (68,111) (51,351) 69,046 (43,134)
Cash flow provided by (used for) financing
activities (2)............................... 8,136 8,873 (84,035) 775
2003
- ----
Revenues....................................... $ 86,432 $ 84,188 $ 79,415 $ 82,979
Expenses (4)................................... 58,910 76,660 56,691 60,856
Income before accounting change (5)............ 18,453 5,129 15,149 15,210
Net income (5)................................. 21,065 5,129 15,149 15,210
Income per share before accounting change:
Basic ....................................... 0.34 0.10 0.28 0.28
Diluted...................................... 0.33 0.09 0.27 0.27
Net income per share:
Basic ....................................... 0.39 0.10 0.28 0.28
Diluted...................................... 0.38 0.09 0.27 0.27
Cash flow from operations...................... 35,509 60,542 49,789 51,775
Cash flow used for investing activities........ (18,139) (54,742) (35,495) (27,502)
Cash flow provided by (used for) financing
activities................................... 119,860 (147,622) (5,534) (28,193)
(1) The loss on settlement of ineffective hedges has been reclassified from Revenues to Expenses in this
presentation. For the second quarter of 2004, $3.5 million loss was reclassified from Revenues to Expenses.
For the third quarter of 2004, $4.8 million loss was reclassified from Revenues to Expenses.
(2) In July 2004, we sold Denbury Offshore, Inc. a subsidiary that held our offshore assets. We used $85 million
of the proceeds to retire debt (see Note 2).
(3) Auction rate securities in the amount of $35.4 million at September 30, 2004, have been reclassified from cash
and equivalent to short-term investments to conform to the December 31, 2004 presentation. Accordingly, cash
flow provided by investing activities for the quarter ended September 30, 2004 has been adjusted to reflect
this presentation.
(4) In the second quarter of 2003, we incurred a $17.6 million ($11.5 million net of income tax) loss on early
retirement of debt (see Note 6).
(5) In the first quarter of 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS
No. 143, "Accounting for Asset Retirement Obligations" (see Note 4).
85
Denbury Resources Inc.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
- -------------------------------------------------------------------------------
FINANCIAL DISCLOSURE
- --------------------
On May 12, 2004, the Audit Committee of Denbury approved the appointment of
PricewaterhouseCoopers LLP as the Company's independent auditors for the fiscal
year ending December 31, 2004, replacing Deloitte & Touche LLP, which had been
the Company's independent auditors since 1990. This decision was affirmed by
Denbury's Board of Directors. Information regarding this change in independent
auditors was included in our report on Form 8-K dated May 17, 2004, and
subsequently amended on May 24, 2004. There have been no other changes in
accountants nor any disagreements with accountants.
ITEM 9A. CONTROLS AND PROCEDURES
- --------------------------------
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our chief executive officer and chief financial
officer have evaluated our disclosure controls and procedures as of the end of
the period covered by this annual report on Form 10-K and have determined that
such disclosure controls and procedures are effective in all material respects
in providing to them on a timely basis material information required to be
disclosed in this annual report. Our assessment of our internal control over
financial reporting as of December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which is included in Item 8 herein.
There have been no changes in internal controls over financial reporting
during the period covered by this annual report on Form 10-K that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
In January 2005, we began processing our transactions on a newly
implemented accounting software system. We changed systems in order (i) to
integrate and automate more of our functions, which will also allow us to have
more information in one integrated database, (ii) to provide operating
efficiencies, (iii) to enable us to close our books in a more timely manner
without sacrificing quality, (iv) to review and improve our processes and (v)
improve the internal control surrounding our computer systems. All of Denbury's
2004 accounting was performed on its prior system and as a result, this change
had no impact on Denbury's internal control over financial reporting during
2004. As a result of moving to a new system in January 2005, we anticipate that
certain control procedures will need to be changed during 2005 in order to
conform to our new system. We plan to evaluate those changes during the first
quarter of 2005. While we believe that our new accounting system will ultimately
strengthen our internal control system, there are inherent weaknesses in
implementing any new system and until we have fully tested all changes to our
controls, we may not be able to provide assurance that our disclosure controls
are effective in all material respects.
ITEM 9B. OTHER INFORMATION
- --------------------------
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
- --------------------------------------------------------
Directors of the Company
Information as to the names, ages, positions and offices with Denbury,
terms of office, periods of service, business experience during the past five
years and certain other directorships held by each director or person nominated
to become a director of Denbury will be set forth in the "Election of Directors"
segment of the Proxy Statement ("Proxy Statement") for the Annual Meeting of
Shareholders to be held May 11, 2005, ("Annual Meeting") and is incorporated
herein by reference.
Executive Officers of the Company
Information concerning the executive officers of Denbury will be set forth
in the "Management" section of the Proxy Statement for the Annual Meeting and is
incorporated herein by reference.
86
Denbury Resources Inc.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 and the rules
thereunder require the Company's executive officers and directors, and persons
who beneficially own more than ten percent (10%) of a registered class of the
Company's equity securities, to file reports of ownership and changes in
ownership with the Securities and Exchange Commission and exchanges and to
furnish the Company with copies. Based solely on its review of the copies of
such forms received by it, or written representations from such persons, the
Company is not aware of any person who failed to file any reports required by
Section 16(a) to be filed for fiscal 2004.
Code of Ethics
We have adopted a Code of Ethics for Senior Financial Officers and
Principal Executive Officer. This Code of Ethics, including any amendments or
waivers, is posted on our website at www.denbury.com.
ITEM 11. EXECUTIVE COMPENSATION
- -------------------------------
Information concerning remuneration received by Denbury's executive
officers and directors will be presented under the caption "Statement of
Executive Compensation" in the Proxy Statement for the Annual Meeting and is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
- -------------------------------------------------------------------------------
RELATED STOCKHOLDER MATTERS
- ---------------------------
Information as to Denbury's common stock that may be issued under our
equity compensation plans, which plans have been approved by shareholders, and
the number of shares of Denbury's common stock beneficially owned as of March 1,
2005, by each of its directors and nominees for director, its five most highly
compensated executive officers and its directors and executive officers as a
group will be presented under the captions "Equity Compensation Plan
Information" and "Security Ownership of Certain Beneficial Owners and
Management" in the Proxy Statement for the Annual Meeting and is incorporated
herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- -------------------------------------------------------
Information on related transactions will be presented under the caption
"Compensation Committee Interlocks and Insider Participation" and "Interests of
Insiders in Material Transactions" in the Proxy Statement for the Annual Meeting
and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
- -----------------------------------------------
Information required to be presented on principal accountant fees and
services will be presented under the caption "Relationship with Independent
Accountants" in the Proxy Statement for the Annual Meeting and is incorporated
herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
- ---------------------------------------------------
Financial Statements and Schedules. Financial statements and schedules filed as
a part of this report are presented on page 46. All financial statement
schedules have been omitted because they are not applicable or the required
information is presented in the financial statements or the notes to
consolidated financial statements.
Exhibits. The following exhibits are filed as part of this report.
Exhibit No. Exhibit
----------- -------
2(a) Agreement and Plan of Merger to Form Holding Company, dated as of December 22, 2003, but effective
December 29, 2003 at 9:00 a.m. EST, by and among the Registrant, the Predecessor and Denbury
Onshore, LLC (incorporated by reference as Exhibit 2.1 of our Form 8-K filed December 29, 2003).
87
Denbury Resources Inc.
Exhibit No. Exhibit
----------- -------
2(b) Stock Purchase Agreement made as of July 19, 2004, between Denbury Resources Inc. and Newfield 2(b)
Exploration Company (incorporated by reference as exhibit 2.14 of our Form 8-K filed August 4,
2004).
3(a) Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware Secretary of
State on December 29, 2003 (incorporated by reference as Exhibit 3.1 of our Form 8-K filed December
29, 2003).
3(b) Bylaws of Denbury Resources Inc., a Delaware corporation, adopted December 29, 2003 (incorporated by
reference as Exhibit 3.2 of our Form 8-K filed December 29, 2003).
4(a) Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013 among Denbury Resources Inc.,
certain of its subsidiaries and JP Morgan Chase Bank as trustee, dated March 25, 2003 (incorporated
by reference from Exhibit 4(a) to our Registration Statement No. 333-105233-04 on Form S-4, filed
May 14, 2003).
4(b) First Supplemental Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013 dated as of
December 29, 2003, among Denbury Resources Inc., certain of its subsidiaries, and the JP Morgan
Chase Bank, as trustee (incorporated by reference as Exhibit 4.1 of our Form 8-K filed December 29,
2003).
10(a) Fifth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, Denbury
Resources Inc., as Parent Guarantor, Bank One, N.A. as Administrative Agent, and certain other
financial institutions, dated September 1, 2004 (incorporated by reference as Exhibit 1.1 of our
Form 8-K filed September 3, 2004).
10(b)** Denbury Resources Inc. Amended and Restated Stock Option Plan (incorporated by reference as Exhibit
99 of our Registration Statement No. 333-106253 on Form S-8, filed June 18, 2003).
10(c)** Denbury Resources Inc. Stock Purchase Plan (incorporated by reference as Exhibit 4(g) of the
Registrant's Registration Statement on Form S-8, No. 333-1006, filed February 2, 1996, with
amendments incorporated by reference as exhibits of our Registration Statements on Forms S-8, No.
333-70485, filed January 12, 1999, No. 333-39218, filed June 13, 2000 and No. 333-90398, filed June
13, 2002).
10(d)** Form of indemnification agreement between Denbury Resources Inc. and its officers and directors
(incorporated by reference as Exhibit 10 of our Form 10-Q for the quarter ended June 30, 1999).
10(e)** Denbury Resources Inc. Directors Compensation Plan (incorporated by reference as Exhibit 4 of our
Registration Statement on Form S-8, No. 333-39172, filed June 13, 2000 and amended March 2, 2001).
10(f)** Denbury Resources Severance Protection Plan, dated December 6, 2001 (incorporated by reference as
Exhibit 10(f) of our Form 10-K for the year ended December 31, 2000).
10(g)* ** Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan as amended.
10(h)* ** Description of non-employee director's compensation arrangements.
10(i)* ** Description of cash bonus compensation arrangements for employees and officers.
10(j)* ** Description of stock option grant practices for employees and officers.
10(k)* ** Form of restricted stock award that vests 20% per annum, for grants to officers pursuant to 2004
Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(l)* ** Form of restricted stock award that vests on retirement, for grants to officers pursuant to 2004
Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(m)* ** Form of restricted stock award that vests 20% per annum, for grants to directors pursuant to 2004
Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(n)* ** Form of incentive stock option agreement that vests 25% per annum, for grants to new employees and
officers on their hire date pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources
Inc.
10(o)* ** Form of incentive stock option agreement that cliff vests 100% four years from the date of grant,
for grants to employees and officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury
Resources Inc.
10(p)* ** Form of non-qualified stock option agreement that vests 25% per annum, for grants to new employees
and officers on their hire date pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury
Resources Inc.
10(q)* ** Form of non-qualified stock option agreement that vests 100% four years from the date of grant, for
grants to employees, officers and directors pursuant to 2004 Omnibus Stock and Incentive Plan for
Denbury Resources Inc.
10(r)* ** Form of stock appreciation rights agreement that vests 25% per annum, for grants to new employees
and officers on their hire date pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury
Resources Inc.
10(s)* ** Form of stock appreciation rights agreement that vests 100% four years from the date of grant, for
grants to employees, officers and directors pursuant to 2004 Omnibus Stock and Incentive Plan for
Denbury Resources Inc.
88
Denbury Resources Inc.
Exhibit No. Exhibit
----------- -------
16 Letter from Deloitte & Touche LLP to the Securities and Exchange Commission, dated May 24, 2004,
regarding change in certifying accountant, pursuant to Item 304(a)(3) of Regulation S-K 21* (filed
as exhibit 16.1 of our Form 8-K/A filed May 24, 2004) and incorporated by reference herein.
21* List of Subsidiaries of Denbury Resources Inc.
23(a)* Consent of PricewaterhouseCoopers LLP.
23(b)* Consent of Deloitte & Touche LLP.
23(c)* Consent of DeGolyer and MacNaughton.
31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99* The summary of DeGolyer and MacNaughton's Report as of December 31, 2004, on oil and gas reserves
(SEC Case) dated March 9, 2005.
* Filed herewith.
** Compensation arrangements.
89
Denbury Resources Inc.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Denbury Resources Inc. has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
DENBURY RESOURCES INC.
March 11, 2005 /s/ Phil Rykhoek
-----------------------
Phil Rykhoek
Sr. Vice President and Chief
Financial Officer
March 11, 2005 /s/ Mark C. Allen
-----------------------
Mark C. Allen
Vice President and Chief
Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of Denbury
Resources Inc. and in the capacities and on the dates indicated.
March 11, 2005 /s/ Gareth Roberts
-----------------------
Gareth Roberts
Director, President and Chief
Executive Officer
(Principal Executive Officer)
March 11, 2005 /s/ Phil Rykhoek
-----------------------
Phil Rykhoek
Sr. Vice President and Chief
Financial Officer
(Principal Financial Officer)
March 11, 2005 /s/ Mark C. Allen
-----------------------
Mark C. Allen
Vice President and Chief
Accounting Officer
(Principal Accounting Officer)
March 11, 2004 /s/ Ron Greene
-----------------------
Ron Greene
Director
March 11, 2005 /s/ David I. Heather
-----------------------
David I. Heather
Director
March 11, 2005 /s/ Randy Stein
-----------------------
Randy Stein
Director
90
March 11, 2005 /s/ Wieland Wettstein
-----------------------
Wieland Wettstein
Director
March 11, 2005 /s/ Greg McMichael
-----------------------
Greg McMichael
Director
March 11, 2005 /s/ Donald Wolf
-----------------------
Donald Wolf
Director
91