e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2006 FORM 10-K
(Mark One)
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Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 |
For the fiscal year ended December 31, 2006
OR
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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)
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Delaware
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20-0467835 |
(State or other jurisdiction
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(I.R.S. Employer |
of incorporation or organization)
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Identification No.) |
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5100 Tennyson Parkway, |
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Suite 1200, Plano, TX
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75024 |
(Address of principal executive offices)
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(Zip Code) |
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Registrants telephone number, including area code:
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(972) 673-2000 |
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class:
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Name of Each Exchange on Which Registered: |
Common Stock $.001 Par Value
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act.
Yes o No þ
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 þ No o
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 registrants 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. (See definition of accelerated filer and large accelerated filer in
Rule 12-b2 of the Exchange Act). (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule
12b-2).
Yes o No þ
The aggregate market value of the registrants common stock held by non-affiliates, based on the
closing price of the registrants common stock as of the last business day of the registrants most
recently completed second fiscal quarter was $3,417,875,900.
The number of shares outstanding of the registrants Common Stock as of January 31, 2007, was
120,470,488.
DOCUMENTS INCORPORATED BY REFERENCE
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Document:
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Incorporated as to: |
1. Notice and Proxy Statement for
the Annual Meeting of Shareholders
to be held May 15, 2007.
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1. Part III, Items 10, 11, 12, 13, 14 |
Denbury Resources Inc.
2006 Annual Report on Form 10-K
Table of Contents
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Denbury Resources Inc.
Glossary and Selected Abbreviations
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Bbl
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One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil
or other
liquid hydrocarbons. |
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Bbls/d
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Barrels of oil produced per day. |
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Bcf
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One billion cubic feet of natural gas or CO2. |
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BOE
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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. |
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BOE/d
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BOEs produced per day. |
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Btu
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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. |
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CO2
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Carbon dioxide. |
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Finding and Development
Cost
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The average cost per BOE to find and develop proved reserves during a given period. It is calculated by
dividing costs, which includes the total acquisition, exploration and development 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. |
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MBbls
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One thousand barrels of crude oil or other liquid hydrocarbons. |
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MBOE
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One thousand BOEs. |
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Mbtu
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One thousand Btus. |
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Mcf
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One thousand cubic feet of natural gas or CO2. |
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Mcf/d
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One thousand cubic feet of natural gas or CO2 produced per day. |
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Mcfe
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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. |
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Mcfe/d
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Mcfes produced per day. |
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MMBbls
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One million barrels of crude oil or other liquid hydrocarbons. |
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MMBOE
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One million BOEs. |
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MMBtu
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One million Btus. |
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MMcf
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One million cubic feet of natural gas or CO2. |
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MMcfe
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One thousand Mcfe. |
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MMcfe/d
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MMcfes produced per day. |
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PV-10 Value
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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 costs and abandonment, 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. |
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Proved Developed
Reserves*
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Reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods. |
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Proved Reserves*
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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. |
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Proved Undeveloped
Reserves*
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Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells
where a relatively major expenditure is required. |
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Tcf
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One trillion cubic feet of natural gas or CO2. |
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* |
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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) and is engaged in the acquisition, development, operation and exploration of oil and
natural gas properties in the Gulf Coast region of the United States, primarily in Louisiana,
Mississippi, Alabama, and Texas. Our corporate headquarters is located at 5100 Tennyson Parkway,
Suite 1200, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2006, we had
596 employees, 390 of whom were employed in field operations or at the field offices. Our employee
count does not include the approximately 190 employees of Genesis Energy, Inc. as of December 31,
2006, as its employees exclusively carry out the business activities of Genesis Energy, L.P., which
we do not consolidate in our financial statements (see Note 1 to the Consolidated Financial
Statements).
Incorporation and Organization
Denbury was originally incorporated in Canada in 1951. In 1992, we acquired all of the shares
of a United States operating company, Denbury Management, Inc. (DMI), and subsequent to the merger
we sold all of its Canadian assets. Since that time, all of our operations have been in the United
States.
In April 1999, our stockholders approved a move of our corporate domicile from Canada to the
United States as a Delaware corporation. Along with the move, our wholly owned subsidiary, DMI,
was merged into the new Delaware parent company, Denbury Resources Inc. This move of domicile did
not have any effect on our operations or assets.
Effective December 29, 2003, Denbury Resources Inc. changed its corporate structure to a
holding company format. As part of this restructure, Denbury Resources Inc. (predecessor entity)
merged into a newly formed limited liability company, and survived as Denbury Onshore, LLC, a
Delaware limited liability company and an indirect subsidiary of the newly formed holding company,
Denbury Holdings, Inc. Denbury Holdings, Inc. subsequently assumed the name Denbury Resources Inc.
(new entity). Stockholders ownership interests in the business did not change as a result of the
new structure and shares of the Company remain publicly traded under the same symbol (DNR) on the
New York Stock Exchange.
Business Strategy
As part of our corporate strategy, we believe in the following fundamental principles:
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remain focused in specific regions; |
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acquire properties where we believe additional value can be created through a
combination of exploitation, development, exploration and marketing, including
secondary and tertiary operations; |
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acquire properties that give us a majority working interest and operational
control or where we believe we can ultimately obtain it; |
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maximize the value of our properties by increasing production and reserves while
reducing cost; and |
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maintain a highly competitive team of experienced and incentivized personnel. |
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Denbury Resources Inc.
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
During 2006, we concentrated on implementing new tertiary floods in our Phase II fields,
Eucutta, Soso and Martinville Fields, while continuing to develop our Phase I fields Little Creek,
Mallalieu, McComb and Brookhaven. We increased our potential tertiary flood candidates during 2006
with the acquisition of Tinsley Field (Phase III) and Delhi Field (Phase V), and an option to
purchase Hastings Field, adding to our inventory of future tertiary floods. Our tertiary
operations are our principal focus and our core assets. During the last seven years, we have
learned a considerable amount about tertiary operations and working with carbon dioxide
(CO2) and our knowledge continues to grow. We like these tertiary operations because
(i) CO2 investments provide a reasonable rate of return, even at relatively low oil
prices, (ii) tertiary flooding exhibits a lower risk profile, and (iii) to date, in our region of
the United States, we have not encountered any industry competition. Generally, from the Texas
Gulf Coast to Florida, there are no known significant natural sources of carbon dioxide except our
own, and these large volumes of CO2 are the foundation for our entire tertiary program.
CO2 is one of the most efficient tertiary recovery mechanisms for crude oil. The
CO2 acts somewhat like a solvent for the oil, removing it from the oil bearing formation
as the CO2 passes through the rock. CO2 tertiary floods are unique because
they require large volumes of CO2, which to our knowledge is limited to a few
geological basins, one of which is our source near Jackson, Mississippi. Further, the most
efficient way to transport CO2 is via dedicated pipelines, which are also in limited
supply. Because the sources and methods of transportation of CO2 are limited, only 3%
or 250,000 Bbls/d of the United States domestic oil production is derived from tertiary recovery
projects.
Our CO2 source field, Jackson Dome, located near Jackson, Mississippi, was
discovered during the 1970s while being explored for hydrocarbons. This significant source of
CO2 is the only known one of its kind in the United States east of the Mississippi
River. Mississippis first enhanced oil recovery project began in the mid 1980s in Little Creek
Field following the installation of Shell Oil Companys Choctaw CO2 Pipeline. The
183-mile Choctaw Pipeline (now referred to as NEJD pipeline) transported CO2 produced
from Jackson Dome to Little Creek Field. While the CO2 flood initially proved to be
successful in recovering significant amounts of oil, commodity prices at that time made the
projects unattractive for Shell and they later sold their oil fields in this area, as well as the
CO2 source wells and pipeline.
While enhanced oil recovery (EOR) projects utilizing CO2 may not be considered a
new technology, Denbury applies several additional technologies to the fields: well evaluations,
new completion or stimulation techniques, operating equipment and seismic interpretations. We
began our CO2 operations in August 1999, when we acquired Little Creek Field in
Mississippi, followed by our acquisition of Jackson Dome in 2001. Based upon our success at Little
Creek we embarked upon a strategic program to improve our understanding and knowledge of CO2
production and tertiary recovery to build a dominant position in this niche play.
We talk about our tertiary operations by labeling operating areas or groups of fields as
phases. Phase I is in Southwest Mississippi and includes several fields along our 183-mile
CO2 pipeline that we acquired in 2001. The most significant fields in this area are
Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which we just started with the 2006
completion of our CO2 pipeline to East Mississippi, includes Eucutta, Soso, Martinville
and later, Heidelberg Fields. With the properties acquired in our January 2006 acquisition, we
have labeled the planned operations at Tinsley Field, Northwest of Jackson Dome, as Phase III.
Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi/ Louisiana
border acquired in 2005 and which are located west of the Phase I fields. Phase V is Delhi Field,
a Louisiana field we acquired in May 2006. We also plan to ultimately flood Citronelle Field,
another field acquired in 2006, and Hastings Field, a field on which we recently acquired a
purchase option. We have not yet labeled these two fields as a specific phase.
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Denbury Resources Inc.
Jackson Dome. 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 provided the platform to significantly expand our
CO2 tertiary recovery operations by assuring 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 additional wells and drilled 11 additional CO2 producing wells,
significantly increasing our estimated proved CO2 reserves to approximately 5.5 Tcf as
of December 31, 2006, which is more than enough for our existing and currently planned phases of
operations. The estimate of 5.5 Tcf of proved CO2 reserves is based on 100% ownership
of the CO2 reserves, of which Denburys net ownership (net revenue interest) is
approximately 4.5 Tcf and is included in the evaluation of proven CO2 reserves prepared
by DeGolyer & MacNaughton. In discussing our available CO2 reserves, we make reference
to the gross amount of proved reserves, as this is the amount that is available both for Denburys
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 uses. 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 additional CO2 deliverability, we plan to drill several additional
CO2 wells in the future, including up to three additional wells during 2007.
During the fourth quarter of 2006, we produced an average of 394 MMcf/d of CO2. We
sold an average of 78 MMcf/d of CO2 to commercial users and we used an average of 316
MMcf/d for our tertiary activities. We estimate that our current daily CO2
deliverability is around 470 MMcf/d. By year-end 2007, we estimate that our planned tertiary
operations will require between 650 and 700 MMcf/d, but with our planned 2007 Jackson Dome
projects, we expect to increase our CO2 deliverability to between 700 MMcf/d and 800
MMcf/d by that time. Our geoscientists are using a 100 square mile 3-D seismic survey to locate
additional structures that are expected to contain CO2. We plan to continue our
CO2 drilling activity in 2007 and beyond, as our CO2 deliverability needs
will continue to grow as we expand our planned tertiary projects.
Man-made CO2 sources. We entered into an agreement and committed to purchase (if
the plant is built) 100% of the CO2 production from a man-made (anthropogenic) source of
CO2, a planned petroleum coke gasification project scheduled to be completed
in 2010. This Faustina plant, proposed to be located near Donaldsonville, Louisiana, will convert
petroleum coke into ammonia. As a byproduct of the combustion, large quantities of CO2
will be produced, estimated to be around 200 MMcf/d. We plan to use this CO2 in our
tertiary operations to recover oil that may otherwise not be produced. In addition, our use of
this CO2 will also eliminate the release of this greenhouse gas into the earths
atmosphere. The Faustina agreement allows us to add the potential equivalent volume of an
additional one Tcf of CO2 over the term of our contract. Construction of this plant has
not yet begun, so we are not certain whether this plant will be built, although it appears likely.
We are in discussions with several other entities that are considering other types of coal or
petroleum coke gasification plants. These plants may convert petroleum coke or coal into a variety
of products including ammonia, methanol, synthetic diesel fuel, or electrical power generation.
The cost of this man-made CO2 will likely be higher than CO2 from our natural
source, but the location of these plants could mitigate some of the incremental cost of
transportation. Further, we see these sources as a possible expansion of our natural Jackson Dome
source, assuming they are economical, and we believe that our potential ability to tie these
sources together with pipelines will give us a significant advantage over our competitors in our
geographic area in acquiring additional oil fields and future potential man-made
sources of CO2.
CO2 pipelines. We acquired the NEJD 183-mile CO2 pipeline that runs
from Jackson Dome to near Donaldsville, Louisiana as part of the 2001 acquisition (see above).
During the first quarter of 2006, we completed the 20, 86-mile Free State Pipeline, which we are
initially using to transport CO2 to our three new Phase II fields in East Mississippi
(Eucutta, Soso, and Martinville). Completion of this line was a significant accomplishment for our
team and expands our CO2 tertiary recovery technology to many potentially significant
reservoirs in the eastern part of the state.
During 2006, we reached agreement with Southern Natural Gas Company to acquire a natural gas
pipeline that runs from Gwinville Field to near Lake St. John Field in Louisiana. This pipeline
crosses our existing NEJD 20 CO2 pipeline in Southwest Mississippi, and once converted
to CO2 service, will allow us to transport CO2 from the NEJD pipeline to Lake
St. John and Cranfield Fields, both acquired in 2005 (our planned Phase IV). We are in the process
of building a small replacement natural gas pipeline to service certain communities currently
supplied by
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Denbury Resources Inc.
the acquired line, after which we can convert the acquired natural gas line to CO2
service. We expect to have this completed by the fourth quarter of 2007.
The 2006 acquisition of Tinsley Field included an eight-inch pipeline, previously being used
for natural gas sales and storage, from our Jackson Dome area to the field. We converted the
natural gas line to a CO2 pipeline and in early 2007 began using it to transport
CO2 to Tinsley Field, albeit in limited volumes. During 2007, we plan to construct a
24, 31 mile line from Jackson Dome to Tinsley Field, with completion anticipated in the third
or fourth quarter of 2007. We plan to further extend this line by building a 68 mile 20 extension from
Tinsley Field to Delhi Field with completion for this segment anticipated during the first half of
2008.
In late 2006, we purchased an option to acquire Hasting Field, a potential tertiary flood
located near Houston, Texas. We plan to build a pipeline to transport CO2 to this field
from the southern end of our existing CO2 pipeline that terminates near Donaldsonville,
Louisiana, estimated at between 280 and 300 miles. Based on very preliminary estimates, this
pipeline is expected to cost between $450 million and $650 million, although this cost could vary
significantly depending on the ultimate size of the pipeline, its pressure rating, its specific
route, and other variables, all of which are unknown at this time. We are initiating studies
related to construction of this line, with a goal of having it installed and operational during
2009. We anticipate initially transporting CO2 from our natural source at Jackson Dome,
but ultimately plan to use man-made (anthropogenic) sources of CO2 for this tertiary
operation.
Overall economics. Initially, our tertiary operations were economic at oil prices below $20
per Bbl, although the economics have always varied by field. Our costs have escalated during the
last few years due to general cost inflation in the industry, raising our current economic oil
price to around $30 per Bbl, again dependent on the specific field. Our inception to date finding
and development costs (including future development and abandonment costs but excluding
expenditures on fields without proven reserves) for our tertiary oil fields through December 31,
2006, was approximately $8.50 per BOE. Currently, we forecast that these costs will range from $5
to $10 per BOE over the life of each field, depending on the state of a particular field at the
time we begin operations, the amount of potential oil, the proximity to a pipeline or other
facilities, etc. Our operating costs for tertiary operations are expected to range from $13 to $15
per BOE over the life of each field (at todays prices), again depending on the field itself.
Oil quality is another significant factor that impacts the economics. In Phase I (Southwest
Mississippi), the light sweet oil produced from our tertiary operations receives near NYMEX prices,
while the average discount to NYMEX for the lower quality oil produced from the fields in Phase II
(East Mississippi), some of which we started flooding during 2006, was $13.51 per BOE during 2006,
a differential that is significantly higher than our historical corporate averages and one that
appears to increase as oil prices increase.
While these economic factors have wide ranges, our rate of return from these operations has
generally been better than the rate of return on our traditional oil and gas operations and entail
less risk, and thus our tertiary operations have become our single most important focus area.
While it is extremely difficult to accurately forecast future production, we do believe that our
tertiary recovery operations provide significant long-term production and reserve growth potential
at reasonable rates of return, with relatively low risk, and thus will be the backbone of our
Companys growth for the foreseeable future. Although we believe that our plans and projections are
reasonable and achievable, there could be delays or unforeseen problems in the future that could
delay or affect the economics of our overall tertiary development program. We believe that such
delays or price effects, if any, should only be temporary.
Tentatively, we plan to spend approximately $70 million in 2007 in the Jackson Dome area with
the intent to add additional CO2 reserves and deliverability for future operations.
Approximately $60 million in capital expenditures is budgeted in 2007 for our Phase II properties
(East Mississippi) and approximately $200 million for Phase III properties (Tinsley), plus an
additional $70 million for properties in other phases, making our combined CO2 related
expenditures just over 60% of our $650 million 2007 capital budget.
Our Tertiary Oil Fields with Proven Tertiary Reserves
At December 31, 2006, we had total tertiary-related proved oil reserves of approximately 62.2
MMBbls, consisting of 3.7 MMBbls at Little Creek Field (and surrounding smaller fields), 13.6
MMBbls at Mallalieu Field, 12.7 MMBbls at McComb Field, 19.0 MMBbls at Brookhaven Field, 2.7 MMBbls
at Smithdale Field, 10.3 MMBbls at Eucutta Field and 0.2 MMBbls at Martinville Field. Overall, our
production from tertiary operations has
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Denbury Resources Inc.
increased from approximately 1,350 Bbls/d in 1999, the then existing production at Little
Creek Field at the time of acquisition, to an average of 10,028 Bbls/d during the fourth quarter of
2006. We expect this production to continue to increase for several years as we expand our
tertiary operations to additional fields.
With regard to our proven tertiary reserves, 2006 was a transition year for us, as we added
only 6.0 MMBbls of tertiary-related proved oil reserves during the year, primarily incremental oil
reserves at McComb and Mallalieu Fields (both Phase I). Previously, we booked most proven tertiary
oil reserves near the start of a project as almost all the oil fields in Phase I were analogous to
Little Creek Field (our first flood) and thus it was not necessary to have an oil production
response to the CO2 injections before they were considered proven. Conversely, our new
floods (after Phase I) are not analogous (for the most part), as the tertiary floods will be in
different geological formations. Therefore, for these new phases, there must be an oil production
response to the CO2 injections before we can recognize proven oil reserves, even though
we believe that these formations have a similar risk profile. Since many of our Phase II projects
were delayed during 2006, the production response needed to record any significant incremental
tertiary oil reserves in this new area was delayed. We anticipate booking significant amounts of
proven tertiary oil reserves during 2007 and beyond, although the magnitude will depend on our
progress with Phases III and IV, two areas we plan to initiate development of during 2007, and the
response from our new Phase II projects.
Mallalieu Field. The Mallalieu Field consists of two fields, West Mallalieu and the smaller
East Mallalieu fields. Combined they are our most prolific tertiary flood, producing in excess of
4,994 Bbls/d for the fourth quarter 2006. In contrast to many of our existing fields, West
Mallalieu Field was not waterflooded prior to CO2 injection. Therefore, we believe that
the tertiary recovery of oil from West Mallalieu Field as a result of CO2 injection
could approach 25% of the original oil in place. During 2006, we increased our proved reserves in
this area, raising our estimated recovery factor from 17% to 20% for these fields, based on
production performance to date. A total of $27.6 million was invested in this field during 2006 to
drill, re-enter or recomplete wells in efforts to improve production. During 2007, we plan to
expand the Mallalieu production facilities to accommodate the expected production growth.
Reservoir modeling indicates the field may be producing in excess of 6,500 Bbls/d by the fourth
quarter of 2007.
From inception through December 31, 2006, we had net positive cash flow (revenue less
operating expenses and capital expenditures) from Mallalieu Field of $139.3 million, plus the
fields have a PV-10 Value of $457.2 million, using December 31, 2006, NYMEX pricing of $61.05 per
barrel.
McComb and Smithdale Fields. We commenced tertiary recovery operations in 2003 at McComb
Field and started injecting CO2 late that year. Significant development occurred during
2004 and 2005 as we expanded the nearby Olive Field CO2 facility to handle the
processing of McCombs produced oil, water and CO2 and developed an additional four
injection patterns. The first production response occurred in the second quarter of 2004 and has
gradually increased since that time, averaging 1,463 Bbls/d in the fourth quarter of 2006. During
2006, we continued the expansion of our operations within McComb Field and further expanded the
production facilities. Although we have encountered injection issues during 2006, which limited
our CO2 injections at McComb, by the second quarter of 2007 we expect to have all the
necessary equipment installed, which we believe will eliminate the injection issues. In addition,
we are injecting CO2 at the nearby, much smaller, Smithdale Field utilizing the same
CO2 facilities. We started injecting CO2 at Smithdale in the second quarter
of 2005, although our production through December 31, 2006 has generally been less than 100
Bbls/day.
From inception through December 31, 2006, we had not yet recovered our costs in these fields
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition costs) from these fields of $91.2 million, although the fields have a PV-10 Value
of $370.7 million, using December 31, 2006, NYMEX pricing.
Brookhaven Field. Our first tertiary CO2 production response at Brookhaven Field
occurred during the fourth quarter of 2005, with oil production rates averaging 125 Bbls/d during
the fourth quarter of 2005. Production rates continued to increase throughout 2006 as additional
patterns were developed. Production during the fourth quarter of 2006 increased only slightly from
third quarter 2006 rates, as CO2 injection rates were less than initially planned.
Incremental work on CO2 injection wells was required to improve injection rates and to
ensure the CO2 was entering the proper intervals. Additional injection pumps were
installed on certain wells to increase injection rates. Oil production during the fourth quarter
of 2006 averaged 1,014 Bbls/d.
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Denbury Resources Inc.
From inception through December 31, 2006, we had not yet recovered our costs in this field
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition cost) from Brookhaven of $50.9 million, although the field has a PV-10 Value of
$353.4 million attributed to the tertiary recovery reserves, using December 31, 2006, NYMEX pricing.
Little Creek Field. During the fourth quarter of 2006, production averaged 2,279 Bbls/d
(including Lazy Creek). Production at Little Creek Field began declining in 2006 and is expected to
continue to decline over the next several years. We are working to mitigate production declines by
monitoring injection patterns, reworking producing wells and using injection surveys to control at
which intervals the CO2 is injected. From inception through December 31, 2006, we had
net positive cash flow (revenue less operating expenses and capital expenditures, including the
acquisition cost) from Little Creek (including adjoining smaller fields) of $127.2 million, plus
the fields have a PV-10 Value of $90.6 million, using December 31, 2006, NYMEX pricing.
Eucutta Field. Eucutta Field is the only field in East Mississippi (Phase II) that currently
has significant proven tertiary oil reserves. This field is analogous to Heidelberg Field in that
the majority of its historical production was produced from the Eutaw formation. The Eutaw
formation at Eucutta was unitized for water flooding in 1966 and has gone through several stages of
development. During the 1980s, Amerada Hess installed an inverted 5-spot injection pilot in the
First City Bank sand (one of the Eutaw sands) to test the application of CO2 flooding.
Although the pilot test only covered approximately 20 acres, the pilot was successful in recovering
an additional 17% of the original oil in place within the pattern. Based on this success, we
designed and constructed a CO2 flood and facility for the Eucutta Field. Initial well
work was completed and CO2 injection started during the first quarter of 2006, with the
first minor tertiary oil production during the fourth quarter of 2006. Our plans for 2007 include
the development of the remaining patterns and expansion of our CO2 facilities. At
December 31, 2006 we had 10.3 MMBbls of proved reserves in the Eucutta field attributable to the
CO2 flood. The proved reserve estimate is based on a 13% recovery factor, lower than
was achieved in the pilot program in the 1980s, and therefore we expect to have upward reserve
increases in the future.
Martinville Field. We initiated our first injections of CO2 in Martinville Field
during the first quarter of 2006 in both the Rodessa and Mooringsport formations. As is the case
with most of the East Mississippi fields, Martinville produces from multiple reservoirs. Unlike
the majority of our other planned CO2 projects, Martinville does not contain a single
large reservoir to CO2 flood, but rather several smaller reservoirs. We completed
construction of the CO2 facilities and essentially completed the development of the
Mooringsport sand during 2006. During the fourth quarter of 2006, the first well responded,
although the average rate for the quarter was only 24 Bbls/d. The tertiary oil rate has increased
to approximately 400 Bbls/d during the month of January 2007. The second reservoir, the Rodessa,
although smaller in size, has similar reservoir characteristics to the Mooringsport. We initiated
injection into the Rodessa with three injection wells during 2006. We have not seen CO2
response to date from the Rodessa.
The Wash Fred 8500 reservoir in the Martinville Field contains a low oil gravity (thick oil),
15 API, which will not develop miscibility with 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 oil gravities and strong water drives, which do not sweep the oil
efficiently. We initiated CO2 injection during the first quarter of 2006 at the crest
of the structure. Although we will not achieve miscibility, the injection of CO2 is
expected to swell the oil, decrease the oil viscosity, and displace the water and oil downward in
the reservoir to the adjacent producing wells and result in incremental oil production. Well bore
issues delayed the implementation of this flood during 2006, but we are currently injecting
CO2 and observing the production from offset wells to determine what effect the
CO2 will have on oil and water production. The success of this flood would provide the
impetus to look at a whole new array of fields that have historically not been considered for
CO2 injection, although there can be no assurance that this technique will be successful
or economic.
Our Tertiary Oil Fields without Proven Tertiary Reserves
During 2007, we plan to commence tertiary operations at a small field, Lockhart Crossing
(Phase I), our first Louisiana flood, and Cranfield Field in West Mississippi (Phase IV), and
install the pipeline necessary to deliver CO2 to Delhi Field (Phase V) so that injection
can begin there in 2008. We initiated CO2 injections at Tinsley Field (Phase III) in
January 2007, although in very limited amounts, with more significant development expected there
when the larger, replacement CO2 pipeline to Tinsley is completed, which we anticipate
will be in the fourth quarter of 2007.
9
Denbury Resources Inc.
Soso Field. Soso Field, near Laurel, Mississippi, produced from numerous reservoirs during
primary production including the Rodessa, Bailey and Cotton Valley sands, all of which we plan to
CO2 flood. The Bailey sand exhibits comparable reservoir characteristics to our West
Mississippi floods and we expect the Bailey tertiary flood to perform in a similar manner. We
elected to co-develop the Bailey sand and Rodessa sand to accelerate the development of the
potential tertiary oil reserves at Soso. Although we began initial development of the Bailey sand
very late in 2005, the majority of our capital investment to date occurred in 2006, which involved
the construction of CO2 facilities and the establishment of the two tertiary injection
projects. During the first quarter 2006, we initiated our first injections of CO2 into
five Bailey injection wells and initiated injection in the Rodessa during the second quarter of
2006, although injections in the Bailey formation were initially limited because of delays in
getting the well work done and limited CO2 supplies. We expect to see our first
tertiary production in Soso Field during the second quarter of 2007.
Tinsley Field. Tinsley field was acquired in January 2006 and is one of the largest oil
fields in the state of Mississippi. As is the case with the majority of fields in Mississippi,
Tinsley produces from multiple reservoirs. While we are working the other reservoirs in an attempt
to increase current conventional production and reserves, our primary target in Tinsley for
CO2 enhanced oil recovery operations is the Woodruff formation. One of the prior
operators performed a pilot CO2 project at Tinsley in the Perry sandstone. The
CO2 was successful at mobilizing oil but the operator decided not to expand the flood
due to low oil prices. The acquisition of the field included an 8 pipeline that was installed to
deliver CO2 to the pilot project but was converted to natural gas service some time ago.
We have reconditioned the pipeline for CO2 service and initiated limited CO2
injection in Tinsley Field in January 2007. In order to expand our injection of CO2 to
the entire field, it will be necessary to install a new CO2 pipeline, which we expect
will be completed by the third or fourth quarter of 2007.
Delhi Field. During May 2006, we purchased the Delhi Holt-Bryant Unit (Delhi) in Northern
Louisiana for $50 million, plus a 25% reversionary interest to the seller after we achieve $200
million in net operating revenue, as defined. Delhi is also a future potential CO2
tertiary oil flood candidate that will require construction of a CO2 pipeline before
flooding can commence, with current plans to make such a line an extension of the larger, new
CO2 pipeline currently planned from Jackson Dome to Tinsley Field. Our goal is to have
this CO2 pipeline installed by 2008, with initial oil production from tertiary
operations currently anticipated during 2009. As of December 31, 2006, there was not any
significant oil production or proved oil reserves at Delhi Field.
Hastings Field. During November 2006, we entered into an agreement with a subsidiary of
Venoco, Inc. that gives us an option, between November
1, 2008 and November 1, 2009, to purchase their interest in Hastings Field a strategically significant potential tertiary flood candidate
located near Houston, Texas. The agreement provides for the parties to agree upon a purchase price
for the conventional proved reserves at the time of the exercise of the option, which may be paid
in cash or through a volumetric production payment; failing agreement as to price, the price will
be determined by a pre-designated independent petroleum engineering firm using specified criteria
for calculation of the discounted present value of proved reserves at that time. As consideration
for the option agreement, we made an upfront payment of $37.5 million and are required to make
additional payments totaling $12.5 million over the next 20 months. We can extend the option
period beyond November 2009 for up to seven additional years at an incremental cost of $30 million
per year. None of the option payment amounts will be credited against the purchase price if we
exercise the option. If we exercise the option, we will be committed to make aggregate net capital
expenditures in the field of approximately $175 million over the subsequent five years to develop
the field for tertiary operations, with an obligation to commence CO2 injections in the
field within three years following the option exercise. Hastings Field is currently producing
approximately 2,400 Bbls/d, although we currently have no economic
interest in this production.
Based on preliminary engineering data, the West Hastings Unit (the most likely area to be
initially developed as a tertiary flood) has significant net reserve potential from CO2
tertiary floods, more reserve potential than any other single field in our inventory. We plan to
build a pipeline to transport CO2 to this field (see CO2 pipelines above).
Based on preliminary estimates, it will cost between
$400 million and $600 million to develop the
West Hastings Unit as a tertiary flood, excluding the cost of the CO2 pipeline.
The Hasting Field agreement provides for a significant strategic addition, giving us an anchor
field to the Texas Gulf Coast region. The field and the CO2 pipeline will significantly
expand our area of operations and growth opportunities into the Texas Gulf Coast region. Denbury
continues to evaluate fields in the area to add to a reserve base in the Texas Gulf Coast area.
10
Denbury Resources Inc.
Overall Tertiary Economics to Date. Through December 31, 2006, we spent a total of $665.4
million on tertiary oil fields (including the allocated acquisition costs), and received $472.2
million in net positive cash flow (revenue less operating expenses), or net unrecovered cash flow
of $193.2 million, the deficit primarily due to the significant funds expended on acquisitions
during 2006. Of our total spending, approximately $273.5 million was spent on fields that had little or no proved reserves at December 31, 2006 (i.e. significant
incremental proved reserves are anticipated during 2007 and beyond). These amounts do not include the capital costs or related depreciation and
amortization of our CO2 producing properties at Jackson Dome, which had an unrecovered net cash flow of $198.7 million as of December 31, 2006, including $54.6 million
associated with the Free State CO2 pipeline. At year-end 2006, the proved oil reserves
in our tertiary recovery oil fields had a PV-10 Value of $1.46 billion, using December 31, 2006,
NYMEX pricing of $61.05 per barrel. In addition, there is significant probable and potential
reserves at several other fields for which tertiary operations are underway or planned.
Texas and the Barnett Shale
We currently own approximately 74,700 gross acres and 53,800 net acres of leases in the
Barnett Shale area in North Central Texas, of which approximately 22,100 gross acres and 19,600 net
acres are in the more tested northern areas of Parker and Wise Counties, with the remainder in
Erath and adjoining more southern and untested counties. We acquired our initial acreage in this
area in 2001 and did only limited development until 2005. Through December 31, 2006, we have spent a total of $267.2 million on the Barnett Shale
area and have received $90.1 million in net operating income (revenue less operating expenses),
or net negative cash flow of $177.1 million. At December 31, 2006, we had
approximately 252.4 Bcfe of proved reserves in the Barnett Shale area with a PV-10 Value of
approximately $243.5 million, using December 31, 2006, Henry Hub indicative cash pricing of $5.63
per MMBtu.
We continue to refine our completion and fracturing techniques, including an analysis of the
best number of fracture treatments to adequately stimulate the entire length of the lateral
sections of our horizontal wells, which can exceed 4,000 feet. During 2006, we drilled an additional 46 horizontal wells, increasing our net Barnett Shale production from
approximately 18.3 MMcfe/d in the fourth quarter of 2005 to approximately 35.4 MMcfe/d during the
fourth quarter of 2006. During 2006, we finalized the acquisition and interpretation of our 3-D
seismic data over our entire northern acreage position, 90 to 100 square miles, and initiated a 3-D
shoot of the southern acreage. The 3-D seismic data helps us better locate our wells so that we
encounter less faulting and underground sink holes, which have been associated with fracture
stimulations into zones outside of the Barnett Shale that are typically water bearing. We expect
production in this area to grow significantly during 2007 as we plan to drill approximately 35 to
40 horizontal wells, all of which are scheduled for Parker County. Including seismic costs and
pipeline infrastructure costs, our planned 2007 capital expenditures in the Barnett Shale area are
estimated to make up $122 million of our current $650 million capital budget.
At this time we are still evaluating the 2006 drilling and completion work in our southern
acreage, primarily Erath County. The initial results do not look very encouraging as we drilled
five wells, completing three, none of which have been economic. We elected not to complete the
last two wells pending a re-analysis of all of our results to date.
East Mississippi Fields Without Proven Tertiary Oil Reserves
We have been active in East Mississippi since Denbury was founded in 1990 and are by far the
largest oil producer in the basin. For years, this has been our area with the highest production
and most proved reserves, representing production of approximately 12,808 BOE/d during the fourth
quarter of 2006 (35% of our Company total) and proved reserves of 52.7 MMBOE as of December 31,
2006 (30% of our Company total). Since we have generally owned these Eastern Mississippi
properties longer than properties in our other regions, they tend to be more fully developed, and
although most are targeted for tertiary operations in the future, only three currently have
tertiary operations (Soso, Martinville and Eucutta Fields). Production from our East Mississippi
fields has been relatively consistent over the last three years, averaging 13,085 BOE/d in 2004,
12,072 BOE/d in 2005 and 12,743 BOE/d during 2006. For 2007, we expect our budget in this region
for conventional operations to be around $50 million, about the same as in 2006, representing
approximately 8% of our current 2006 exploration and development budget of $650 million.
Heidelberg Field. The largest field in the region and one of our largest fields corporately is
Heidelberg Field, which for the fourth quarter of 2006 produced an average of 7,444 BOE/d, 2% more
than the 2005 average of 7,312 BOE/d. Heidelberg Field was acquired from Chevron in December 1997.
The field is a large salt-cored anticline that is divided into western and eastern segments due to
subsequent faulting. There are 11 producing formations in
11
Denbury Resources Inc.
Heidelberg Field containing 40 individual reservoirs, with the majority of the past and
current production coming from the Eutaw, Selma Chalk and Christmas sands at depths of 3,500 to
5,000 feet. When we acquired the property in 1997, production was approximately 2,800 BOE/d.
The
majority of the oil production at Heidelberg is from six waterflood units that produce
from the Eutaw formation (at approximately 4,400 feet). Most of our recent development at
Heidelberg has been in the Selma Chalk, a natural gas reservoir at around 3,700 feet, making
Heidelberg our second largest gas field. We have steadily developed the Selma Chalk since 2001,
drilling from 13 to 20 wells per year, increasing the natural gas production at Heidelberg to a
peak quarterly average of 15.8 MMcf/d in the fourth quarter of 2004, averaging 14.3 MMcf/d during
2006. During 2005 we drilled and completed our first horizontal well in the Selma Chalk. The well
was drilled in an area of the field where prior vertical wells
typically yielded lower than
average production rates. The well was completed in two stages and the results were encouraging.
During 2006, we drilled 12 Selma Chalk wells, four of which were horizontal wells, and we plan to
drill 13 horizontal wells during 2007.
South Louisiana
We own interests in the land and marshes of south Louisiana, a region that produces primarily
natural gas. Production from this area averaged 39.4 MMcfe/d net to our interest in the
fourth quarter of 2006, a slight increase from our 2005 average of 37.0 MMcfe/d. Production
was as high as 51.7 MMcfe/d during the second quarter of 2006 following the completion of several
new wells drilled in late 2005 and early 2006, but has declined significantly from that peak as a
result of the relatively rapid depletion for wells in this area. During 2006, we spent
approximately $64.7 million (excluding acquisitions) in this region, approximately 13% of our total
exploration and development expenditures, drilling approximately 12 wells, primarily in Cameron,
Jefferson Davis, and Terrebonne Parish areas. For 2007, our spending is expected to be
approximately $40 million or 6% of our currently planned $650 million exploration and development
budget, significantly less than our 2006 expenditures in this area.
The majority of our onshore Louisiana fields lie in the Houma embayment area of Terrebonne
Parish, including Lirette and South Chauvin Fields, and our recent shallow natural gas plays at
Bayou Sauveur and Gibson Fields. We drilled four wells in Terrebonne Parish during 2006. In 2007,
we plan to drill approximately three exploratory wells in Terrebonne Parish and four development
wells.
In late 2005 we spudded our Gumbo Prospect in Terrebonne Parish, the Westerfelt #2 well, a
19,000+ foot well testing the Rob L sands. We logged the well in January 2006, constructed
production facilities and completed the well. The well produced approximately 645 MMcf and 26
MBbls of condensate (gross) during a two month period. In October 2006 the well logged-off and is
presently being evaluated for sidetracking to another fault block. Based on the Westerfelt #2
production information and pressures, we believe that the Westerfelt #2 encountered an isolated
reservoir area that is not in communication with the large feature it was intended to test. Based
upon the results of the Westerfelt #2 and review of the seismic interpretation, we decided to drill
an offset, the State Lease 18380 #1 well. We believe that this well should encounter a larger
reservoir with greater reserve potential. The completion of drilling operations is expected late
in the first quarter or early in the second quarter of 2007. Assuming the well logs are favorable,
significant production history will be required to fully evaluate the potential reserves associated
with this prospect.
12
Denbury Resources Inc.
Field Summaries
Denbury operates in four primary areas: Louisiana, Eastern Mississippi, Western Mississippi
and Texas. Our 16 largest fields (listed below) constitute approximately 93% of our total proved
reserves on a BOE basis and on a PV-10 Value basis. Within these 16 fields, we own a weighted
average 92% working interest and operate all of these fields. The concentration of value in a
relatively small number of fields allows us to benefit substantially from any operating cost
reductions or production enhancements we achieve and allows us to effectively manage the properties
from our five primary field offices located in Houma, Louisiana, Laurel, Mississippi; McComb,
Mississippi; Brandon; Mississippi; and Cleburne, Texas.
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves as of December 31, 2006 (1) |
|
|
2006 Average Daily Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
Average Net |
|
|
|
Oil |
|
|
Natural Gas |
|
|
|
|
|
|
BOE |
|
|
PV-10 Value |
|
|
Oil |
|
|
Gas |
|
|
Revenue |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
|
MBOEs |
|
|
% of total |
|
|
(000's) |
|
|
(Bbls/d) |
|
|
(Mcf/d) |
|
|
Interest |
|
|
Mississippi
CO2 floods |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
18,987 |
|
|
|
|
|
|
|
18,987 |
|
|
|
10.9 |
% |
|
$ |
353,406 |
|
|
|
833 |
|
|
|
|
|
|
|
82.0 |
% |
Mallalieu (East & West) |
|
|
13,582 |
|
|
|
|
|
|
|
13,582 |
|
|
|
7.8 |
% |
|
|
457,200 |
|
|
|
5,210 |
|
|
|
|
|
|
|
76.6 |
% |
McComb/Olive |
|
|
12,717 |
|
|
|
|
|
|
|
12,717 |
|
|
|
7.3 |
% |
|
|
297,449 |
|
|
|
1,177 |
|
|
|
|
|
|
|
77.0 |
% |
Eucutta |
|
|
10,313 |
|
|
|
|
|
|
|
10,313 |
|
|
|
5.9 |
% |
|
|
186,229 |
|
|
|
47 |
|
|
|
|
|
|
|
83.5 |
% |
Little Creek & Lazy Creek |
|
|
3,696 |
|
|
|
|
|
|
|
3,696 |
|
|
|
2.1 |
% |
|
|
90,592 |
|
|
|
2,739 |
|
|
|
|
|
|
|
83.3 |
% |
Smithdale and other |
|
|
2,872 |
|
|
|
|
|
|
|
2,872 |
|
|
|
1.7 |
% |
|
|
71,560 |
|
|
|
64 |
|
|
|
|
|
|
|
79.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Mississippi CO2 floods |
|
|
62,167 |
|
|
|
|
|
|
|
62,167 |
|
|
|
35.7 |
% |
|
|
1,456,436 |
|
|
|
10,070 |
|
|
|
|
|
|
|
79.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Mississippi |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heidelberg (East & West) |
|
|
25,943 |
|
|
|
51,512 |
|
|
|
34,528 |
|
|
|
19.8 |
% |
|
|
477,186 |
|
|
|
5,036 |
|
|
|
14,330 |
|
|
|
76.2 |
% |
Tinsley |
|
|
3,299 |
|
|
|
90 |
|
|
|
3,314 |
|
|
|
1.9 |
% |
|
|
60,391 |
|
|
|
881 |
|
|
|
10 |
|
|
|
81.7 |
% |
Eucutta |
|
|
2,708 |
|
|
|
|
|
|
|
2,708 |
|
|
|
1.6 |
% |
|
|
35,524 |
|
|
|
819 |
|
|
|
40 |
|
|
|
69.4 |
% |
S. Cypress Creek |
|
|
1,903 |
|
|
|
102 |
|
|
|
1,920 |
|
|
|
1.1 |
% |
|
|
26,041 |
|
|
|
233 |
|
|
|
41 |
|
|
|
83.0 |
% |
Summerland |
|
|
1,662 |
|
|
|
|
|
|
|
1,662 |
|
|
|
0.9 |
% |
|
|
20,556 |
|
|
|
445 |
|
|
|
|
|
|
|
74.4 |
% |
King Bee |
|
|
1,458 |
|
|
|
|
|
|
|
1,458 |
|
|
|
0.8 |
% |
|
|
17,316 |
|
|
|
269 |
|
|
|
|
|
|
|
78.9 |
% |
Other Mississippi |
|
|
5,172 |
|
|
|
11,694 |
|
|
|
7,121 |
|
|
|
4.1 |
% |
|
|
118,821 |
|
|
|
1,887 |
|
|
|
4,618 |
|
|
|
33.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Mississippi |
|
|
42,145 |
|
|
|
63,398 |
|
|
|
52,711 |
|
|
|
30.2 |
% |
|
|
755,835 |
|
|
|
9,570 |
|
|
|
19,039 |
|
|
|
64.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S. Chauvin |
|
|
436 |
|
|
|
13,940 |
|
|
|
2,759 |
|
|
|
1.6 |
% |
|
|
57,189 |
|
|
|
298 |
|
|
|
11,744 |
|
|
|
38.3 |
% |
Thornwell |
|
|
406 |
|
|
|
5,876 |
|
|
|
1,385 |
|
|
|
0.8 |
% |
|
|
33,905 |
|
|
|
1,068 |
|
|
|
11,147 |
|
|
|
37.4 |
% |
Other Louisiana |
|
|
901 |
|
|
|
20,076 |
|
|
|
4,248 |
|
|
|
2.4 |
% |
|
|
75,305 |
|
|
|
789 |
|
|
|
11,800 |
|
|
|
41.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Louisiana |
|
|
1,743 |
|
|
|
39,892 |
|
|
|
8,392 |
|
|
|
4.8 |
% |
|
|
166,399 |
|
|
|
2,155 |
|
|
|
34,691 |
|
|
|
39.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Newark (Barnett Shale) |
|
|
11,606 |
|
|
|
182,812 |
|
|
|
42,075 |
|
|
|
24.1 |
% |
|
|
243,474 |
|
|
|
106 |
|
|
|
28,525 |
|
|
|
75.0 |
% |
Other Texas |
|
|
179 |
|
|
|
669 |
|
|
|
290 |
|
|
|
0.2 |
% |
|
|
1,552 |
|
|
|
8 |
|
|
|
|
|
|
|
79.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Texas |
|
|
11,785 |
|
|
|
183,481 |
|
|
|
42,365 |
|
|
|
24.3 |
% |
|
|
245,026 |
|
|
|
114 |
|
|
|
28,525 |
|
|
|
75.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Citronelle |
|
|
8,283 |
|
|
|
|
|
|
|
8,283 |
|
|
|
4.8 |
% |
|
|
67,594 |
|
|
|
1,026 |
|
|
|
|
|
|
|
62.7 |
% |
Other Alabama |
|
|
7 |
|
|
|
1,978 |
|
|
|
337 |
|
|
|
0.2 |
% |
|
|
3,165 |
|
|
|
1 |
|
|
|
727 |
|
|
|
30.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Alabama |
|
|
8,290 |
|
|
|
1,978 |
|
|
|
8,620 |
|
|
|
5.0 |
% |
|
|
70,759 |
|
|
|
1,027 |
|
|
|
727 |
|
|
|
60.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
55 |
|
|
|
77 |
|
|
|
67 |
|
|
|
0.0 |
% |
|
|
744 |
|
|
|
|
|
|
|
93 |
|
|
|
0.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company Total |
|
|
126,185 |
|
|
|
288,826 |
|
|
|
174,322 |
|
|
|
100.0 |
% |
|
$ |
2,695,199 |
|
|
|
22,936 |
|
|
|
83,075 |
|
|
|
57.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The reserves were prepared using constant prices and costs in accordance with the guidelines of
the SEC based on the prices received on a field-by-field basis as of December 31, 2006. The prices
at that date were a NYMEX oil price of $61.05 per Bbl adjusted to prices received by field and a
Henry Hub natural gas price average of $5.63 per MMBtu also adjusted to prices received by field. |
13
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 Denburys 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 Denburys acreage position at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Mississippi |
|
|
107,930 |
|
|
|
86,143 |
|
|
|
276,809 |
|
|
|
54,303 |
|
|
|
384,739 |
|
|
|
140,446 |
|
Louisiana |
|
|
56,393 |
|
|
|
49,126 |
|
|
|
21,517 |
|
|
|
15,002 |
|
|
|
77,910 |
|
|
|
64,128 |
|
Texas |
|
|
20,256 |
|
|
|
18,119 |
|
|
|
56,454 |
|
|
|
37,487 |
|
|
|
76,710 |
|
|
|
55,606 |
|
Alabama |
|
|
34,329 |
|
|
|
21,919 |
|
|
|
77,524 |
|
|
|
18,887 |
|
|
|
111,853 |
|
|
|
40,806 |
|
Other |
|
|
5,429 |
|
|
|
1,503 |
|
|
|
38,710 |
|
|
|
9,687 |
|
|
|
44,139 |
|
|
|
11,190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
224,337 |
|
|
|
176,810 |
|
|
|
471,014 |
|
|
|
135,366 |
|
|
|
695,351 |
|
|
|
312,176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denburys net undeveloped acreage that is subject to expiration over the next three
years, if not renewed, is approximately 7% in 2007, 8% in 2008 and 4% in 2009.
Productive Wells
The following table sets forth our gross and net productive oil and natural gas wells at
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Natural |
|
|
|
|
|
|
Producing Oil Wells |
|
|
Gas Wells |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
492 |
|
|
|
474.9 |
|
|
|
176 |
|
|
|
161.8 |
|
|
|
668 |
|
|
|
636.7 |
|
Louisiana |
|
|
30 |
|
|
|
24.7 |
|
|
|
47 |
|
|
|
39.2 |
|
|
|
77 |
|
|
|
63.9 |
|
Texas |
|
|
3 |
|
|
|
3.0 |
|
|
|
96 |
|
|
|
94.2 |
|
|
|
99 |
|
|
|
97.2 |
|
Alabama |
|
|
158 |
|
|
|
124.1 |
|
|
|
35 |
|
|
|
20.4 |
|
|
|
193 |
|
|
|
144.5 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
683 |
|
|
|
626.7 |
|
|
|
354 |
|
|
|
315.6 |
|
|
|
1,037 |
|
|
|
942.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
37 |
|
|
|
3.4 |
|
|
|
17 |
|
|
|
3.9 |
|
|
|
54 |
|
|
|
7.3 |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
3.7 |
|
|
|
17 |
|
|
|
3.7 |
|
Texas |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
0.5 |
|
|
|
4 |
|
|
|
0.5 |
|
Alabama |
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
1.5 |
|
|
|
10 |
|
|
|
1.5 |
|
Other |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
38 |
|
|
|
3.4 |
|
|
|
48 |
|
|
|
9.6 |
|
|
|
86 |
|
|
|
13.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
529 |
|
|
|
478.3 |
|
|
|
193 |
|
|
|
165.7 |
|
|
|
722 |
|
|
|
644.0 |
|
Louisiana |
|
|
30 |
|
|
|
24.7 |
|
|
|
64 |
|
|
|
42.9 |
|
|
|
94 |
|
|
|
67.6 |
|
Texas |
|
|
3 |
|
|
|
3.0 |
|
|
|
100 |
|
|
|
94.7 |
|
|
|
103 |
|
|
|
97.7 |
|
Alabama |
|
|
158 |
|
|
|
124.1 |
|
|
|
45 |
|
|
|
21.9 |
|
|
|
203 |
|
|
|
146.0 |
|
Other |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
721 |
|
|
|
630.1 |
|
|
|
402 |
|
|
|
325.2 |
|
|
|
1,123 |
|
|
|
955.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
Denbury Resources Inc.
Drilling Activity
The following table sets forth the results of our drilling activities over the last three
years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Exploratory Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
10 |
|
|
|
8.5 |
|
|
|
12 |
|
|
|
7.1 |
|
|
|
8 |
|
|
|
5.8 |
|
Non-productive(3) |
|
|
8 |
|
|
|
6.8 |
|
|
|
1 |
|
|
|
0.6 |
|
|
|
4 |
|
|
|
2.3 |
|
Development Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
90 |
|
|
|
82.7 |
|
|
|
81 |
|
|
|
74.3 |
|
|
|
68 |
|
|
|
53.8 |
|
Non-productive(3)(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
108 |
|
|
|
98.0 |
|
|
|
94 |
|
|
|
82.0 |
|
|
|
81 |
|
|
|
62.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or
gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A
developmental well is a well drilled within the presently proved productive area of an oil or
natural gas reservoir, as indicated by reasonable interpretation of available data, with the
objective of completing in that reservoir. |
|
(2) |
|
A productive well is an exploratory or development well found to be capable of producing
either oil or natural gas in sufficient quantities to justify completion as an oil or natural
gas well. |
|
(3) |
|
A nonproductive well is an exploratory or development well that is not a producing well. |
|
(4) |
|
During 2006, 2005 and 2004, an additional 14, 5, and 8 wells, respectively, were drilled for
water or CO2 injection purposes. |
Production and Unit Prices
Information regarding average production rates, unit sale prices and unit costs per BOE are
set forth under Managements Discussion and Analysis of Financial Condition and Results of
Operations Operating Income included herein.
Title to Properties
Customarily in the oil and gas industry, only a perfunctory title examination is conducted at
the time properties believed to be suitable for drilling operations are first acquired. Prior to
commencement of drilling operations, a thorough drill site title examination is normally conducted,
and curative work is performed with respect to significant defects. During acquisitions, title
reviews are performed on all properties; however, formal title opinions are obtained on only the
higher value properties. We believe that we have good title to our oil and natural gas properties,
some of which are subject to minor encumbrances, easements and restrictions.
Geographic Segments
All of our operations are in the United States.
Significant Oil and Gas Purchasers and Product Marketing
Oil and gas sales are made on a day-to-day basis under short-term contracts at the current
area market price. The loss of any single purchaser would not be expected to have a material
adverse effect upon our operations; however, the loss of a large single purchaser could potentially
reduce the competition for our oil and natural gas production, which in turn could negatively
impact the prices we receive. For the year ended December 31, 2006, we had two purchasers that
each accounted for 10% or more of our oil and natural gas revenues: Marathon Ashland
Petroleum LLC
(28%) and Hunt Crude Oil Supply Co. (18%). For the year ended December 31, 2005, three purchasers
each accounted for more than 10% of our total oil and natural gas revenues: Marathon Ashland
Petroleum LLC (28%), Hunt Crude Oil Supply Co. (20%) and Sunoco, Inc (13%). For the year ended
December 31, 2004, two purchasers each accounted for 10% or more of our oil and natural gas
revenues: Hunt Crude Oil Supply Co. (21%) and Genesis Energy, L.P. (14%).
15
Denbury Resources Inc.
Our ability to market oil and natural gas depends on many factors beyond our control,
including the extent of domestic production and imports of oil and gas, the proximity of our gas
production to pipelines, the available capacity in such pipelines, the demand for oil and natural
gas, the effects of weather, and the effects of state and federal regulation. Our production is
primarily from developed fields close to major pipelines or refineries and established
infrastructure. As a result, we have not experienced any difficulty to date in finding a market
for all of our production as it becomes available or in transporting our production to those
markets; however, there is no assurance that we will always be able to market all of our production
or obtain favorable prices.
Oil Marketing
The quality of our crude oil varies by area as well as the corresponding price received. In
Heidelberg Field, one of our larger fields, and our other Eastern Mississippi properties, our oil
production is primarily light to medium sour crude and sells at a significant discount to the NYMEX
prices. In Western Mississippi, the location of our current CO2 operations, our oil
production is primarily light sweet crude, which typically sells at near NYMEX prices, or often at
a premium. For the year ended December 31, 2006, the discount for our oil production from
Heidelberg Field averaged $13.31 per Bbl and for our Eastern Mississippi properties as a whole the
discount averaged $12.11 per Bbl relative to NYMEX oil prices. For Mallalieu Field, the largest
producer during 2006 of our CO2 properties in Western Mississippi, we averaged a premium
of $0.20 per Bbl over NYMEX oil prices, and $0.30 per Bbl over NYMEX prices for our tertiary oil
production in Western Mississippi taken as a whole. Our Louisiana properties averaged $13.82 per
Bbl below NYMEX prices during 2006, largely because the reported oil sales include a significant
amount of natural gas liquids, which typically sell at a lower price than crude oil.
Natural Gas Marketing
Virtually all of our natural gas production is close to existing pipelines and consequently we
generally have a variety of options to market our natural gas. We sell the majority of our natural
gas on one-year contracts with prices fluctuating month-to-month based on published pipeline
indices with slight premiums or discounts to the index. We receive near NYMEX or Henry Hub prices
for most of our natural gas sales due to our proximity to Henry Hub and the high Btu content of our
natural gas. For the year ended December 31, 2006, we averaged $0.77 above NYMEX prices for our
Louisiana natural gas production. However, in the Barnett Shale area in Texas, due primarily to
its location, the price we received averaged $0.83 below NYMEX prices. We expect our overall
differential to NYMEX prices to gradually increase in the future due to our increasing emphasis in
the Barnett Shale area.
Competition and Markets
We face competition from other oil and natural gas companies in all aspects of our business,
including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and
obtaining goods, services and labor. Many of our competitors have substantially larger financial
and other resources. Factors that affect our ability to acquire producing properties include
available funds, available information about prospective properties and our standards established
for minimum projected return on investment. Gathering systems are the only practical method for the
intermediate transportation of natural gas. Therefore, competition for natural gas delivery is
presented by other pipelines and gas gathering systems. Competition is also presented by
alternative fuel sources, including heating oil and other fossil fuels. Because of the nature of
our core assets (our tertiary operations) and our ownership of a relatively uncommon significant
natural source of carbon dioxide, we believe that we are effective in competing in the market.
The demand for qualified and experienced field personnel to drill wells and conduct field
operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas
industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing
periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand
for rigs and equipment has increased along with the number of wells being drilled. These factors
also cause significant increases in costs for equipment, services and personnel. Higher oil and
natural gas prices generally stimulate increased demand and result in increased prices for drilling
rigs, crews and associated supplies, equipment and services. We cannot be certain when we will
experience
16
Denbury Resources Inc.
these issues and these types of shortages or price increases could significantly
decrease our profit margin, cash flow and operating results or restrict our ability to drill those
wells and conduct those operations that we currently have planned and budgeted.
Federal and State Regulations
Numerous federal and state laws and regulations govern the oil and gas industry. These laws
and regulations are often changed in response to changes in the political or economic environment.
Compliance with this evolving regulatory burden is often difficult and costly, and substantial
penalties may be incurred for noncompliance. The following section describes some specific laws and
regulations that may affect us. We cannot predict the impact of these or future legislative or
regulatory initiatives.
Management believes that we are in substantial compliance with all laws and regulations
applicable to our operations and that continued compliance with existing requirements will not have
a material adverse impact on us. The future annual capital costs of complying with the regulations
applicable to our operations is uncertain and will be governed by several factors, including future
changes to regulatory requirements. However, management does not currently anticipate that future
compliance will have a materially adverse effect on our consolidated financial position or results
of operations.
Regulation of Natural Gas and Oil Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local
levels. Such regulation includes requiring permits for drilling wells, maintaining bonding
requirements in order to drill or operate wells and regulating the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with
operations. Our operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration units and the density
of wells that may be drilled in those units and the unitization or pooling of oil and gas
properties. In addition, state conservation laws establish maximum rates of production from oil
and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations may limit the amount of
oil and gas we can produce from our wells and may limit the number of wells or the locations at
which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing
business and, consequently, affects our profitability.
Federal Regulation of Sales Prices and Transportation
The transportation and certain sales of natural gas in interstate commerce are heavily
regulated by agencies of the U.S. federal government and are affected by the availability, terms
and cost of transportation. In particular, 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 FERCs 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.
17
Denbury Resources Inc.
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.
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 Companys
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 that 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, 2006, 2005 and 2004.
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 82% 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
18
Denbury Resources Inc.
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.
Our proved undeveloped natural gas reserves associated with our Selma Chalk play at Heidelberg
and the Barnett Shale play account for approximately 96% of our proved undeveloped natural gas
reserves. The remaining undeveloped natural gas reserves are spread over multiple fields. Our
current plans for 2006 include drilling 45 to 55 new wells in these
two primary natural gas plays.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
ESTIMATED PROVED RESERVES: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
126,185 |
|
|
|
106,173 |
|
|
|
101,287 |
|
Natural gas (MMcf) |
|
|
288,826 |
|
|
|
278,367 |
|
|
|
168,484 |
|
Oil equivalent (MBOE) |
|
|
174,322 |
|
|
|
152,568 |
|
|
|
129,369 |
|
PERCENTAGE OF TOTAL MBOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved producing |
|
|
48 |
% |
|
|
40 |
% |
|
|
39 |
% |
Proved non-producing |
|
|
17 |
% |
|
|
16 |
% |
|
|
16 |
% |
Proved undeveloped |
|
|
35 |
% |
|
|
44 |
% |
|
|
45 |
% |
REPRESENTATIVE OIL AND GAS PRICES:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil NYMEX |
|
$ |
61.05 |
|
|
$ |
61.04 |
|
|
$ |
43.45 |
|
Natural gas Henry Hub |
|
|
5.63 |
|
|
|
10.08 |
|
|
|
6.18 |
|
PRESENT VALUES:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Discounted estimated future net cash flow before
income taxes (PV-10 Value) (thousands) |
|
$ |
2,695,199 |
|
|
$ |
3,215,478 |
|
|
$ |
1,643,289 |
|
Standardized measure of discounted estimated future net
cash flow after income taxes (thousands) |
|
|
1,837,341 |
|
|
|
2,084,449 |
|
|
|
1,129,196 |
|
|
|
|
(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 Henry Hub cash 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. See Risk Factors
Estimating our reserves, production and future net cash flow is difficult to do with any
certainty. See also Note 12, Supplemental Oil and Natural Gas Disclosures, to the Consolidated
Financial Statements.
19
Denbury Resources Inc.
Item 1A. Risk Factors
Risks Related To Our Business
Our production will decline if our access to sufficient amounts of carbon dioxide is limited.
Our current long-term growth strategy is focused on our CO2 tertiary recovery
operations, and we expect approximately 60% of our 2007 capital expenditures to be in this area.
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 crude oil production is also dependent on our ability to increase the production volumes of
CO2 and inject adequate amounts of CO2 into the proper formation and area
within each oil field. The production of crude oil from tertiary operations is highly dependent on
the timing, volumes and location of the CO2 injections. If our crude oil production
were to decline, it could have a material adverse effect on our financial condition and results of
operations and cash flows.
Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices
could adversely affect our financial results.
Our future financial condition, results of operations and the carrying value of our oil and
natural gas properties depend 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. Oil prices
are likely to affect us more than natural gas prices because approximately 72% of our December 31,
2006 proved reserves are oil, with oil being an even larger percentage of our future potential
reserves and projects due to our focus on tertiary operations. The prices for oil and natural gas
are subject to a variety of additional factors that are beyond our control. These factors include:
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|
the level of consumer demand for oil and natural gas; |
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|
|
|
the domestic and foreign supply of oil and natural gas; |
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|
|
|
the ability of the members of the Organization of Petroleum Exporting Countries to
agree to and maintain oil price and production controls; |
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|
|
|
the price of foreign oil and natural gas; |
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|
|
|
domestic governmental regulations and taxes; |
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|
|
|
the price and availability of alternative fuel sources; |
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|
|
|
weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico; |
|
|
|
|
market uncertainty; |
|
|
|
|
political conditions in oil and natural gas producing regions, including the Middle East; and |
|
|
|
|
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.
20
Denbury Resources Inc.
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 2006, NYMEX oil prices
were high throughout the year, averaging $66.27 per Bbl. During 2004, 2005 and 2006, 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 2005,
averaging $6.33 per Bbl. Our 2006 differential was about the same as 2005, averaging $6.41 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 significantly impact our profitability.
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. During 2004 NYMEX
natural gas prices averaged $6.23 per MMBtu, during 2005 NYMEX averaged $8.97 per MMBtu and during
2006, averaged $6.97 per MMBtu.
Product Price Derivative Contracts may expose us to potential financial loss.
To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and
may in the future enter into derivative contracts in order to economically hedge a portion of our
oil and natural gas production. Derivative contracts expose us to risk of financial loss in some
circumstances, including when:
|
|
|
production is less than expected; |
|
|
|
|
the counter-party to the derivative contract defaults on its contract obligations; or |
|
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|
|
there is a change in the expected differential between the underlying price in the
hedging agreement and actual prices received. |
In addition, these derivative contracts 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
Managements Discussion and Analysis of Financial Condition and Results of Operations Market
Risk Management, and in Note 10 Derivative Instruments and Hedging Activities, to the
Consolidated Financial Statements.
Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and
adversely affect results of operations.
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. Due to the recent record high oil and gas prices, we have experienced shortages
of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the
number of wells being drilled. Higher oil and natural gas prices generally stimulate increased
demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield
equipment and services and personnel in our exploration and production operations. These types of
shortages or price increases could significantly decrease our profit margin, cash flow and
operating results and/or restrict or delay our ability to drill those wells and conduct those
operations that we currently have planned and budgeted, causing us to miss our forecasts and
projections.
Our future performance depends upon our ability to find or acquire additional oil and natural gas
reserves that are economically recoverable.
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 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
21
Denbury Resources Inc.
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 or meet expectations. In addition, certain of 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.
In January 2006, we purchased three oil fields for $250 million that we believe have
significant potential oil reserves that can be recovered through the use of tertiary flooding:
Tinsley Field approximately 40 miles northwest of Jackson, Mississippi; Citronelle Field in
Southwest Alabama, and the smaller South Cypress Creek Field near our Eucutta Field in Eastern
Mississippi. These three fields produced approximately 2,569 BOE/d net to the acquired interests
during the fourth quarter of 2006, and have proved reserves of approximately 13.5 million BOEs. We
purchased these fields because we believe that they have significant additional potential through
tertiary flooding and we paid a premium price for these properties based on that assumption. In
addition to this specific acquisition, we have, and plan to continue, acquiring other old oil
fields that we believe are tertiary flood candidates, likely at a premium price. We are investing
significant amounts of capital as part of this strategy. If we are unable to successfully develop
the potential oil in these acquired fields, it would negatively affect the return on our investment
on these acquisitions and could severely reduce our ability to obtain additional capital for the
future, fund future acquisitions, and negatively affect our financial
results to a significant degree.
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. Many of our competitors have
substantially larger financial and other resources. Other 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.
Oil and natural gas drilling and producing operations involve various risks.
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:
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unexpected drilling conditions; |
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|
|
|
title problems; |
|
|
|
|
pressure or irregularities in formations; |
|
|
|
|
equipment failures or accidents; |
|
|
|
|
adverse weather conditions, including hurricanes and tropical storms in and around
the Gulf of Mexico that can damage oil and natural gas facilities and delivering
systems and disrupt operations; |
|
|
|
|
compliance with environmental and other governmental requirements; and |
|
|
|
|
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.
22
Denbury Resources Inc.
The nature of these risks is such that some liabilities could exceed our insurance 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.
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 an adverse
effect upon the profitability of these operations.
We depend on our key personnel.
We believe our continued success depends on the collective abilities and efforts of our senior
management. The loss of one or more key personnel could have a material adverse effect on our
results of operations. We do not have any employment agreements and do not maintain any key man
life insurance policies. Additionally, if we are unable to find, hire and retain needed key
personnel in the future, our results of operations could be materially and adversely affected.
The loss of more than one of our large oil and natural gas purchasers could have a material adverse
effect on our operations.
For the year ended December 31, 2006, two purchasers each accounted for more than 10% of our
oil and natural gas revenues and in the aggregate, for 46% of these revenues. We would not expect
the loss of any single purchaser 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.
Estimating our reserves, production and future net cash flow is difficult to do with any certainty.
Estimating quantities of proved oil and natural gas reserves is a complex process. It
requires interpretations of available technical data and various assumptions, including assumptions
relating to economic factors, such as future commodity prices, production costs, severance and
excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of
governmental regulation. There are numerous uncertainties about when a property may have proved
reserves as compared to potential or probable reserves, particularly relating to our tertiary
recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations
and the production rates anticipated therefrom requires estimates, one of the most significant
being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the
use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily
represent the most appropriate discount factor, given actual interest rates and risks to which our
business or the oil and natural gas industry in general are subject. Any significant inaccuracies
in these interpretations or assumptions or changes of conditions could result in a reduction of the
quantities and net present value of our reserves.
Quantities of proved reserves are estimated based on economic conditions, including oil and
natural gas prices in existence at the date of assessment. Our 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.
The reserve data included in documents incorporated by reference represent only estimates. 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 cost as of the date of the estimate.
As of December 31, 2006, approximately 35% of our estimated proved reserves were undeveloped.
Recovery of undeveloped reserves requires significant capital expenditures and may require
successful drilling operations. The reserve data assumes that we can and will make these
expenditures and conduct these operations successfully, but these assumptions may not be accurate,
and this may not occur.
23
Denbury Resources Inc.
We are subject to complex federal, state and local laws and regulations, including environmental
laws, which could adversely affect our business.
Exploration for and development, exploitation, production and sale of oil and natural gas in
the United States are subject to extensive federal, state and local laws and regulations, including
complex tax laws and environmental laws and regulations. Existing laws or regulations, as
currently interpreted or reinterpreted in the future, or future laws, regulations or incremental
taxes and fees, could harm our business, results of operations and financial condition. We may be
required to make large expenditures to comply with environmental and other governmental
regulations.
It is possible that new taxes on our industry could be implemented and/or tax benefits could
be eliminated or reduced, reducing our profitability and available cash flow. In addition to the
short-term negative impact on our financial results, such additional burdens, if enacted, would
reduce our funds available for reinvestment and thus ultimately reduce our growth and future oil
and natural gas production.
Matters subject to regulation include oil and gas production and saltwater disposal operations
and our processing, handling and disposal of hazardous materials, such as hydrocarbons and
naturally occurring radioactive materials, discharge permits for drilling operations, spacing of
wells, environmental protection and taxation. We could incur significant costs as a result of
violations of or liabilities under environmental or other laws, including third-party claims for
personal injuries and property damage, reclamation costs, remediation and clean-up costs resulting
from oil spills and discharges of hazardous materials, fines and sanctions, and other environmental
damages.
Our level of indebtedness may adversely affect operations and limit our growth.
As
of February 28, 2007, we had approximately $150 million outstanding on our bank credit
line with approximately $350 million available on our borrowing base. The next semi-annual
redetermination of the borrowing base for our bank credit facility will be on April 1, 2007. Our
bank borrowing base is adjusted at the banks discretion and is based in part upon external
factors, such as commodity prices, over which we have no control. If our then redetermined
borrowing base is less than our outstanding borrowings under the facility, we will be required to
repay the deficit over a period of six months.
We may incur additional indebtedness in the future under our bank credit facility in
connection with our acquisition, development, exploitation and exploration of oil and natural gas
producing properties. Further, our cash flow from operations is highly dependent on the prices that
we receive for oil and natural gas. If oil and natural gas prices were to decline significantly,
particularly for an extended period of time, our degree of leverage could increase substantially.
The level of our indebtedness could have important consequences, including but not limited to, the
following:
|
|
|
a substantial portion of our cash flows from operations may be dedicated to
servicing our indebtedness and would not be available for other purposes; |
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|
|
|
our business may not generate sufficient cash flow from operations to enable us to
continue to meet our obligations under our indebtedness; |
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|
|
our level of indebtedness may impair our ability to obtain additional financing in
the future for working capital, capital expenditures, acquisitions or general corporate
and other purposes; |
|
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|
|
our interest expense may increase in the event of increases in interest rates,
because certain of our borrowings are at variable rates of interest; |
|
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|
|
our vulnerability to general adverse economic and industry conditions may increase,
potentially restricting us from making acquisitions, introducing new technologies or
exploiting business opportunities; |
|
|
|
|
our ability to borrow additional funds, dispose of assets, pay dividends and make
certain investments may be limited by the covenants contained in the agreements
governing our outstanding indebtedness limit; and |
|
|
|
|
our debt covenants may also affect our flexibility in planning for, and reacting to,
changes in the economy and in our industry. Our failure to comply with such covenants
could result in an event |
24
Denbury Resources Inc.
of default under such debt instruments which, if not cured or waived, could have a
material adverse effect on us.
If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make
required payments on our indebtedness or if we otherwise fail to comply with the various covenants
in such indebtedness, including covenants in our bank credit facility, we would be in default. This
default would permit the holders of such indebtedness to accelerate the maturity of such
indebtedness and could cause defaults under other indebtedness, including the subordinated notes,
or result in our bankruptcy. Our ability to meet our obligations will depend upon our future
performance, which will be subject to prevailing economic conditions and to financial, business and
other factors, including factors beyond our control.
Item 1B. Unresolved Staff Comments
None.
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 Managements Discussion and Analysis of Financial
Condition and Results of Operations, and Note 11, 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. 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.
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 2006.
25
Denbury Resources Inc.
PART II
Item 5. Market for Registrants 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 Denburys common stock on the New York Stock Exchange (NYSE), for each quarterly
period for the last two fiscal years. The sales prices are adjusted to reflect the 2-for-1 stock
split on October 31, 2005. On April 25, 2006, we closed the $125 million sale (net to Denbury) of
3,492,595 shares of common stock in a public offering. As of January 31, 2007, the number of
record holders of Denburys common stock was 821. Management believes, after inquiry, that the
number of beneficial owners of Denburys common stock is in
excess of 10,500. On January 31, 2007, the last reported sales price of Denburys Common Stock, as reported on the NYSE, was $27.70 per
share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
High |
|
Low |
|
High |
|
Low |
First Quarter |
|
$ |
32.65 |
|
|
$ |
23.57 |
|
|
$ |
18.32 |
|
|
$ |
12.37 |
|
Second Quarter |
|
|
36.60 |
|
|
|
25.91 |
|
|
|
20.53 |
|
|
|
14.02 |
|
Third Quarter |
|
|
35.80 |
|
|
|
26.53 |
|
|
|
25.71 |
|
|
|
19.95 |
|
Fourth Quarter |
|
|
30.93 |
|
|
|
25.95 |
|
|
|
25.50 |
|
|
|
19.36 |
|
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 2006.
26
Denbury Resources Inc.
Share Performance Graph
The following Performance Graph and related information shall not be deemed soliciting
material or to be filed with the Securities and Exchange Commission, nor shall such information
be incorporated by reference into any future filings under the Securities Act of 1933 or Securities
Exchange Act of 1934, each as amended, except to the extent that the Company specifically
incorporates it by reference into such filing.
The following graph illustrates changes over the five year period ended December 31, 2006, in
cumulative total stockholder return on our common stock as measured against the cumulative total
return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The results
assume $100 was invested on December 31, 2001, and that dividends were reinvested.
Cumulative Total Return on $100 Investment
(December 31, 2001-December 31, 2006)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2001 |
|
2002 |
|
2003 |
|
2004 |
|
2005 |
|
2006 |
|
|
|
Denbury |
|
$ |
100 |
|
|
$ |
155 |
|
|
$ |
190 |
|
|
$ |
376 |
|
|
$ |
623 |
|
|
$ |
760 |
|
S&P 500 |
|
|
100 |
|
|
|
78 |
|
|
|
100 |
|
|
|
111 |
|
|
|
117 |
|
|
|
135 |
|
Dow Jones Exploration and Production |
|
|
100 |
|
|
|
102 |
|
|
|
134 |
|
|
|
190 |
|
|
|
314 |
|
|
|
331 |
|
27
Denbury Resources Inc.
Item 6. Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, unless otherwise noted) |
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004(1) |
|
2003 |
|
2002 |
Consolidated Statements of
Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
731,536 |
|
|
$ |
560,392 |
|
|
$ |
382,972 |
|
|
$ |
333,014 |
|
|
$ |
285,152 |
|
Net income |
|
|
202,457 |
(2) |
|
|
166,471 |
|
|
|
82,448 |
|
|
|
56,553 |
(3) |
|
|
46,795 |
|
Net income per common share (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
1.74 |
(2) |
|
|
1.49 |
|
|
|
0.75 |
|
|
|
0.52 |
(3) |
|
|
0.44 |
|
Diluted |
|
|
1.64 |
(2) |
|
|
1.39 |
|
|
|
0.72 |
|
|
|
0.51 |
(3) |
|
|
0.43 |
|
Weighted average number of common
shares outstanding (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
116,550 |
|
|
|
111,743 |
|
|
|
109,741 |
|
|
|
107,763 |
|
|
|
106,487 |
|
Diluted |
|
|
123,774 |
|
|
|
119,634 |
|
|
|
114,603 |
|
|
|
110,928 |
|
|
|
108,730 |
|
Consolidated Statements of Cash
Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used by): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
461,810 |
|
|
$ |
360,960 |
|
|
$ |
168,652 |
|
|
$ |
197,615 |
|
|
$ |
159,600 |
|
Investing activities |
|
|
(856,627 |
) |
|
|
(383,687 |
) |
|
|
(93,550 |
) |
|
|
(135,878 |
) |
|
|
(171,161 |
) |
Financing activities |
|
|
283,601 |
|
|
|
154,777 |
|
|
|
(66,251 |
) |
|
|
(61,489 |
) |
|
|
12,005 |
|
Production (Daily): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
22,936 |
|
|
|
20,013 |
|
|
|
19,247 |
|
|
|
18,894 |
|
|
|
18,833 |
|
Natural gas (Mcf) |
|
|
83,075 |
|
|
|
58,696 |
|
|
|
82,224 |
|
|
|
94,858 |
|
|
|
100,443 |
|
BOE (6:1) |
|
|
36,782 |
|
|
|
29,795 |
|
|
|
32,951 |
|
|
|
34,704 |
|
|
|
35,573 |
|
Unit Sales Price (excluding hedges): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
59.87 |
|
|
$ |
50.30 |
|
|
$ |
36.46 |
|
|
$ |
27.47 |
|
|
$ |
22.36 |
|
Natural gas (per Mcf) |
|
|
7.10 |
|
|
|
8.48 |
|
|
|
6.24 |
|
|
|
5.66 |
|
|
|
3.31 |
|
Unit Sales Price (including hedges): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
59.23 |
|
|
$ |
50.30 |
|
|
$ |
27.36 |
|
|
$ |
24.52 |
|
|
$ |
22.27 |
|
Natural gas (per Mcf) |
|
|
7.10 |
|
|
|
7.70 |
|
|
|
5.57 |
|
|
|
4.45 |
|
|
|
3.35 |
|
Costs per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
12.46 |
|
|
$ |
9.98 |
|
|
$ |
7.22 |
|
|
$ |
7.06 |
|
|
$ |
5.48 |
|
Production taxes and marketing expenses |
|
|
2.71 |
|
|
|
2.54 |
|
|
|
1.55 |
|
|
|
1.17 |
|
|
|
0.92 |
|
General and administrative |
|
|
3.20 |
|
|
|
2.62 |
|
|
|
1.78 |
|
|
|
1.20 |
|
|
|
0.96 |
|
Depletion, depreciation, and
amortization |
|
|
11.11 |
|
|
|
9.09 |
|
|
|
8.09 |
|
|
|
7.48 |
|
|
|
7.26 |
|
Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
126,185 |
|
|
|
106,173 |
|
|
|
101,287 |
|
|
|
91,266 |
|
|
|
97,203 |
|
Natural gas (MMcf) |
|
|
288,826 |
|
|
|
278,367 |
|
|
|
168,484 |
|
|
|
221,887 |
|
|
|
200,947 |
|
MBOE (6:1) |
|
|
174,322 |
|
|
|
152,568 |
|
|
|
129,369 |
|
|
|
128,247 |
|
|
|
130,694 |
|
Carbon
Dioxide (MMcf) (5) |
|
|
5,525,948 |
|
|
|
4,645,702 |
|
|
|
2,664,633 |
|
|
|
1,613,840 |
|
|
|
815,315 |
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,139,837 |
|
|
$ |
1,505,069 |
|
|
$ |
992,706 |
|
|
$ |
982,621 |
|
|
$ |
895,292 |
|
Total long-term liabilities |
|
|
833,380 |
|
|
|
617,343 |
|
|
|
368,128 |
|
|
|
434,845 |
|
|
|
432,616 |
|
Stockholders equity (6) |
|
|
1,106,059 |
|
|
|
733,662 |
|
|
|
541,672 |
|
|
|
421,202 |
|
|
|
366,797 |
|
|
|
|
(1) |
|
We sold Denbury Offshore, Inc. in July 2004. |
|
(2) |
|
Effective January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123(R),
Share Based Payment. |
|
(3) |
|
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 $0.02. In April 2003, we recorded a pre-tax charge of
$17.6 million associated with an early debt retirement. |
|
(4) |
|
On October 31, 2005, we split our common stock on a 2-for-1 basis. Information relating to
all prior years shares and earnings per share has been retroactively restated to reflect the stock
split. |
|
(5) |
|
Based on a gross working interests basis and includes reserves dedicated to volumetric
production payments of 210.5 Bcf at December 31, 2006, 237.1 Bcf at December 31, 2005, 178.7 Bcf at
December 31, 2004 and 162.6 Bcf at December 31, 2003 (See Note 14 to the Consolidated Financial
Statements). |
|
(6) |
|
We have never paid any dividends on our common stock. |
28
Denbury Resources Inc.
Item 7. Managements 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 carbon dioxide (CO2) reserves east of the
Mississippi River used for tertiary oil recovery, and hold significant operating acreage onshore
Louisiana, Alabama, and in the Barnett Shale play near Fort Worth, 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 five primary field
offices located in Houma, Louisiana; Laurel, Mississippi; McComb, Mississippi; Brandon,
Mississippi; and Cleburne, Texas.
2006 Overview
Operating results. During 2006, the combination of high commodity prices and record annual
production resulted in record annual earnings and cash flow from operations. Production for 2006
averaged 36,782 BOE/d, 23% higher than our average production during 2005, with production
increases in every operating area. Commodity prices, on a BOE basis net to us, increased 6%
between the fiscal year-end 2005 and 2006. Virtually all expenses increased during 2006, on both
an absolute and per BOE basis, as we experienced cost increases in almost every aspect of our
business. Overall industry costs continue to increase, the primary reason for higher operating
costs and depreciation and depletion rates per BOE in 2006. Operating expenses were also impacted
by higher energy costs (electrical and fuel charges) and our continuing emphasis on tertiary
operations. General and administrative expenses increased 51% between 2005 and 2006 primarily as a
result of the adoption of SFAS No. 123(R) relating to stock compensation and continued growth in
personnel and inflation in the industry. Interest expense increased 31% as a result of average
debt levels that were 83% higher than in 2005, partially offset by $11.3 million of capitalized
interest expense, primarily relating to the unevaluated properties included in our 2006
acquisitions. Our commodity derivative contract mark-to-market adjustments were the only positive
trend in expenses during 2006, wherein we recognized a $19.8 million gain in 2006, as compared to a
$29.0 million loss in 2005. Our derivative gain was primarily a result of our decision to enter
into natural gas swaps in mid December 2006 covering between 80% and 90% of our forecasted 2007
natural gas production, followed by a decline in natural gas prices by year-end.
As has been our practice for several years, we are reinvesting virtually all of our cash flow
in new projects, with a desire to further increase our production and reserves. During 2006, our
proved reserves increased from 152.6 MMBOE as of December 31, 2005 to 174.3 MMBOE as of December
31, 2006, replacing approximately 260% of our 2006 production, over 60% of which was from internal
organic growth, with the balance from acquisitions. The most significant reserve additions during
2006 were in the Barnett Shale. We did not recognize many tertiary oil reserve additions during
2006 because of delays in getting projects completed (and the related delays in associated
production response) and because of a transition in how proved tertiary oil reserves were being
recognized (see Results of Operations Depletion, Depreciation and Amortization for a review of
our reserve changes during 2006 and a discussion of our proved tertiary reserves).
Net income for 2006 was $202.5 million as compared to $166.5 million for 2005 and $82.4
million for 2004. The incremental net income during the 2006 was attributable to most of the
factors noted above, principally higher production, partially offset by higher costs. Continued
high commodity prices during 2006 also played a significant role in the 2006 results.
In addition to inflationary costs in our industry, we are experiencing more and more delays in
obtaining goods and services. This industry trend has caused us to experience higher costs than
originally forecasted and to periodically fall behind schedule with regard to the timing of planned
activities. While there are preliminary signs that these trends are slowing as a result of the
decline in commodity prices in late 2006, unless commodity prices remain flat or continue to
decrease, we believe that we are likely to see a resumption of these trends. These rising costs,
both for operating expenses and capital expenditures, and shortages of goods and services,
contribute to delays in completing our planned projects and may cause delays and shortfalls in
achieving our anticipated production and profitability targets. See Results of Operations for a
more thorough discussion of our operating results.
Continued expansion of our tertiary operations. Since we acquired our first carbon dioxide
tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of
operations. We particularly like this
29
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 below for a discussion of these
operations, their potential, and the ramifications of our continuing emphasis on these operations.
Having enough CO2 to flood our tertiary oil fields is one of the most important
ingredients, if not the key ingredient, to our tertiary operations. During 2006 we increased our
proved CO2 reserve quantities by 19%, from 4.6 Tcf as of December 31, 2005, to
approximately 5.5 Tcf as of December 31, 2006 (both of these quantities are on a working interest
basis see CO2 Operations CO2 Resources for further information). We
are continuing to buy additional oil fields that are tertiary flood candidates (See 2006
Acquisitions below).
2006 Acquisitions.
Tinsley and Citronelle Fields. On January 31, 2006, we completed an acquisition of three
producing oil properties that are future potential CO2 tertiary oil flood candidates:
Tinsley Field approximately 40 miles northwest of Jackson, Mississippi, Citronelle Field in
Southwest Alabama, and the smaller South Cypress Creek Field near the Companys Eucutta Field in
Eastern Mississippi. In 2006 we began our tertiary development work at Tinsley Field, consisting
primarily of planning, land and engineering work, with more extensive development and facility
construction planned for 2007. The timing of tertiary development at Citronelle Field is uncertain
as we will need to build a 60-to-70 mile extension of our Free State pipeline (CO2
pipeline from Jackson Dome to East Mississippi) before flooding can commence, and South Cypress
Creek will probably be flooded following our initial development of our other East Mississippi
properties. The adjusted purchase price for these three properties was approximately $250 million.
The acquisition was funded with proceeds of the $150 million of senior subordinated notes issued in
December 2005 and $100 million of bank financing under the Companys existing credit facility
(repaid in April 2006 with proceeds from our equity offering at that time). During the fourth
quarter of 2006, these fields produced an average of 2,569 BOE/d, up slightly from the 2,200 BOE/d
at the time of acquisition. As of December 31, 2006, these fields had proved reserves of
approximately 13.5 million BOEs. We operate all three fields and own the majority of the working
interests.
Delhi Field. During May 2006, we purchased the Delhi Holt-Bryant Unit (Delhi) in northern
Louisiana for $50 million, plus a 25% reversionary interest to the seller after we have achieved
$200 million in net operating revenue, as defined. Delhi is also a future potential CO2
tertiary oil flood candidate that will require construction of a CO2 pipeline before
flooding can commence, with current plans to make such a line an extension of the larger, new
CO2 pipeline currently planned from Jackson Dome to Tinsley Field. Our goal is to have
this CO2 line installed by 2008, with initial oil production from tertiary operations
currently anticipated during 2009. No significant oil production or proved oil reserves existed at
Delhi Field at December 31, 2006.
Hastings Field. During November 2006 we entered into an agreement with a subsidiary of Venoco,
Inc. that gives us an option, between November 1, 2008
and November 1, 2009, to purchase their interest in Hastings Field, a strategically significant potential tertiary flood candidate located near
Houston, Texas. The agreement provides for the parties to agree upon
a purchase price for the conventional proved reserves at the time
of the exercise of the option, which may be paid in cash or through a volumetric production
payment; failing an agreement as to price, the price will be determined by a pre-designated
independent petroleum engineering firm using specified criteria for calculation of the discounted
present value of proved reserves at that time. As consideration for the option agreement, we made
an upfront payment of $37.5 million and are required to make additional payments totaling $12.5
million over the next twenty months. We can extend the option period beyond November 2009 for up
to seven additional years at an incremental cost of $30 million per year. None of the option
payment amounts will be credited against the purchase price if we exercise the option. If we
exercise the option, we will be committed to make aggregate net capital expenditures in the field
of approximately $175 million over the subsequent five years to develop the field for tertiary
operations, with an obligation to commence CO2 injections in the field within three
years following the option exercise. Hastings Field is currently producing approximately 2,400
Bbls/d, although we currently have no economic interest in this production.
We believe that Hastings Field has significant potential oil reserves from tertiary flooding.
We plan to build a pipeline to transport CO2 to this field, estimated at between 280 and
300 miles, from the southern end of our existing CO2 pipeline which terminates near
Donaldsonville, Louisiana. Based on very preliminary estimates, this pipeline is expected to cost
between $450 million and $650 million, although this cost could vary significantly depending on the
ultimate size of the pipeline, its pressure rating, its specific route, and other variables, all of
which are unknown
30
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
at this time. We are initiating studies related to construction of this line, with a goal of
having it installed and
operational within the next few years. We anticipate initially transporting CO2 to the
Hastings Field from our natural CO2 source at Jackson Dome, but ultimately plan to use
manufactured (anthropogenic) sources of CO2 for this tertiary operation. See Results
of Operations CO2 Resources for a discussion of an agreement we entered into during
2006 to purchase a man-made source of CO2 from a planned petroleum coke gasification
project.
April 2006 Equity Offering. On April 25, 2006, we closed the $125 million sale (net to
Denbury) of 3,492,595 shares of common stock in a public offering. We used the net proceeds from
the offering to repay then current borrowings under our bank credit facility, which were $120
million as of that date, principally incurred to partially fund our $250 million acquisition of
three properties in January 2006.
Capital Resources and Liquidity
Our current 2007 capital budget is $650 million, excluding any potential acquisitions.
Approximately 60% of our 2007 budget is expected to be spent on tertiary related operations,
approximately 20% in the Barnett Shale area, and less than 10% on exploration projects, with the
balance spent on our conventional properties in Mississippi or Louisiana. This capital program
includes an estimated $80 million to $100 million for a CO2 pipeline from our
CO2 source at Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during
2006. Based on futures commodity prices as of the end of January 2007, this budget is $200 million
to $250 million greater than our anticipated cash flow from operations, a much greater shortfall
than we have had in recent years. Currently, we plan to fund the majority of this shortfall by
refinancing our two existing CO2 pipelines with Genesis Energy, L.P. (Genesis) by
entering into some type of long-term financing or sale transaction, effectively paying for the cost
of the pipeline over an extended period of time and recouping our cash previously spent. We would
anticipate a similar financing with Genesis for the new CO2 pipeline from Jackson Dome
to Tinsley and Delhi Fields once it is completed, forecasted at this time to be during the first
half of 2008. We have discussed with Genesis that any such financings are conditioned upon Genesis
achieving certain goals, primarily the acquisition of other economic projects that are not related
to Denbury, based upon acquisition by Genesis of $1.50 of non-Denbury-related acquisitions for
every $1.00 of financings or sales with Denbury. If Genesis is not successful in acquiring
properties from third parties or we cannot reach mutually agreeable terms with Genesis to sell them
these CO2 pipeline assets, we would plan to fund the shortfall with conventional debt
and could potentially reduce our capital budget later in the year. As of February 16, 2007, we had
$150 million of bank debt outstanding on a $500 million borrowing base (see Revised bank credit
agreement below), leaving us significant incremental borrowing capacity, more than we currently
plan or desire to use.
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 increased our capital budget throughout the year. As a result of
the recent cost inflation in our industry, many of our recent budget increases have related to
escalating costs rather than additional projects. In this inflationary environment, we often have
to either increase our capital budget or consider the elimination of a portion of our planned
projects.
We also continue to pursue additional acquisitions of mature oil fields that we believe have
potential as future tertiary flood candidates. These possible acquisitions are difficult to
forecast and the purchase price can vary widely depending on the levels in the fields of existing
production and conventional proved reserves and commodity prices. Any additional acquisitions would
be funded, at least temporarily, with bank or other debt, although if significant, the acquisition
would likely be ultimately funded with more permanent capital such as subordinated debt and/or
additional equity.
Revised bank credit agreement. On September 14, 2006, we entered into a Sixth Amended and
Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative
agent. The new agreement (i) improved the credit pricing under the agreement, (ii) extended the
term of the credit arrangements by two and one-half years to September 14, 2011, (iii) increased
the borrowing base from $300 million to $500 million, (iv) increased the maximum facility size from
$300 million to $800 million, and (v) made other minor modifications. Under the new agreement, the
commitment amount remained at $150 million, an amount increased in December 2006 to $250 million.
The borrowing base represents the amount that can be borrowed from a credit standpoint based on our
assets, as confirmed by the banks, while the commitment amount is the amount the banks have
committed to fund pursuant to the terms of the credit agreement. The banks have the option to
participate in
31
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
any borrowing request by us in excess of the commitment amount ($250 million), up to the borrowing
base limit
($500 million), although the banks are not obligated to fund any amount in excess of the commitment
amount. At December 31, 2006, we had outstanding $375.0 million (principal amount) of 7.5%
subordinated notes, approximately $10.0 million of capital lease commitments, $134.0 million of
bank debt, and a working capital deficit of approximately $17.1 million.
Sources and Uses of Capital Resources
During 2006, we spent $507.3 million on oil and natural gas exploration and development, $63.6
million on CO2 exploration and development, and approximately $319.0 million on property
acquisitions, for total capital expenditures of approximately $889.9 million. Our oil and natural
gas exploration and development expenditures included approximately $245.3 million spent on
drilling, $31.6 million spent on geological, geophysical and acreage expenditures and $230.4
million incurred on facilities and recompletion costs. We funded our total capital expenditures
with $461.8 million of cash flow from operations, $125 million of equity, $134 million of net bank
borrowings, and a $13.2 million increase in our accrued capital expenditures, with the balance
funded with working capital, predominately cash from the December 2005 issuance of $150 million of
subordinated debt. 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 $448.4 million for 2006, while cash flow from operations for the
same period, the GAAP measure, was $461.8 million.
During 2005, we spent $292.8 million on oil and natural gas exploration and development
expenditures, $76.8 million on CO2 exploration and development expenditures (including
approximately $46.0 million for our CO2 pipeline to East Mississippi), and approximately
$70.9 million on property acquisitions, for total capital expenditures of approximately $440.5
million. Our exploration and development expenditures included approximately $147.8 million spent
on drilling, $25.5 million of geological, geophysical and acreage expenditures and $135.1 million
spent on facilities and recompletion costs. Our 2005 acquisition expenditures include the purchase
of additional interest and acreage in the Barnett Shale area and purchase of two oil fields,
Cranfield and Lake St. John Fields, which may be potential tertiary flood candidates in the future.
Our $440.5 million of capital expenditures included an increase of $18.2 million in our accrued
capital expenditures, with the remaining cash portion of our capital expenditures funded primarily
with $361.0 million of cash flow from operations and approximately $57 million of short-term
investments remaining at December 31, 2004, from the sale of our offshore properties during 2004.
Additionally, we issued $150 million of subordinated debt in December 2005 and raised $14.4 million
during 2005 from the sale of another volumetric production payment of CO2 to Genesis,
along with a related long-term CO2 supply agreement with an industrial customer. All of
these sources not only funded our capital expenditures, but also increased our cash balance at
year-end 2005 to $165.1 million, with a portion of such funds used in January 2006 to partially
fund our $250 million acquisition. 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 below) was $343.4 million for 2005, while cash flow
from operations for the same period, the GAAP measure, was $361.0 million.
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, 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.
32
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 payment obligations that are not on our
balance sheet include our operating leases, which at year-end 2006 totaled $101.4 million
(including $71.4 million of equipment costs) relating primarily to the lease financing of
certain equipment for CO2 recycling facilities at our tertiary oil fields. We also have
several leases relating to office space and other minor equipment leases. Additionally, we have
dollar related 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 below.
At December 31, 2006, we had a total of $10.5 million outstanding in letters of credit.
Genesis Energy, Inc., our 100% owned subsidiary that is the general partner of Genesis, may, as
general partner, be a potential guarantor of the bank debt of Genesis, which consists of $8.0
million in debt and $4.6 million in letters of credit at December 31, 2006. 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, 2006. We do not have any material transactions with related parties other
than sales of production, transportation arrangements, and capital leases 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 at December 31, 2006, is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
Amounts in Thousands |
|
Total |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
Thereafter |
|
Contractual Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated debt (a) |
|
$ |
375,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
375,000 |
|
Senior Bank Loan (a) |
|
|
134,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
134,000 |
|
|
|
|
|
Estimated interest payments on
subordinated debt and Senior Bank Loan (a) |
|
|
246,164 |
|
|
|
36,634 |
|
|
|
36,634 |
|
|
|
36,634 |
|
|
|
36,634 |
|
|
|
34,116 |
|
|
|
65,512 |
|
Operating lease obligations |
|
|
101,378 |
|
|
|
13,056 |
|
|
|
12,667 |
|
|
|
11,857 |
|
|
|
11,527 |
|
|
|
10,967 |
|
|
|
41,304 |
|
Capital lease obligations (b) |
|
|
10,028 |
|
|
|
1,291 |
|
|
|
1,291 |
|
|
|
1,529 |
|
|
|
1,291 |
|
|
|
1,291 |
|
|
|
3,335 |
|
Capital expenditure obligations (c) |
|
|
102,660 |
|
|
|
66,386 |
|
|
|
20,284 |
|
|
|
14,235 |
|
|
|
1,755 |
|
|
|
|
|
|
|
|
|
Derivative contracts (receipt) payment (d) |
|
|
(14,726 |
) |
|
|
(22,125 |
) |
|
|
7,399 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hastings field purchase option |
|
|
12,500 |
|
|
|
7,500 |
|
|
|
5,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Cash Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future development costs on proved oil and gas
reserves, net of capital obligations (e) |
|
|
463,707 |
|
|
|
180,000 |
|
|
|
141,523 |
|
|
|
85,490 |
|
|
|
19,367 |
|
|
|
9,442 |
|
|
|
27,885 |
|
Future
development cost on proved CO2
reserves, net of capital obligations (f) |
|
|
149,367 |
|
|
|
31,267 |
|
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
11,000 |
|
|
|
87,100 |
|
Asset retirement obligations (g) |
|
|
91,338 |
|
|
|
1,940 |
|
|
|
1,130 |
|
|
|
2,428 |
|
|
|
5,351 |
|
|
|
1,509 |
|
|
|
78,980 |
|
|
Total |
|
$ |
1,671,416 |
|
|
$ |
315,949 |
|
|
$ |
245,928 |
|
|
$ |
152,173 |
|
|
$ |
75,925 |
|
|
$ |
202,325 |
|
|
$ |
679,116 |
|
|
|
|
|
(a) |
|
These long-term borrowings and related interest payments are further discussed in Note 6 to
the Consolidated Financial Statements. This table assumes that our long-term debt is held
until maturity. |
|
(b) |
|
Represents future minimum cash commitments of $8.2 million to Genesis under capital leases in
place at December 31, 2006, primarily for transportation of crude oil and CO2, $1.6
million for our office in Laurel, Mississippi, and auto leases for $0.2 million.
Approximately $3.0 million of these payments represents interest. |
|
(c) |
|
Represents future minimum cash commitments under contracts in place as of December 31, 2006,
primarily for drilling rig services and well related costs. As is common in our industry, we
commit to make certain expenditures on a regular |
33
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
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 2007 is currently set at $650 million. 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 the amounts of these types of
recurring 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 oil and gas derivative contracts based on
the futures market prices as of December 31, 2006. 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, 2006, was a $15.7 million net asset. See further
discussion of our derivative contracts and their market price sensitivities in Market Risk
Management below in this Managements Discussion and Analysis of Financial Condition and in
Note 10 to the Consolidated Financial Statements. |
|
(e) |
|
Represents projected capital costs as scheduled in our December 31, 2006 proved reserve
report that are necessary in order to recover our proved undeveloped oil and natural gas
reserves. These are not contractual commitments and are net of any other capital obligations
shown under Contractual Obligations in table above. |
|
(f) |
|
Represents projected capital costs as scheduled in our December 31, 2006 proved reserve
report that are necessary in order to recover our proved undeveloped CO2 reserves
from our CO2 source wells used to produce CO2 for our tertiary
operations. These are not contractual commitments and are net of any other capital obligations
shown above. |
|
(g) |
|
Represents the estimated future asset retirement obligations on an undiscounted basis. The
present discounted asset retirement obligation is $41.1 million, as determined under SFAS No.
143, is further discussed in Note 4 to the Consolidated Financial Statements. |
The above table does not include the commitment to purchase CO2 from the
proposed Faustina plant, if built (see Results of Operations CO2 Resources Man-made
CO2 sources below) and does not include the commitments related to Hastings Field if
the purchase option is exercised by us (see 2006 Acquisitions above), as both obligations are
contingent on certain events. The above table does include the remaining $12.5 million due on the
Hastings option payment.
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 three volumetric production payments (VPP) entered into during 2003 through
2005. Based upon the maximum amounts deliverable as stated in the industrial contracts and the
volumetric production payments, we estimate that we may be obligated to deliver up to 391 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, currently we project that our commitment would likely be reduced to
approximately 255 Bcf. The maximum volume required in any given year is approximately 105 MMcf/d,
although based on our current level of deliveries, this would likely be reduced to approximately 69
MMcf/d. Given the size of our proven CO2 reserves at December 31, 2006 (approximately
5.5 Tcf before deducting approximately 210.5 Bcf for the three 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. Our interest in tertiary operations has increased to the point that approximately
60% of our 2007 capital budget is dedicated to tertiary related operations. We particularly like
this play as (i) it has a lower risk and is more predictable than most traditional exploration and
development activities, (ii) it provides a reasonable rate of return at relatively low oil prices
(generally around $30 a barrel at todays cost levels, depending on the specific field and area),
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.
We talk about our tertiary operations by labeling operating areas or groups of fields as
phases. Phase I is in Southwest Mississippi and includes several fields along our 183-mile
CO2 pipeline that we acquired in 2001. The
34
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II,
which began with the early 2006 completion of our CO2 pipeline to East Mississippi,
includes Eucutta, Soso, Martinville and Heidelberg Fields. With the properties acquired in our
January 2006 acquisition (see 2006 Acquisitions above), we have labeled the planned operations at
Tinsley Field, Northwest of Jackson Dome, as Phase III. Phase IV includes Cranfield and Lake St.
John Fields, two fields near the Mississippi/Louisiana border located west of the Phase I fields,
and Phase V is Delhi Field, a Louisiana field we acquired in 2006, located southwest of Tinsley
Field (see 2006 Acquisitions). Ultimately, we also plan to ultimately flood Citronelle Field,
another field acquired in 2006, and Hastings Field, a field on which we acquired a purchase option
in late 2006. We have not yet labeled these two fields as a specific phase.
CO2 Resources. In February 2001, we acquired the CO2 source field
located near Jackson, Mississippi, and a 183-mile pipeline to transport it to our oil fields.
Since February 2001, we have acquired two producing wells and
drilled 11 additional CO2
producing wells, significantly increasing our estimated proved CO2 reserves from
approximately 800 Bcf at the time of the 2001 acquisition to approximately 5.5 Tcf as of December
31, 2006, approximately 250 Bcf more than we estimate we need for our existing and currently
planned phases of tertiary operations. During 2006, our proven CO2 reserves increased
approximately 19%, or 900 Bcf, from 4.6 Tcf to 5.5 Tcf. The estimate of 5.5 Tcf of proved
CO2 reserves is based on 100% ownership of the CO2 reserves, of which
Denburys net revenue interest ownership is approximately 4.5 Tcf. Both reserve estimates are
included in the evaluation of proven CO2 reserves prepared by DeGolyer & MacNaughton.
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 Denburys tertiary recovery
programs and industrial users, as Denbury is responsible for distributing the entire CO2
production stream for both of these uses. We currently estimate that
it will take approximately 850 Bcf of CO2 to develop and produce the proved tertiary recovery reserves we have recorded
at December 31, 2006.
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 2007, we estimate that we
are capable of producing approximately 470 MMcf/d of CO2, over seven times the rate that
we were capable of producing at the time of our initial acquisition in 2001. We continue to drill
additional CO2 wells, with three more wells planned for 2007, in order to further
increase our production capacity and potentially increase our proven CO2 reserves. Our
drilling activity at Jackson Dome will continue beyond 2007 as our current forecasts for the five
phases which are specifically planned to date suggest that we will
need approximately 1,000 MMcf/d of
CO2 production by 2011.
In addition to using CO2 for our tertiary operations, we sell CO2 to
third party industrial users under long-term contracts. Most of these industrial contracts have
been sold to Genesis along with the sale of a volumetric production payment for the CO2.
Our average daily CO2 production during 2004, 2005 and 2006 was approximately 218
million, 242 million, and 342 million cubic feet per day, of which approximately 73% in 2004, 73%
in 2005, and 75% in 2006 was used in our tertiary recovery operations, with the balance delivered
to Genesis under the volumetric production payments or sold to third party industrial users.
We spent approximately $0.19 per Mcf in operating expenses to produce our CO2
during 2006, more than our 2005 average of $0.16 per Mcf, principally as a result of higher
oil commodity prices, which results in higher royalty payments, and higher labor, utilities and
equipment rental expense. During 2004, we spent approximately $0.12 per Mcf to produce our
CO2. Our estimated total cost per thousand cubic feet of CO2 during 2006 was
approximately $0.28, after inclusion of depreciation and amortization expense related to the
CO2 production, as compared to approximately $0.25 during 2005.
Man-Made CO2 sources. We entered into an agreement and committed to purchase (if
the plant is built) 100% of the CO2 production from a man-made (anthropogenic) source of
CO2, a planned petroleum coke gasification project scheduled to be completed
in 2010. This Faustina plant, proposed to be located near Donaldsonville, LA, will convert
petroleum coke into ammonia. As a byproduct of the combustion, large quantities of CO2
will be produced, estimated to be around 200 MMcf/d. We plan to use this CO2 in our
tertiary operations program to recover oil. The Faustina agreement allows us to add the potential
equivalent volume of an additional one Tcf of CO2 over the term of our contract.
Construction of this plant has not yet begun, so we are not certain whether this plant will be
built, although it currently appears likely. We are in discussions with several other entities
that are considering other types of coal or petroleum coke gasification plants. The cost of this
man-made CO2 will
35
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
likely be higher than CO2 from our natural source, but the location of these plants
could mitigate some of the incremental cost of transporting CO2 from Jackson Dome.
Further, we see these sources as a possible expansion of natural sources, assuming they are
economical, and we believe that our potential ability to tie these sources together with pipelines
will give us a significant advantage over our competitors in our geographic area in acquiring
additional oil fields and in acquiring these future potential man-made sources of CO2.
Overview of Tertiary Economics. Initially, our tertiary operations were economic at oil
prices below $20 per Bbl, although the economics have always varied by field. Our costs have
escalated during the last few years due to general cost inflation in the industry, raising our
current economic oil price to around $30 per Bbl, again dependent on the specific field. Our
inception-to-date finding and development costs (including future development and abandonment costs
but excluding expenditures on fields without proven reserves) for our tertiary oil fields through
December 31, 2006, are approximately $8.50 per BOE. Currently, we forecast that these costs will
range from $5 to $10 per BOE over the life of each field, depending on the state of a particular
field at the time we begin operations, the amount of potential oil, the proximity to a pipeline or
other facilities, etc. Our operating costs for tertiary operations are expected to range from $13
to $15 per BOE over the life of each field (at todays prices), again depending on the field
itself, however, our 2006 operating costs were in excess of this range.
Oil quality is another significant factor that impacts the economics. In Phase I (Southwest
Mississippi), the light sweet oil produced from our tertiary operations receives near NYMEX prices,
while the average discount to NYMEX for the lower quality oil produced from the fields in Phase II
(East Mississippi), some of which we started flooding during 2006, was $13.51 per BOE during 2006,
a differential that is significantly higher than our corporate historical averages and one that
appears to increase as oil prices increase. See Oil and Natural Gas Revenues below for a further
discussion of our NYMEX differentials.
While these economic factors have wide ranges, our rate of return from these operations has
generally been better than our rate of return on traditional oil and gas operations, and thus our
tertiary operations have become our single most important focus area. While it is extremely
difficult to accurately forecast future production, we do believe that our tertiary recovery
operations provide significant long-term production growth potential at reasonable rates of return,
with relatively low risk, and thus will be the backbone of our Companys growth for the foreseeable
future. Although we believe that our plans and projections are reasonable and achievable, there
could be delays or unforeseen problems in the future that could delay or affect the economics of
our overall tertiary development program. We believe that such delays or price effects, if any,
should only be temporary.
Financial Statement Impact of CO2 Operations. Our increasing emphasis on
CO2 tertiary recovery projects has significantly impacted, and will continue to impact
on our financial results and certain operating statistics.
First, there is a significant delay between the initial capital expenditures and operating
expenses and the resulting production increases, as we must build facilities before CO2
flooding can commence, and it usually takes six to 12 months before the field responds to the
injection of CO2 (i.e., oil production commences) to the injection of CO2.
Further, we may spend significant amounts of capital before we can recognize any proven reserves
from fields we flood (See Analysis of Tertiary Recovery Operations below). Even after a field
has proven reserves, there will usually be significant amounts of additional capital required to
fully develop the field.
Secondly, these tertiary projects are usually 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 near-liquid state for
re-injection purposes). As commodity and energy prices increase, so do our operating expenses in
these fields. Our operating cost during 2006 for our tertiary operations averaged $17.69 per Bbl
for our producing tertiary fields, as compared to an estimated cost of around $12 to $15 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 (including obligations covered by the volumetric production payments sold to
Genesis). Most of our CO2 operating expenses are allocated to our oil fields and
recorded as lease operating expenses on those fields at the time the CO2 is injected.
Since we expense all of the operating costs to produce and inject our CO2, the operating
costs per barrel will be higher at the inception of CO2 injection projects before oil
production is realized in a particular field. Our total corporate operating expenses on a per BOE
basis will likely continue to increase as these operations constitute an increasingly larger
percentage of our operations. Generally, these higher operating costs are somewhat offset by lower
finding and development costs which helps to lower our overall depreciation and depletion rate (see
also Overview of Tertiary Economics above).
36
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Third, our net oil price relative to NYMEX prices may be affected by the oil produced from our
tertiary operations (see Overview of Tertiary Operations above). Currently, all of our current
oil production from tertiary operations is from fields that produce light sweet oil and receive oil
prices close to, and sometimes actually higher than, NYMEX prices. However, the oil produced from
fields that we recently commenced flooding as part of Phase II generally sell at a significant
discount to NYMEX because of the quality of the crude oil there. The relative mix of this
production, coupled with changing market conditions for the various types of crude, can cause our
NYMEX differentials to fluctuate widely.
Analysis
of
CO2
Tertiary Recovery Operating Activities. We currently have tertiary
operations ongoing at Little Creek, Mallalieu, McComb and Brookhaven Fields in Phase I and Soso,
Martinville and Eucutta Fields in Phase II, as well as in various smaller adjacent fields. We
project that our oil production from these operations will increase substantially over the next
several years as we continue to expand this program by adding additional projects and phases. As
of December 31, 2006, we had approximately 62.2 MMBbls of proven oil reserves related to tertiary
operations (51.7 MMBbls of which was in Phase I and the balance in Phase II) and have identified
and estimate significant additional oil potential in other fields that we own in this region. We
initiated CO2 injections at Tinsley Field (Phase III) in January 2007, although in very
limited amounts, with more significant development expected there when the CO2 pipeline
to Tinsley is completed, which we currently anticipate in the
third or fourth quarter of 2007. We also
expect to initiate flooding at Cranfield and Lockhart Crossing Fields in the second half of 2007
(Phase IV).
With regard to our proven tertiary reserves, 2006 was a transition year for us, as we
added only 6.0 MMBbls of tertiary-related proved oil reserves during the year, primarily
incremental oil reserves at McComb and Mallalieu Fields (both Phase I). Previously, we booked most
proven tertiary oil reserves near the start of a project as almost all the oil fields in Phase I
were analogous to Little Creek Field (our first flood) and thus it was not necessary to have an oil
production response to the CO2 injections before they were considered proven.
Conversely, our new floods (after Phase I) are not analogous (for the most part), as the tertiary
floods will be in different geological formations. Therefore for these new phases, there must be
an oil production response to the CO2 injections before we can recognize proven oil
reserves, even though we believe that these formations have a similar risk profile. Since many of
our Phase II projects were delayed during 2006, the production response needed to record any
significant incremental tertiary oil reserves in this new area did not take place. We anticipate
booking significant amounts of proven tertiary oil reserves during 2007 and beyond, although the
magnitude will depend on our progress with Phases III and IV, two areas we plan to initiate during
2007, and the response from our new Phase II projects.
Our average annual oil production from our CO2 tertiary recovery activities has
increased during the last few years, from 3,970 Bbls/d in 2002 to 10,070 Bbls/d during 2006.
Tertiary oil production represented approximately 44% of our total corporate oil production during
2006 and approximately 27% of our total corporate production of both oil and natural gas during the
same period on a BOE basis. We expect that this tertiary related oil production will continue to
increase, although the increases are not always predictable or consistent. During 2006, our
CO2 injections were less than we forecasted due to a series of different types of delays
in obtaining equipment or completing facilities, resulting in a corresponding shortfall between our
forecasted and actual tertiary oil production. These delays are caused by various factors:
difficulties reentering certain injection wells, which has required that some wells be redrilled;
delays in getting certain permits and right-of-ways; and a general tightening of available
materials and equipment in the industry. This temporary fluctuation in oil production does not
indicate any issue with the proved and potential oil reserves recoverable with CO2,
because the historical correlation between oil production and CO2 injections remains
high. For our tertiary oil production, we anticipate a 40% to 50% increase in our average
production rates for 2007 as compared to 2006 levels. A detailed discussion of each of our
tertiary oil fields and the development of each is included on pages 7 9 under Our Tertiary Oil
Fields with Proven Tertiary Reserves. Following is a chart with our tertiary oil production by
field for 2004, 2005 and by quarter for 2006.
37
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Year Ended December 31, |
Tertiary Oil Field |
|
2006 |
|
2006 |
|
2006 |
|
2006 |
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
|
Brookhaven |
|
|
547 |
|
|
|
798 |
|
|
|
965 |
|
|
|
1,014 |
|
|
|
|
833 |
|
|
|
31 |
|
|
|
|
|
Little Creek & Lazy Creek |
|
|
3,006 |
|
|
|
3,056 |
|
|
|
2,623 |
|
|
|
2,279 |
|
|
|
|
2,739 |
|
|
|
3,529 |
|
|
|
3,148 |
|
Mallalieu (East and West) |
|
|
5,219 |
|
|
|
5,385 |
|
|
|
5,243 |
|
|
|
4,994 |
|
|
|
|
5,210 |
|
|
|
4,739 |
|
|
|
3,351 |
|
McComb & Olive |
|
|
932 |
|
|
|
1,062 |
|
|
|
1,242 |
|
|
|
1,467 |
|
|
|
|
1,177 |
|
|
|
908 |
|
|
|
285 |
|
Smithdale |
|
|
54 |
|
|
|
74 |
|
|
|
41 |
|
|
|
63 |
|
|
|
|
58 |
|
|
|
8 |
|
|
|
|
|
Martinville |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
Eucutta |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187 |
|
|
|
|
47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
10,028 |
|
|
|
|
10,070 |
|
|
|
9,215 |
|
|
|
6,784 |
|
|
|
|
|
In addition to higher energy costs to operate our tertiary recycling facilities caused by
higher commodity prices, we have experienced general cost inflation during the last few years. We
also lease a portion of our recycling and plant equipment used in our tertiary operations, which
further increases operating expenses. Over the last four years we have leased certain equipment
that qualifies for operating lease treatment representing an underlying aggregate cost of
approximately $71.4 million as of December 31, 2006. We expect to enter into new leases for
equipment during 2007 and 2008 representing additional underlying costs of approximately $44
million. These leases have been an attractive cost of financing due to their low imputed interest
rates, which are fixed for seven to ten years. During 2006, the cost to produce our CO2
also increased (see CO2 Resources above), all of which resulted in an increase
in our tertiary operating cost per BOE from $12.00 per BOE in 2005 to $17.69 per BOE during 2006.
Included in the 2006 amount is approximately $7.5 million, or approximately $2.04 per BOE, for
operating expenses at three new tertiary floods in Phase II where we commenced operations but have
had only a very limited or no production response to date (initial response is expected late in
2007). The absolute amount of operating expenses related to tertiary operations increased from
$24.6 million during 2004 to $40.4 million during 2005 to $65.0 million during 2006.
Through December 31, 2006, we spent a total of $665.4 million on fields currently being
flooded (including allocated acquisition costs) and received $472.2 million in net cash flow
(revenue less operating expenses and capital expenditures). Of this total, approximately $273.5
million was spent on fields which had little or no proved reserves at December 31, 2006 (i.e.,
significant incremental proved reserves are anticipated during 2007 and beyond). The proved oil reserves in
our CO2 fields have a PV-10 Value of $1.46 billion, using December 31, 2006 constant
NYMEX pricing of $61.05 per Bbl. These amounts do not include the capital costs or related
depreciation and amortization of our CO2 producing properties, but do include CO2
source field lease operating costs and transportation costs. Through December 31, 2006, we
had a balance of approximately $198.7 million of unrecovered net
cash flows for our CO2 assets.
CO2 Related Capital Budget for 2007. Tentatively, we plan to spend approximately
$70 million in 2007 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 2007 for our Phase II properties (East Mississippi) and approximately
$200 million for Phase III properties (Tinsley), plus an additional $70 million for properties in
other phases, making our combined CO2 related expenditures just over 60% of our $650
million 2007 capital budget.
Operating Results
Adjusted cash flow from operations (see discussion below regarding this non-GAAP measure) and
net income have increased each year during the last three years, along with rising commodity
prices. Production declined 10% from 2004 to 2005, primarily related to the sale of our offshore
properties in July 2004 and to a lesser extent due to the hurricanes during 2005, but the effect of
this deferred production was more than offset by higher commodity prices in 2005. Production
increased 23% between 2005 and 2006, which, coupled with high prices, resulted in record annual net
income and cash flow. Included in our 2006 net income is the effect of approximately $7.5 million
of non-cash charges related to the adoption of SFAS No. 123(R) as of January 1, 2006, relating to
certain stock-based compensation that was previously only reflected as a footnote disclosure and
not recorded in the financial statements (See Note 9 to the Consolidated Financial Statements) and
approximately $6.0 million of other
38
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
non-cash stock charges associated with the departure of a senior vice president and retirement of
another vice president, both during 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands Except Per Share Amounts |
|
2006 |
|
2005 |
|
2004 |
|
Net income |
|
$ |
202,457 |
|
|
$ |
166,471 |
|
|
$ |
82,448 |
|
Net income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.74 |
|
|
$ |
1.49 |
|
|
$ |
0.75 |
|
Diluted |
|
|
1.64 |
|
|
|
1.39 |
|
|
|
0.72 |
|
|
Adjusted cash flow from operations |
|
$ |
448,414 |
|
|
$ |
343,383 |
|
|
$ |
200,193 |
|
Net change in assets and liabilities relating to operations |
|
|
13,396 |
|
|
|
17,577 |
|
|
|
(31,541 |
) |
|
Cash flow from operations (GAAP measure) |
|
$ |
461,810 |
|
|
$ |
360,960 |
|
|
$ |
168,652 |
|
|
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, 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. During 2005, we had a $17.6
million increase to our GAAP cash flow from operations resulting from the net change in assets and
liabilities relating to operations. This is primarily due to higher accounts payable and accrued
liabilities associated with increased capital spending levels as compared to the prior year. Our
accrual for production receivables was higher at the end of 2006 than a year earlier, due to higher
oil and natural gas prices, partially offsetting the benefit of higher accounts payable and accrued
liabilities. During 2006, we also had a $13.4 million increase to our GAAP cash flow from
operations resulting from the same items as in 2005; namely higher accounts payable and accrued
liabilities due to the higher spending levels, partially offset by an increase in our accrued
production receivable as a result of the higher production levels in 2006.
39
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Certain of our operating statistics for each of the last three years are set forth in the
following chart:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
AVERAGE DAILY PRODUCTION VOLUMES |
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
22,936 |
|
|
|
20,013 |
|
|
|
19,247 |
|
Mcf/d |
|
|
83,075 |
|
|
|
58,696 |
|
|
|
82,224 |
|
BOE/d (1) |
|
|
36,782 |
|
|
|
29,795 |
|
|
|
32,951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
501,176 |
|
|
$ |
367,414 |
|
|
$ |
256,843 |
|
Natural gas sales |
|
|
215,381 |
|
|
|
181,641 |
|
|
|
187,934 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
716,557 |
|
|
$ |
549,055 |
|
|
$ |
444,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL AND GAS DERIVATIVE CONTRACTS (in thousands) (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense on settlements of derivative contracts |
|
$ |
(5,302 |
) |
|
$ |
(16,761 |
) |
|
$ |
(84,557 |
) |
Non-cash derivative (expense) income |
|
|
25,130 |
|
|
|
(12,201 |
) |
|
|
(1,270 |
) |
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and gas derivative contracts |
|
$ |
19,828 |
|
|
$ |
(28,962 |
) |
|
$ |
(85,827 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
167,271 |
|
|
$ |
108,550 |
|
|
$ |
87,107 |
|
Production taxes and marketing expenses (3) |
|
|
36,351 |
|
|
|
27,582 |
|
|
|
18,737 |
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
203,622 |
|
|
$ |
136,132 |
|
|
$ |
105,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NON-TERTIARY CO2 OPERATING MARGIN (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
9,376 |
|
|
$ |
8,119 |
|
|
$ |
6,276 |
|
CO2 operating expenses |
|
|
3,190 |
|
|
|
2,251 |
|
|
|
1,338 |
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
6,186 |
|
|
$ |
5,868 |
|
|
$ |
4,938 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UNIT PRICES-INCLUDING IMPACT OF DERIVATIVE SETTLEMENTS (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
59.23 |
|
|
$ |
50.30 |
|
|
$ |
27.36 |
|
Gas price per Mcf |
|
|
7.10 |
|
|
|
7.70 |
|
|
|
5.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UNIT PRICES-EXCLUDING IMPACT OF DERIVATIVE SETTLEMENTS (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
59.87 |
|
|
$ |
50.30 |
|
|
$ |
36.46 |
|
Gas price per Mcf |
|
|
7.10 |
|
|
|
8.48 |
|
|
|
6.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
53.37 |
|
|
$ |
50.49 |
|
|
$ |
36.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas lease operating expenses |
|
$ |
12.46 |
|
|
$ |
9.98 |
|
|
$ |
7.22 |
|
Oil and gas production taxes and marketing expenses |
|
|
2.71 |
|
|
|
2.54 |
|
|
|
1.55 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
15.17 |
|
|
$ |
12.52 |
|
|
$ |
8.77 |
|
|
|
|
|
(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 Companys derivative
transactions. Effective January 1, 2005, we elected to discontinue hedge accounting for our
oil and natural gas derivative contracts; see Note 10 to the Consolidated Financial Statements
and Critical Accounting Policies and Estimates Oil and Gas Derivative Contracts below. |
|
(3) |
|
For 2006, 2005 and 2004, includes transportation expenses paid to Genesis of $4.4 million,
$4.0 million and $1.2 million, respectively. |
|
(4) |
|
For 2006, 2005, and 2004 includes deferred revenue of $4.2 million, $3.1 million and $2.4
million respectively, associated with volumetric production payments and transportation income
of $4.6 million, $3.5 million and $2.7 million, respectively, both from Genesis. |
40
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production. Average daily production by area for 2006, 2005 and 2004, and each of the
quarters of 2006 is listed in the following table (BOE/d).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
|
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
Year Ended December 31, |
|
Operating Area |
|
2006 |
|
|
2006 |
|
|
2006 |
|
|
2006 |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
Mississippi non-CO2 floods |
|
|
12,455 |
|
|
|
12,633 |
|
|
|
13,069 |
|
|
|
12,808 |
|
|
|
|
12,743 |
|
|
|
12,072 |
|
|
|
13,085 |
|
Mississippi CO2 floods |
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
10,028 |
|
|
|
|
10,070 |
|
|
|
9,215 |
|
|
|
6,784 |
|
Onshore Louisiana |
|
|
8,349 |
|
|
|
8,623 |
|
|
|
8,221 |
|
|
|
6,572 |
|
|
|
|
7,937 |
|
|
|
6,164 |
|
|
|
7,630 |
|
Barnett Shale |
|
|
3,953 |
|
|
|
4,621 |
|
|
|
4,952 |
|
|
|
5,925 |
|
|
|
|
4,868 |
|
|
|
2,145 |
|
|
|
587 |
|
Alabama |
|
|
917 |
|
|
|
1,213 |
|
|
|
1,215 |
|
|
|
1,243 |
|
|
|
|
1,148 |
|
|
|
19 |
|
|
|
|
|
Other (1) |
|
|
22 |
|
|
|
9 |
|
|
|
(10 |
) |
|
|
43 |
|
|
|
|
16 |
|
|
|
180 |
|
|
|
|
|
|
|
|
|
|
|
Total production excl. offshore |
|
|
35,454 |
|
|
|
37,474 |
|
|
|
37,561 |
|
|
|
36,619 |
|
|
|
|
36,782 |
|
|
|
29,795 |
|
|
|
28,086 |
|
Offshore Gulf of Mexico Sold July 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,865 |
|
|
|
|
|
|
|
Total Company |
|
|
35,454 |
|
|
|
37,474 |
|
|
|
37,561 |
|
|
|
36,619 |
|
|
|
|
36,782 |
|
|
|
29,795 |
|
|
|
32,951 |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Primarily represents production from an offshore property retained from the sale
in July 2004. |
As outlined in the above table, average production in 2006 increased 23% (6,987 BOE/d) over
2005 levels. The third quarter of 2005 was negatively affected by Hurricanes Katrina and Rita, as
approximately 1,100 BOE/d is estimated as having been deferred during that period. If last years
average production is adjusted to include this deferred production, the average production increase
between the two years would be reduced to approximately 19%. Of this adjusted annual increase, the
January 2006 acquisition contributed approximately 2,148 BOE/d of the increase (36%) with 1,122
BOE/d attributable to the Mississippi non-CO2 floods and 1,026 BOE/d to Alabama
fields, although a small portion of that increase was from our internal development efforts
following the acquisition.
Production in the Mississippi non-CO2 floods area declined only modestly during
2006 (before giving effect to the January 2006 acquisition related increase noted above) and also
during 2005. Recent drilling activity in the Heidelberg Selma Chalk (natural gas) has helped
offset the gradual declines in oil production during 2006 and 2005.
See CO2 Operations above for a discussion of the tertiary related production.
Our onshore Louisiana production for 2006 increased 1,773 BOE/d (29% increase) over the prior
years level, due primarily to production increases at Thornwell and South Chauvin Fields as a
result of 2005 and 2006 drilling activity in that area. We drilled 15 successful wells during
2005, which boosted the production levels in early 2006. However, our Louisiana production is
currently declining, as evidenced by the decline between the third and fourth quarters of 2006, as
a result of depletion with insufficient new production to offset it as our 2006 success rate was
not as good as it had been during 2005. Since our budget for 2007 has been reduced in this area,
it is unlikely that our production here will increase during 2007. Our Louisiana properties are
generally shorter-lived properties than our properties in most other areas, and therefore decline
rather rapidly, requiring a consistent increase in new production in order to maintain production
levels.
Our production in the Barnett Shale area during 2006 increased 2,723 BOE/d (127% increase)
over our 2005 level, also as a result of increased drilling activity, with 46 wells drilled during
2006, as compared to 23 wells drilled during 2005. Production from this area has increased every
quarter during the last two years, with additional modest increases expected during most of 2007 as
we plan to drill 35 to 40 wells in this area during 2007, although this upward trend will not
continue indefinitely. These wells are characterized by steep decline rates in their first year of
production (as much as 50% to 60%), followed by a gradual leveling-off of production and a
resultant slow decline rate, giving them an overall long production life.
41
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
As a result of the sale of our offshore properties in July 2004, total production decreased
between fiscal year-ends 2004 and 2005. If 2004 is adjusted to exclude offshore production,
overall production increased approximately 6% on a BOE/d basis during 2005, anchored by the
increased production from our tertiary operations and from our Barnett Shale play, generally offset
by overall declines in production from our onshore conventional properties in Mississippi and
natural gas wells in Louisiana.
Our production for 2006 was weighted toward oil (62%) compared to 67% in 2005 and 58% in 2004,
and we expect a similar weighting toward oil in 2007 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, primarily as a result of higher commodity prices, offset in part in 2005 by lower
production as a result of our 2004 sale of offshore properties, but supplemented in 2006 by a 23%
increase in production levels. Between fiscal year-end 2005 and 2006, revenues increased by 31%.
The 23% increase in production in 2006, as compared to production in 2005, increased oil and
natural gas revenues by $128.8 million (77% of the total revenue increase) and the 6% higher
overall commodity prices in 2006 (on a BOE basis) further increased revenue by $38.7 million (23%
of the total revenue increase). Between 2004 and 2005, revenues increased by 23%. The overall
increase in commodity prices contributed $148.0 million in additional revenues, (142% of the
increase); partially offset by an overall decrease in revenues of $43.7 million (a negative 42% of
the total revenue increase) related to the 10% lower production volumes.
Our net average realized crude oil price has increased each year, averaging 18% higher in 2006
over 2005 levels and 84% higher in 2005 over 2004 levels. Our net average realized natural gas
price decreased 8% in 2006 as compared to 2005 levels, but the average price in 2005 was 38% higher
than during 2004. On a weighted average net price per BOE, the increases in oil prices have more
than offset the less consistent natural gas prices, resulting in a 6% increase in 2006 price levels
as compared to 2005 prices and a 37% increase in 2005 prices as compared to 2004 levels.
Our net revenue is also affected by the difference between our net average price and the NYMEX
quoted price (i.e., the NYMEX differential). During 2004 and continuing into 2005 and 2006, the
discount for our heavier, sour crude (which predominantly applies to our Eastern Mississippi
production) increased significantly, lowering our overall net price relative to NYMEX. Our net oil
price averaged $4.91 below NYMEX during 2004, increased to $6.33 during 2005, and further increased
to $6.41 during 2006. This occurred in spite of our increasing light sweet oil production from our
Phase I tertiary operations, which should have improved our overall net price as such crude
receives near NYMEX prices and is becoming a higher percentage of our overall production. However,
as evident in 2005 and 2006, the oil market is subject to significant and sudden changes and it is
difficult to forecast these trends, although our experience indicates that the discount or NYMEX
differential for our heavier sour crude increases as NYMEX oil prices increase.
Our net natural gas prices relative to NYMEX fluctuate primarily as a result of the trend in
the NYMEX prices during the month. Since most of our natural gas is sold on an index price that is
set near the first of each month, the variance will decrease if NYMEX natural gas prices
consistently decrease during the quarter and the opposite is true if prices are increasing. Our
natural gas differentials relative to NYMEX improved in 2006 as compared to 2005, primarily due to
decreasing natural gas prices throughout most of the year, but the opposite was true during 2005,
when prices were generally rising. During 2006 our natural gas price averaged $0.13 above NYMEX,
during 2005 we had an average discount to NYMEX of $0.49, and during 2004 we had an average premium
of $0.02 to NYMEX. The NYMEX differential can also vary by area and our natural gas in the Barnett
Shale area has a higher discount to NYMEX than the natural gas in Louisiana. Since our production
in the Barnett area is growing and expected to increase again during 2007, while our Louisiana
natural gas is generally declining, if prices remain consistent, we would expect our discount to
NYMEX to gradually increase.
Oil and natural gas derivative contracts. During 2006, we made payments on our derivative
contracts of $5.3 million, related to oil swaps put in place in late 2005 to protect the rate of
return on the fields acquired in January 2006. These payments lowered our effective net oil price
received in 2006 by $0.64 per Bbl. During 2005, we made payments on our derivative contracts of
$16.8 million, down from $84.6 million paid out during the prior year. Our 2005 payments related to
a natural gas collar, lowering our effective net natural gas price by $0.78 per Mcf. During 2004,
we paid out $64.1 million on our derivative contracts ($9.10 per Bbl) and $20.4 million ($0.68
42
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
per Mcf) on our natural gas derivative contracts relating to swaps and collars we purchased one to
two years earlier when commodity prices were lower. About $30.5 million of the payments related to
swaps originally put in place to protect the rate of return for the COHO acquisition in August
2002.
Changing commodity prices cause fluctuations in the mark-to-market value adjustments of our
derivative contracts. We recognized a non-cash gain of $25.1 million in 2006 as a result of the
decreasing prices, primarily related to the 75 MMcf/d of natural gas swaps for calendar 2007 that
we entered into during December 2006. During 2005, because of our decision to abandon hedge
accounting as of January 1, 2005, we recognized a non-cash expense of $12.2 million primarily
related to the amortization of the fair value of the derivative contracts in place as of January 1,
2005 over the remaining life of the contracts, which was generally 2005. During 2004, we
recognized only $1.3 million of mark-to-market non-cash value adjustments as we were following
hedge accounting prior to January 1, 2005. See also Market Risk Management.
Operating Expenses. Our lease operating expenses have increased each year on both a per BOE
basis and in absolute dollars primarily as a result of (i) our increasing emphasis on tertiary
operations (see discussion of those expenses under CO2 Operations above), (ii) general
cost inflation in our industry, (iii) increased personnel and related costs, (iv) higher fuel and
energy costs to operate our properties, (v) increasing lease payments for certain of our tertiary
operating facilities and equipment, and (vi) higher workover costs. The adoption of SFAS No.
123(R) effective January 1, 2006 (see Overview Operating results) also added approximately $1.5
million of non-cash charges to 2006 operating expenses, representing the stock compensation expense
pertaining to operating personnel.
During 2006, operating costs averaged $12.46 per BOE, up from $9.98 per BOE in 2005 and $7.22
per BOE during 2004. Operating expenses of our tertiary operations increased from $24.6 million in
2004 to $40.4 million during 2005 and $65.0 million during 2006, as a result of increased tertiary
activity. Tertiary operating expenses were particularly impacted by higher power and energy costs,
higher costs for CO2 and payments on leased facilities and equipment (see
CO2 Operations above). We expect this increase in tertiary operating costs to
continue and to further increase our cost per BOE as these costs become a more significant portion
of our total production and operations.
Workover expenses increased by over $11.5 million during 2006 as compared to 2005 levels, with
over one-half of the increase relating to costs incurred on fields acquired during the year to
bring them up to our operating standard. Workover expenses were higher in 2005 than in 2004
primarily due to expenses to repair a mechanical failure on one onshore Louisiana well.
Production taxes and marketing expenses generally change in proportion to commodity prices and
therefore have been higher in each of the last three years along with the increasing commodity
prices. The sale of our offshore properties in 2004 also contributed to the increase in production
taxes and marketing expenses on a per BOE basis during 2005 and 2006, as most of our offshore
properties were exempt from severance taxes.
General and Administrative Expenses
During the last three years, general and administrative (G&A) expenses have increased on both
a gross and per BOE basis as outlined below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands Except Per BOE and Employee Data |
|
2006 |
|
2005 |
|
2004 |
|
Gross G&A expense |
|
$ |
94,095 |
|
|
$ |
64,622 |
|
|
$ |
53,658 |
|
State franchise taxes |
|
|
1,825 |
|
|
|
1,454 |
|
|
|
923 |
|
Operator labor and overhead recovery charges |
|
|
(45,283 |
) |
|
|
(32,452 |
) |
|
|
(28,048 |
) |
Capitalized exploration expense |
|
|
(7,623 |
) |
|
|
(5,084 |
) |
|
|
(5,072 |
) |
|
Net G&A expense |
|
$ |
43,014 |
|
|
$ |
28,540 |
|
|
$ |
21,461 |
|
|
Average G&A expense per BOE |
|
$ |
3.20 |
|
|
$ |
2.62 |
|
|
$ |
1.78 |
|
Employees as of December 31 |
|
|
596 |
|
|
|
460 |
|
|
|
380 |
|
|
43
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Gross G&A expenses increased $29.5 million, or 46%, between 2005 and 2006 and $11.0
million, or 20%, between 2004 and 2005. The single biggest increase during 2006 was due to the
adoption of SFAS No. 123(R) in January 2006, which increased gross G&A expense by approximately
$8.9 million during the year, representing the non-cash charge for stock compensation (stock
options and stock appreciation rights) pertaining to personnel charged to G&A. In addition, 2006
expenses include approximately $3.5 million of non-cash compensation expense associated with the
amortization of deferred compensation resulting from the issuance of restricted stock to officers
and directors during 2004 which was already being expensed prior to the adoption of SFAS No.
123(R). During 2006, we also incurred a $5.3 million charge to earnings related to the
modification of the vesting terms of certain restricted stock and stock options previously granted
to our former Senior Vice-President of Operations, associated with his departure, and the expensing
of approximately $750,000 related to the retirement of our Vice President of Marketing.
G&A also increased because of higher compensation costs due to additional employees,
associated expenses and wage increases. During 2006 we had a net increase of 30% in our employee
count related to our acquisitions and increased activity level and a 21% increase during the prior
year. In addition, due to increased competitive pressures in the industry, our wages are
increasing at a rate higher than general inflation and we expect this trend to continue. As an
example, in 2006 we granted a 5% mid-year pay raise to all employees in order to remain competitive
with industry compensation levels.
During 2005, we incurred approximately $1.4 million to provide food, water, gasoline, and
other essential supplies to our employees and charitable organizations in Mississippi and Louisiana
following the hurricanes. In addition, we have had higher professional service and consultant fees
during 2005, primarily related to Sarbanes-Oxley compliance, investigation of hotline reports, and
documentation and testing of our new software system that we began using in January 2005, as well
as increased maintenance costs as a result of the change to our new software system. Many of these
expenses were also applicable in 2006. These 2005 increases were offset by the absence of
approximately $2.4 million of employee severance payments paid in 2004 related to the sale of our
offshore properties in July 2004.
Higher operator overhead recovery charges resulting from 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, drilling activity during the past year, and increased compensation expense (including
the allocation of stock compensation to lease operating expense) the
amount we recovered as operator labor and overhead charges increased by 40% between 2005 and 2006 and 16%
between 2004 and 2005. Capitalized exploration costs increased in 2006 as compared to 2005
primarily due to increased compensation costs, most of which related to the expensing of stock
based compensation associated with the adoption of SFAS
No. 123(R). Capitalized exploration costs were relatively unchanged between 2005 and 2004 as the personnel reductions associated with the sale of
our offshore properties in July 2004 offset the other increases. The net effect of the increases
in gross G&A expenses, operator overhead recoveries and capitalized exploration costs was a 51%
increase in net G&A expense between 2005 and 2006 and a 33% increase between 2004 and 2005.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands Except Per BOE Data |
|
2006 |
|
2005 |
|
2004 |
|
Cash interest expense |
|
$ |
33,787 |
|
|
$ |
18,800 |
|
|
$ |
18,506 |
|
Non-cash interest expense |
|
|
1,121 |
|
|
|
827 |
|
|
|
962 |
|
Less: Capitalized interest |
|
|
(11,333 |
) |
|
|
(1,649 |
) |
|
|
|
|
|
Interest expense |
|
$ |
23,575 |
|
|
$ |
17,978 |
|
|
$ |
19,468 |
|
|
Interest and other income |
|
$ |
5,603 |
|
|
$ |
3,218 |
|
|
$ |
2,388 |
|
|
Average net cash interest expense per BOE (1) |
|
$ |
1.26 |
|
|
$ |
1.28 |
|
|
$ |
1.34 |
|
Average debt outstanding |
|
$ |
455,603 |
|
|
$ |
248,825 |
|
|
$ |
270,770 |
|
Average interest rate (2) |
|
|
7.4 |
% |
|
|
7.6 |
% |
|
|
6.8 |
% |
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest and other income on a BOE basis. |
|
(2) |
|
Includes commitment fees but excludes amortization of debt issue costs. |
44
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Interest expense increased in 2006, primarily due to substantially higher average debt levels
offset in part by higher interest capitalized on our significant unevaluated properties, primarily
related to our 2006 acquisitions. Debt levels were unusually low in the first half of 2005
following the sale of our offshore properties in mid-2004. Conversely, debt levels increased in
the first quarter of 2006 following the $250 million acquisition which closed at the end of January
2006, funded by $150 million of subordinated debt issued in December 2005 and $100 million of bank
debt borrowed at closing. The bank debt was repaid in April 2006 with the proceeds from an equity
sale made that month (see Overview April 2006 Equity Offering), but an additional $50 million
was subsequently borrowed to fund the Delhi acquisition in May 2006 (see Overview Recent
Acquisitions) and an additional $84 million for general working capital and the payment of the
option on Hastings Field entered into in November 2006, leaving us with total bank debt of $134
million as of December 31, 2006.
Interest expense for 2005 decreased from 2004 levels primarily due to capitalized interest of
$1.6 million relating to the construction of our CO2 pipeline to East Mississippi and
the payoff of our bank debt in the third quarter of 2004 with the proceeds from our offshore
property sale. As a result of lower production because of our 2004 offshore sale and production
deferred as a result of the two hurricanes, interest expense on a per BOE basis was not as positive
as it was on an absolute basis.
Depletion, Depreciation and Amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands, Except Per BOE Data |
|
2006 |
|
2005 |
|
2004 |
|
Depletion and depreciation of oil and natural gas properties |
|
$ |
132,880 |
|
|
$ |
88,949 |
|
|
$ |
88,505 |
|
Depletion
and depreciation of CO2 assets |
|
|
8,375 |
|
|
|
5,334 |
|
|
|
4,664 |
|
Asset retirement obligations |
|
|
2,389 |
|
|
|
1,682 |
|
|
|
2,408 |
|
Depreciation of other fixed assets |
|
|
5,521 |
|
|
|
2,837 |
|
|
|
1,950 |
|
|
Total DD&A |
|
$ |
149,165 |
|
|
$ |
98,802 |
|
|
$ |
97,527 |
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
10.08 |
|
|
$ |
8.34 |
|
|
$ |
7.54 |
|
CO2 assets and other fixed assets |
|
|
1.03 |
|
|
|
0.75 |
|
|
|
0.55 |
|
|
Total DD&A cost per BOE |
|
$ |
11.11 |
|
|
$ |
9.09 |
|
|
$ |
8.09 |
|
|
Our proved reserves increased from 129.4 MMBOE as of December 31, 2004, to 152.6 MMBOE as
of December 31, 2005, and further increased to 174.3 MMBOE as of December 31, 2006. Reserve
quantities and associated production are only one side of the DD&A equation, with capital
expenditures less accumulated depletion, asset retirement obligations less related salvage value,
and projected future development costs making up the remainder of the calculation.
We adjust our DD&A rate each quarter for significant 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 increased 22% between fiscal year-end 2005 and 2006, largely because we did not add
many tertiary oil reserves during 2006, which historically have had a lower finding and development
cost than our overall company average. We added approximately 17.8 MMBOE of reserves in the
Barnett Shale during 2006 and approximately 6.0 MMBOE in our tertiary oil properties and only minor
amounts elsewhere. Further, costs continued to climb in the industry throughout 2006, causing us
not only to exceed our cost estimates on our 2006 projects, but also to re-evaluate and raise our
future development costs on our proved undeveloped reserves. Lastly, we did not have any
significant discoveries in our exploration program in Louisiana, which further contributed to an
increase in our DD&A rate.
In general, 2006 was a transition year for us with regard to our tertiary oil reserves. Prior
to 2006, many of our tertiary floods could be considered proven near the start of a project as they
were analogous to Little Creek Field (an already-producing substantial tertiary flood) and thus it
was not necessary to have a production response to CO2 injections before we recognized
proved reserves. Conversely, most of our new floods, including two that we started during 2006
(Soso and Martinville Fields), are not analogous and thus must have an oil production response to
the CO2 injections before we can recognize tertiary proved oil reserves in these fields,
even though we believe there is a similar risk profile in flooding these fields. Due to several
delays throughout the year, the Soso and Martinville floods were completed so late in 2006 that
there was not a significant production response before year-end, a pre-condition to booking proved
reserves in these fields.
45
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
We allocated approximately $124 million of our $250 million January 2006 acquisition costs and
virtually all of the second quarter 2006 $50 million Delhi acquisition costs to unevaluated
properties to reflect the significant potential reserves that we considered to be part of these
acquisitions. As a result, these acquisitions did not materially affect our overall DD&A rate, as
the amount included in our full cost pool was a cost per BOE relatively consistent with our overall
DD&A rate.
Our DD&A rate on a per BOE basis increased 12% between 2004 and 2005, primarily due to rising
costs and increases in capital spending. During 2005, we spent approximately $71.0 million on
acquisitions, of which approximately $50.1 million was included in our full cost pool, with the
balance becoming part of our unevaluated properties. Due to high commodity prices, our acquisition
costs per BOE was around $14.60 per BOE, contributing to the higher DD&A rate. In addition, most
of our future development cost estimates on our proved undeveloped reserves have been increased to
reflect the rising costs in the industry.
Our DD&A rate for our CO2 and other fixed assets has increased in both 2005 and
2006 as a result of the Free State CO2 pipeline to eastern Mississippi, which went into
service late in the first quarter of 2006, additional costs incurred drilling CO2 wells
during each year and higher associated future development costs, partially offset by an increase in
CO2 reserves from 2.7 Tcf as of December 31, 2004, to 4.6 Tcf as of December 31, 2005,
to 5.5 Tcf as of December 31, 2006 (100% working interest basis before amounts attributable to
Genesis volumetric production payments see CO2 Operations CO2
Resources).
As part of the requirements of Statement of Financial Accounting Standards (SFAS) No. 143,
Accounting for Asset Retirement Obligations, the fair value of a liability for an asset retirement
obligation is recorded in the period in which it is incurred, discounted to its present value using
our credit adjusted risk-free interest rate, with a corresponding capitalized amount. The
liability is accreted each period, and the capitalized cost is depreciated over the useful life of
the related asset. On an undiscounted basis, we estimated our retirement obligations as of
December 31, 2004, to be $52.1 million ($21.5 million present value), with an estimated salvage
value of $43.6 million, on an undiscounted basis. As of December 31, 2005, we estimated our
retirement obligations to be $69.1 million ($27.1 million present value), with an estimated salvage
value of $50.2 million. As of December 31, 2006, we estimated our retirement obligations to be
$91.3 million ($41.1 million present value), with an estimated salvage value of $60.0 million, the
increase related to our increased activity and higher cost estimates due to the inflation in our
industry. 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 2004, 2005 or 2006.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands, Except Per BOE Amounts |
|
2006 |
|
2005 |
|
2004 |
|
Current income tax expense |
|
$ |
19,865 |
|
|
$ |
27,177 |
|
|
$ |
22,929 |
|
Deferred income tax provision |
|
|
107,252 |
|
|
|
54,393 |
|
|
|
16,463 |
|
|
Total income tax provision |
|
$ |
127,117 |
|
|
$ |
81,570 |
|
|
$ |
39,392 |
|
|
Average income tax provision per BOE |
|
$ |
9.47 |
|
|
$ |
7.50 |
|
|
$ |
3.27 |
|
Net effective tax rate |
|
|
38.6 |
% |
|
|
32.9 |
% |
|
|
32.3 |
% |
Total net deferred tax asset (liability) |
|
$ |
(229,925 |
) |
|
$ |
(129,474 |
) |
|
$ |
(71,936 |
) |
|
Our income tax provision for all three periods was based on an estimated statutory tax
rate of approximately 39%. For 2004 and 2005, our net effective tax rate was lower than the
statutory rate primarily due to the recognition of enhanced oil recovery credits (EOR) which
lowered our overall tax expense. For 2006, we did not earn any additional EOR credits because of
the high oil prices during 2005, which completely phased out our ability to earn any additional
credits. Under the recently adopted accounting rules of SFAS No. 123(R), a tax benefit, if any,
for compensation expenses arising from the issuance of incentive stock options (the majority of our
options issued prior to 2006) is not recognizable during the vesting period, the period during
which they are expensed for book purposes, which also caused a slight increase in our effective tax
rate in 2006. During the third quarter of 2004, we recognized
46
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 that existed at that time. We no longer have any net operating loss
carryforwards.
In all three periods, the current income tax expense represents our anticipated alternative
minimum cash taxes that we cannot offset with EOR credits. As of December 31, 2006, we had an
estimated $41.9 million of EOR credit carryforwards that we can utilize to reduce a portion of our
cash taxes. These EOR credits do not begin to expire until 2020. Since the ability to earn
additional enhanced oil recovery credits is reduced or even eliminated based on the level of oil
prices, we do not expect to earn any EOR credits during 2007 because of the high oil prices during
2006. If oil prices remain at current levels or increase further in the future, we will not earn
any additional EOR credits and once our existing EOR credits are utilized, our cash taxes will also
increase.
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 |
|
2006 |
|
2005 |
|
2004 |
|
Oil and natural gas revenues |
|
$ |
53.37 |
|
|
$ |
50.49 |
|
|
$ |
36.88 |
|
Loss on settlements of derivative contracts |
|
|
(0.39 |
) |
|
|
(1.54 |
) |
|
|
(7.01 |
) |
Lease operating expenses |
|
|
(12.46 |
) |
|
|
(9.98 |
) |
|
|
(7.22 |
) |
Production taxes and marketing expenses |
|
|
(2.71 |
) |
|
|
(2.54 |
) |
|
|
(1.55 |
) |
|
Production netback |
|
|
37.81 |
|
|
|
36.43 |
|
|
|
21.10 |
|
Non-tertiary CO2 operating margin |
|
|
0.46 |
|
|
|
0.54 |
|
|
|
0.41 |
|
General and administrative expenses |
|
|
(3.20 |
) |
|
|
(2.62 |
) |
|
|
(1.78 |
) |
Net cash interest expense |
|
|
(1.26 |
) |
|
|
(1.28 |
) |
|
|
(1.34 |
) |
Current income taxes and other |
|
|
(0.41 |
) |
|
|
(1.50 |
) |
|
|
(1.78 |
) |
Changes in assets and liabilities relating to operations |
|
|
1.00 |
|
|
|
1.62 |
|
|
|
(2.63 |
) |
|
Cash flow from operations |
|
|
34.40 |
|
|
|
33.19 |
|
|
|
13.98 |
|
DD&A |
|
|
(11.11 |
) |
|
|
(9.09 |
) |
|
|
(8.09 |
) |
Deferred income taxes |
|
|
(7.99 |
) |
|
|
(5.00 |
) |
|
|
(1.37 |
) |
Non-cash derivative adjustments |
|
|
1.87 |
|
|
|
(1.12 |
) |
|
|
(0.11 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
(2.09 |
) |
|
|
(2.67 |
) |
|
|
2.43 |
|
|
Net income |
|
$ |
15.08 |
|
|
$ |
15.31 |
|
|
$ |
6.84 |
|
|
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
$134 million of bank debt outstanding as of December 31, 2006, and $150 million outstanding at
February 28, 2007. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity Dates |
|
Carrying |
|
Fair |
Amounts in Thousands |
|
2006-2011 |
|
Value |
|
Value |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
Senior Subordinated Notes due 2013, net of discount |
|
$ |
|
|
|
$ |
223,786 |
|
|
$ |
227,250 |
|
(The interest rate on the subordinated debt is a fixed rate of 7.5%.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Subordinated Notes due 2015 |
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
152,250 |
|
(The interest rate on the subordinated debt is a fixed rate of 7.5%.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
47
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
From time to time, we enter into various derivative contracts to provide an economic hedge of
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 consisted of price floors, collars and fixed price swaps. Historically, we hedged
up to 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. Since 2005 and beyond, we have entered into fewer derivative contracts,
primarily because of our strong financial position resulting from our lower levels of debt relative
to our cash flow from operations. We did make an exception in late 2006 when we swapped 80% to 90%
of our forecasted 2007 natural gas production at a weighted average price of $7.96 per Mcf. We did
this to protect our 2007 projected cash flow primarily because we currently plan to spend $200
million to $250 million more than we expect to generate in cash flow from operations (see Capital
Resources and Liquidity) and we did not want to be exposed to the risk of lower natural gas
prices. These natural gas swaps had increased in value significantly during the short time we held
them in 2006 (see value discussion below), although by February 23, 2007, this positive market
value was virtually gone as natural gas prices rebounded during the first part of 2007.
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. As of December
31, 2006, we had derivative contracts in place related to our $250 million acquisition that closed
on January 31, 2006, on which we entered into contracts to cover 100% of the estimated proved
producing production at the time we signed the purchase and sale agreement. While these derivative
contracts related to the acquisition represent approximately 7% of our estimated 2007 production,
they are intended to help protect our acquisition economics related to the first three years of
production from the proved producing reserves that we acquired. These swaps cover 2,000 Bbls/d for
2007 at a price of $58.93 per Bbl; and 2,000 Bbls/d for 2008 at a price of $57.34 per Bbl.
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 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
derivative contract positions at year-end 2006, see Note 10 to the Consolidated Financial
Statements.
Effective January 1, 2005, for accounting purposes, we elected to de-designate our existing
derivative contracts as hedges and began to account for them as speculative contracts. 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
ineffective portion to earnings. During 2005, we amortized the December 31, 2004 balance in
Accumulated Other Comprehensive Loss to earnings as that was the remaining life of those contracts.
Information regarding our current derivative contract positions and results of our historical
derivative activity is included in Note 10 to the Consolidated Financial Statements.
At December 31, 2006, our derivative contracts were recorded at their fair value, which was a
net asset of approximately $15.7 million, an increase of $25.1 million from the $9.4 million fair
value liability recorded as of December 31, 2005. This change is the result of lower commodity
prices, primarily relating to our natural gas hedges for 2007 (see above). During 2006, we
recognized total income related to our hedge contracts of $19.8 million, consisting of $5.3 million
of cash payments on settlements of expired contracts and $25.1 million of income relating to
market-to-market non-cash adjustments.
Based on NYMEX crude oil futures prices at December 31, 2006, we would expect to make future
cash payments of $11.7 million on our crude oil commodity derivative contracts. If crude oil
futures prices were to decline by 10%, we would expect to make future cash payments on our crude
oil commodity derivative contracts of $2.1 million, and if futures prices were to increase by 10%
we would expect to pay $21.4 million. Based on NYMEX natural gas futures prices at December 31,
2006, we would expect to receive future cash payments of $26.5 million on our natural gas commodity
hedges. If natural gas futures prices were to decline by 10%, the amount we would expect to
receive under our natural gas commodity hedges would increase to $45.6 million, and if future
prices were to increase by 10% we would expect to receive $7.3 million.
48
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 the net book value of 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 10% using commodity prices in effect at the end of
the reporting period. The financial results for a given period could be substantially different
depending on the method of accounting that 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, Denburys annual revisions to its reserve
estimates have averaged approximately 2% of the previous years estimates and have been both
positive and negative.
Changes in commodity prices also affect our reserve quantities. During 2004, 2005 and 2006,
the change to reserve quantities related to commodity prices was relatively small, less than in
prior years, as prices were relatively high each year-end. 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 2006 DD&A rate from $11.60 per Bbl
to approximately $11.12 per Bbl and a 5% decrease in our proved reserve quantities would have
increased our DD&A rate to approximately $12.13 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.
49
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 two
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 are usually 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 during
the last three year-ends. (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. See also discussion of
requirements to book proven tertiary oil reserves at Results of Operations Depletion,
Depreciation and Amortization.
Asset Retirement Obligations
We have significant obligations related to the plugging and abandonment of our oil and gas
wells, 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.
Accounting for Tertiary Injection Costs
We expense at the time of injection our costs associated with the CO2 we use in our
tertiary recovery operations. Our costs associated with the CO2 we produce and inject
are principally our costs to produce, transport and pay royalties. There are other acceptable
alternatives in accounting for tertiary injectant costs, such as capitalizing these costs as oil
and gas properties and depleting them over time, or expensing a portion and deferring a portion of
the cost if the injectant material can be recovered and sold at a later time. Our decision to
expense our tertiary injectant costs at the time of injection results in greater expense to us at
the onset of a new tertiary recovery project as we may inject CO2 for several months
before we experience any production response. Also, the injection of CO2 will generally
be higher in the earlier portions of the life of the project and will gradually decrease over time.
We expensed costs for the CO2 we injected of $18.1 million in 2006, $10.1 million in
2005, and $4.6 million in 2004.
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 2005, net operating loss carry
forwards. 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
50
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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, 2006 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%
increase in our effective tax rate would have increased our calculated income tax expense by
approximately $3.3 million, $2.5 million, and $1.2 million for the years ended December 31, 2006,
2005 and 2004. See Note 7 to the Consolidated Financial Statements for further information
concerning our income taxes.
Oil and Gas Derivative Contracts
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. Under SFAS No. 133, every
derivative instrument is 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
accumulated other comprehensive income (equity) to the extent that the hedge is effective and in
the income statement to the extent it is ineffective.
Prior to 2005, we applied hedge accounting to our commodity derivative contracts, thereby
recording a significant portion of the fair value changes to equity instead of income. We
recognized losses on ineffectiveness on our hedges of $2.7 million for 2004. We measured and
computed hedge effectiveness on a quarterly basis. If a hedging instrument became ineffective,
hedge accounting was discontinued and any deferred gains or losses on the cash flow hedge remained
in accumulated other comprehensive income until the periods during which the hedges would have
otherwise expired. If we determined it probable that a hedged forecasted transaction will not
occur, deferred gains or losses on the hedging instrument were recognized in earnings immediately.
As of January 1, 2005, we abandoned hedge accounting. 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 the effective portion to other comprehensive income and the balance to
earnings. While we may experience more volatility in our net income than if we had continued to
apply hedge accounting treatment as permitted by SFAS No. 133, we believe that for us the benefits
associated with applying hedge accounting do not outweigh the cost, time and effort to comply with
hedge accounting. During 2006 and 2005, we recognized expense (income) of ($25.1) million and $4.5
million, respectively, related to changes in the fair market value of our derivative contracts.
For 2004, if we had not chosen to designate hedge accounting treatment to our oil and natural gas
derivative contracts, or if none of our derivative contracts had qualified for hedge accounting
treatment, we estimate that our net income would have increased by approximately $25.0 million.
Stock Compensation Plans
Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No.
123(R), Share-Based Payment using the modified prospective application method described in the
statement. Among other items, SFAS 123(R) eliminates the use of APB 25 and the intrinsic value
method of accounting, and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of those awards, in
the financial statements. Under the modified prospective application method, effective January 1,
2006, we began to recognize compensation expense for the unvested portion of awards outstanding as
of December 31, 2005, over the remaining service periods, and for new awards granted or modified
after January 1, 2006.
We estimate the fair value of stock option or stock appreciation right (SAR) awards on the
date of grant using the Black-Scholes option pricing model. The Black-Scholes option valuation
model requires the input of somewhat subjective assumptions, including expected stock price
volatility and expected term. Other assumptions required for estimating fair value with the
Black-Scholes model are the expected risk-free interest rate and expected dividend yield of the
Companys stock. The risk-free interest rates used are the U.S. Treasury yield for bonds
51
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
matching the expected term of the option on the date of grant. Our dividend yield is zero, as
Denbury does not pay a dividend. We utilize historical experience in arriving at our assumptions
for volatility and expected term inputs.
We recognize the stock-based compensation expense on a straight-line basis over the requisite
service period for the entire award. The expense we recognize is net of estimated forfeitures. We
estimate our forfeiture rate based on prior experience and true it up for actual results as the
awards vest. As of December 31, 2006, there was $11.9 million of total compensation cost to be
recognized in future periods related to non-vested stock options and SARs. The cost is expected to
be recognized over a weighted-average period of 1.2 years.
Use of Estimates
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
In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes
(FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with SFAS No. 109, Accounting for Income Taxes.
This interpretation prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to be taken in a tax
return. FIN 48 requires recognition of the impact of a tax position in the Companys financial
statements if that position is more likely than not of being sustained on audit, based on the
technical merits of the position. FIN 48 also provides guidance on derecognition, classification,
interest and penalties, accounting in interim periods, disclosure and transition. The provisions
of FIN 48 are effective as of the beginning of the Companys 2007 fiscal year, with the cumulative
effect of the change in accounting principle recorded as an adjustment to opening retained
earnings. We are still evaluating the potential impact of this interpretation on the Companys
financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157
defines fair value, establishes a framework for measuring fair value in accordance with accounting
principles generally accepted in the United States, and expands disclosures about fair value
measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with
earlier application encouraged. Any amounts recognized upon adoption as a cumulative effect
adjustment will be recorded to the opening balance of retained earnings in the year of adoption.
We have not yet determined the impact of this Statement on the Companys 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 Managements 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 or
forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values,
potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based on
current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values,
competition, long-term forecasts of production, finding cost, rates of return, estimated costs or
changes in 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 managements current plans,
expectations, estimates and assumptions and is subject to a number of risks and uncertainties that
could significantly affect current plans, anticipated actions,
52
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
the timing of such actions and the Companys 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 Companys 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 Companys 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
Managements Discussion and Analysis of Financial Condition and Results of Operations, appearing
on pages 47 through 48.
Item 8. Financial Statements and Supplementary Data
|
|
|
|
|
|
|
Page |
|
|
|
|
54 |
|
|
|
|
55 |
|
|
|
|
57 |
|
|
|
|
58 |
|
|
|
|
59 |
|
|
|
|
60 |
|
|
|
|
61 |
|
|
|
|
62 |
|
|
|
|
86 |
|
|
|
|
90 |
|
53
MANAGEMENTS 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 Companys 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, 2006. 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 managements assessment, we have concluded that our internal control over
financial reporting was effective as of December 31, 2006, based on those criteria.
Our managements assessment of the effectiveness of the Companys internal control over
financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their audit report, which appears
herein.
54
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Denbury Resources Inc.:
We have completed integrated audits of Denbury Resources Inc.s consolidated financial statements
and of its internal control over financial reporting as of December 31, 2006, in accordance with
the standards of the Public Company Accounting Oversight Board (United States). Our opinions,
based on our audits, 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 at December 31, 2006 and 2005, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2006 in conformity with
accounting principles generally accepted in the United States of America. These financial
statements are the responsibility of the Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of
accounting for stock-based compensation costs in 2006.
Internal control over financial reporting
Also, in our opinion, managements assessment, included in the accompanying Managements Report
on Internal Control Over Financial Reporting, that the Company maintained effective internal
control over financial reporting as of December 31, 2006 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, 2006, based on criteria
established in Internal Control Integrated Framework issued by the COSO. The Companys
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 managements assessment and on the effectiveness of the
Companys 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 managements 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 companys 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
companys 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 companys assets that could have a material effect on the
financial statements.
55
(continued from page 55)
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
|
|
|
|
|
|
PricewaterhouseCoopers LLP |
|
|
Dallas, Texas |
|
|
February 28, 2007 |
|
|
56
Denbury Resources Inc.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
(In Thousands, Except Shares) |
|
2006 |
|
|
2005 |
|
Assets |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
53,873 |
|
|
$ |
165,089 |
|
Accrued production receivable |
|
|
72,279 |
|
|
|
65,611 |
|
Related party receivable Genesis |
|
|
119 |
|
|
|
1,312 |
|
Trade and other receivables, net of allowance
of $315 and $289 |
|
|
24,260 |
|
|
|
25,887 |
|
Derivative assets |
|
|
26,883 |
|
|
|
|
|
Deferred tax assets |
|
|
5,855 |
|
|
|
41,284 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
183,269 |
|
|
|
299,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment |
|
|
|
|
|
|
|
|
Oil and natural gas properties (using full cost
accounting) |
|
|
|
|
|
|
|
|
Proved |
|
|
2,226,942 |
|
|
|
1,669,579 |
|
Unevaluated |
|
|
293,657 |
|
|
|
46,597 |
|
CO2 properties and equipment |
|
|
267,483 |
|
|
|
210,046 |
|
Other |
|
|
43,133 |
|
|
|
34,647 |
|
Less accumulated depletion and depreciation |
|
|
(951,447 |
) |
|
|
(804,899 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
1,879,768 |
|
|
|
1,155,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in Genesis |
|
|
10,640 |
|
|
|
10,829 |
|
Deposits on properties under option or contract |
|
|
49,002 |
|
|
|
26,425 |
|
Other assets |
|
|
17,158 |
|
|
|
12,662 |
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
2,139,837 |
|
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
139,111 |
|
|
$ |
104,840 |
|
Oil and gas production payable |
|
|
52,244 |
|
|
|
41,821 |
|
Derivative liabilities |
|
|
4,302 |
|
|
|
2,759 |
|
Deferred revenue Genesis |
|
|
4,070 |
|
|
|
4,070 |
|
Short-term capital lease obligations |
|
|
671 |
|
|
|
574 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
200,398 |
|
|
|
154,064 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term Liabilities |
|
|
|
|
|
|
|
|
Capital lease obligations |
|
|
6,387 |
|
|
|
5,870 |
|
Long-term debt, net of discount |
|
|
507,786 |
|
|
|
373,591 |
|
Asset retirement obligations |
|
|
39,331 |
|
|
|
25,297 |
|
Derivative liabilities |
|
|
6,834 |
|
|
|
6,624 |
|
Deferred revenue Genesis |
|
|
28,843 |
|
|
|
33,023 |
|
Deferred tax liability |
|
|
235,780 |
|
|
|
170,758 |
|
Other |
|
|
8,419 |
|
|
|
2,180 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
833,380 |
|
|
|
617,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 11) |
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding |
|
|
|
|
|
|
|
|
Common stock, $.001 par value, 250,000,000 shares authorized; 120,506,815 and 115,038,531
shares issued at December 31, 2006 and 2005, respectively |
|
|
121 |
|
|
|
115 |
|
Paid-in capital in excess of par |
|
|
616,046 |
|
|
|
443,283 |
|
Retained earnings |
|
|
498,032 |
|
|
|
295,575 |
|
Treasury stock, at cost, 370,327 and 340,337 shares at December 31, 2006 and 2005,
respectively |
|
|
(8,140 |
) |
|
|
(5,311 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,106,059 |
|
|
|
733,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity |
|
$ |
2,139,837 |
|
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
57
Denbury Resources Inc.
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
(In Thousands, Except Per Share Data) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and related product sales |
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated parties |
|
$ |
715,061 |
|
|
$ |
544,408 |
|
|
$ |
381,253 |
|
Related party Genesis |
|
|
1,496 |
|
|
|
4,647 |
|
|
|
63,524 |
|
CO2 sales and transportation fees |
|
|
9,376 |
|
|
|
8,119 |
|
|
|
6,276 |
|
Loss on effective hedge contracts |
|
|
|
|
|
|
|
|
|
|
(70,469 |
) |
Interest income and other |
|
|
5,603 |
|
|
|
3,218 |
|
|
|
2,388 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
731,536 |
|
|
|
560,392 |
|
|
|
382,972 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
167,271 |
|
|
|
108,550 |
|
|
|
87,107 |
|
Production taxes and marketing expenses |
|
|
31,993 |
|
|
|
23,553 |
|
|
|
17,569 |
|
Transportation expense Genesis |
|
|
4,358 |
|
|
|
4,029 |
|
|
|
1,168 |
|
CO2 operating expenses |
|
|
3,190 |
|
|
|
2,251 |
|
|
|
1,338 |
|
General and administrative |
|
|
43,014 |
|
|
|
28,540 |
|
|
|
21,461 |
|
Interest, net of amounts capitalized of $11,333 in 2006 and $1,649 in 2005 |
|
|
23,575 |
|
|
|
17,978 |
|
|
|
19,468 |
|
Depletion, depreciation and amortization |
|
|
149,165 |
|
|
|
98,802 |
|
|
|
97,527 |
|
Commodity derivative expense (income) |
|
|
(19,828 |
) |
|
|
28,962 |
|
|
|
15,358 |
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
402,738 |
|
|
|
312,665 |
|
|
|
260,996 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net income (loss) of Genesis |
|
|
776 |
|
|
|
314 |
|
|
|
(136 |
) |
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
329,574 |
|
|
|
248,041 |
|
|
|
121,840 |
|
Income tax provision |
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
19,865 |
|
|
|
27,177 |
|
|
|
22,929 |
|
Deferred income taxes |
|
|
107,252 |
|
|
|
54,393 |
|
|
|
16,463 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
202,457 |
|
|
$ |
166,471 |
|
|
$ |
82,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share basic |
|
$ |
1.74 |
|
|
$ |
1.49 |
|
|
$ |
0.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
$ |
1.64 |
|
|
$ |
1.39 |
|
|
$ |
0.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
116,550 |
|
|
|
111,743 |
|
|
|
109,741 |
|
Diluted |
|
|
123,774 |
|
|
|
119,634 |
|
|
|
114,603 |
|
See Notes to Consolidated Financial Statements.
58
Denbury Resources Inc.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
(In Thousands) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
Cash Flow from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
202,457 |
|
|
$ |
166,471 |
|
|
$ |
82,448 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
149,165 |
|
|
|
98,802 |
|
|
|
97,527 |
|
Deferred income taxes |
|
|
107,252 |
|
|
|
54,393 |
|
|
|
16,463 |
|
Deferred revenue Genesis |
|
|
(4,180 |
) |
|
|
(3,080 |
) |
|
|
(2,399 |
) |
Stock based compensation |
|
|
17,246 |
|
|
|
4,121 |
|
|
|
1,601 |
|
Non-cash derivative adjustments |
|
|
(25,129 |
) |
|
|
12,201 |
|
|
|
1,270 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
9,218 |
|
|
|
1,706 |
|
Amortization of debt issue costs and other |
|
|
1,603 |
|
|
|
1,257 |
|
|
|
1,577 |
|
Changes in assets and liabilities relating to operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued production receivable |
|
|
(5,474 |
) |
|
|
(21,388 |
) |
|
|
(19,776 |
) |
Trade and other receivables |
|
|
1,712 |
|
|
|
(14,924 |
) |
|
|
7,475 |
|
Derivative assets and liabilities |
|
|
|
|
|
|
|
|
|
|
(7,519 |
) |
Other assets |
|
|
(672 |
) |
|
|
129 |
|
|
|
(166 |
) |
Accounts payable and accrued liabilities |
|
|
7,038 |
|
|
|
38,202 |
|
|
|
(10,522 |
) |
Oil and gas production payable |
|
|
10,422 |
|
|
|
16,966 |
|
|
|
2,641 |
|
Other liabilities |
|
|
370 |
|
|
|
(1,408 |
) |
|
|
(3,674 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities |
|
|
461,810 |
|
|
|
360,960 |
|
|
|
168,652 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Used for Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas expenditures |
|
|
(507,327 |
) |
|
|
(308,366 |
) |
|
|
(167,001 |
) |
Acquisitions of oil and gas properties |
|
|
(319,000 |
) |
|
|
(70,870 |
) |
|
|
(11,069 |
) |
Change in accrual for capital expenditures |
|
|
13,195 |
|
|
|
18,196 |
|
|
|
|
|
Investment in Genesis |
|
|
|
|
|
|
(4,257 |
) |
|
|
|
|
Acquisition
of CO2 assets and CO2 capital expenditures |
|
|
(63,586 |
) |
|
|
(78,726 |
) |
|
|
(50,265 |
) |
Net purchases of other assets |
|
|
(10,531 |
) |
|
|
(6,441 |
) |
|
|
(5,210 |
) |
Deposits on properties under option or contract |
|
|
(11,159 |
) |
|
|
(21,917 |
) |
|
|
(4,507 |
) |
Increase in restricted cash |
|
|
(981 |
) |
|
|
(249 |
) |
|
|
(542 |
) |
Purchases of short-term investments |
|
|
|
|
|
|
|
|
|
|
(76,517 |
) |
Sales of short-term investments |
|
|
|
|
|
|
57,133 |
|
|
|
19,350 |
|
Net proceeds from CO2 production payment Genesis |
|
|
|
|
|
|
14,363 |
|
|
|
4,636 |
|
Net proceeds from sales of properties and equipment |
|
|
42,762 |
|
|
|
17,447 |
|
|
|
10,042 |
|
Sale of Denbury Offshore, Inc. |
|
|
|
|
|
|
|
|
|
|
187,533 |
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used for Investing Activities |
|
|
(856,627 |
) |
|
|
(383,687 |
) |
|
|
(93,550 |
) |
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(249,000 |
) |
|
|
(64,800 |
) |
|
|
(88,000 |
) |
Bank borrowings |
|
|
383,000 |
|
|
|
64,800 |
|
|
|
13,000 |
|
Payments on capital lease obligations |
|
|
(580 |
) |
|
|
(521 |
) |
|
|
(32 |
) |
Income tax benefit from equity awards |
|
|
16,575 |
|
|
|
|
|
|
|
|
|
Issuance of subordinated debt |
|
|
|
|
|
|
150,000 |
|
|
|
|
|
Issuance of common stock |
|
|
139,834 |
|
|
|
12,392 |
|
|
|
13,168 |
|
Purchase of treasury stock |
|
|
(5,544 |
) |
|
|
(5,119 |
) |
|
|
(3,977 |
) |
Costs of debt financing |
|
|
(684 |
) |
|
|
(1,975 |
) |
|
|
(410 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used for) Financing Activities |
|
|
283,601 |
|
|
|
154,777 |
|
|
|
(66,251 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
(111,216 |
) |
|
|
132,050 |
|
|
|
8,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
165,089 |
|
|
|
33,039 |
|
|
|
24,188 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
53,873 |
|
|
$ |
165,089 |
|
|
$ |
33,039 |
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
59
Denbury Resources Inc.
Consolidated Statements of Changes in Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid-In |
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Capital in |
|
|
|
|
|
|
Other |
|
|
Treasury Stock |
|
|
Total |
|
|
|
($.001 Par Value) |
|
|
Excess of |
|
|
Retained |
|
|
Comprehensive |
|
|
(at cost) |
|
|
Stockholders |
|
(Dollar amounts in Thousands) |
|
Shares |
|
|
Amount |
|
|
Par |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Shares |
|
|
Amount |
|
|
Equity |
|
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 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
1,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,601 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
419,345 |
|
|
|
129,104 |
|
|
|
(4,788 |
) |
|
|
93,072 |
|
|
|
(2,046 |
) |
|
|
541,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
142,287 |
|
|
|
(5,119 |
) |
|
|
(5,119 |
) |
Issued pursuant to employee stock
purchase plan |
|
|
|
|
|
|
|
|
|
|
887 |
|
|
|
|
|
|
|
|
|
|
|
(80,869 |
) |
|
|
1,854 |
|
|
|
2,741 |
|
Issued pursuant to employee stock
option plan |
|
|
949,051 |
|
|
|
1 |
|
|
|
9,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,651 |
|
Issued pursuant to directors
compensation plan |
|
|
3,502 |
|
|
|
|
|
|
|
119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119 |
|
Restricted stock grants |
|
|
10,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Two-for-one stock split |
|
|
57,468,101 |
|
|
|
57 |
|
|
|
(57 |
) |
|
|
|
|
|
|
|
|
|
|
185,847 |
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
4,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,121 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
|
|
|
|
9,218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,218 |
|
Derivative contracts, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,764 |
|
|
|
|
|
|
|
|
|
|
|
4,764 |
|
Unrealized gain on available-for-sale securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
24 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
166,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
166,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005 |
|
|
115,038,531 |
|
|
|
115 |
|
|
|
443,283 |
|
|
|
295,575 |
|
|
|
|
|
|
|
340,337 |
|
|
|
(5,311 |
) |
|
|
733,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
167,255 |
|
|
|
(5,544 |
) |
|
|
(5,544 |
) |
Issued pursuant to employee stock
purchase plan |
|
|
|
|
|
|
|
|
|
|
1,245 |
|
|
|
|
|
|
|
|
|
|
|
(137,265 |
) |
|
|
2,715 |
|
|
|
3,960 |
|
Issued pursuant to employee stock
option plans |
|
|
2,012,472 |
|
|
|
2 |
|
|
|
11,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,020 |
|
Issued pursuant to directors
compensation plan |
|
|
4,441 |
|
|
|
|
|
|
|
134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
134 |
|
Restricted stock grants |
|
|
129,987 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants forfeited |
|
|
(171,211 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
18,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,941 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
|
|
|
|
16,575 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,575 |
|
Issuance of common stock |
|
|
3,492,595 |
|
|
|
4 |
|
|
|
124,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124,854 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
202,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
202,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006 |
|
|
120,506,815 |
|
|
$ |
121 |
|
|
$ |
616,046 |
|
|
$ |
498,032 |
|
|
$ |
|
|
|
|
370,327 |
|
|
$ |
(8,140 |
) |
|
$ |
1,106,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
60
Denbury Resources Inc.
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
(In Thousands) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
Net Income |
|
$ |
202,457 |
|
|
$ |
166,471 |
|
|
$ |
82,448 |
|
Other comprehensive income (loss), net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative contracts, net
of tax of ($19,328) |
|
|
|
|
|
|
|
|
|
|
(31,535 |
) |
Reclassification adjustments related to
settlements of derivative
contracts, net of tax of $2,920 and $33,025, respectively |
|
|
|
|
|
|
4,764 |
|
|
|
53,884 |
|
Unrealized gain (loss) on securities available for sale,
net of tax of $15 and ($15), respectively
|
|
|
|
|
|
|
24 |
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
Comprehensive Income |
|
$ |
202,457 |
|
|
$ |
171,259 |
|
|
$ |
104,773 |
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
61
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. We have 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
Genesis (see Note 3) and to third party industrial users.
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 Genesis limited partnership agreement we do
not consolidate Genesis. See Note 3 for more information regarding our related party transactions
with Genesis. 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.
Stock Split
On October 19, 2005, stockholders of Denbury Resources Inc. approved an amendment to our
Restated Certificate of Incorporation to increase the number of shares of our authorized common
stock from 100,000,000 shares to 250,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on October 31, 2005, received one additional share of Denbury common
stock for each share of common stock held at that time. Information pertaining to shares and
earnings per share has been retroactively adjusted in the accompanying financial statements and
related notes thereto to reflect the stock split.
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 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. The
depletion and depreciation rate associated with our oil and gas producing activities was
$10.54 in 2006, $8.69 in 2005 and $7.82 in 2004.
c) Asset Retirement Obligations. In general, our future asset
retirement obligations relate to future costs associated with plugging and abandonment of our oil,
natural gas and CO2 wells, removal of equipment and facilities from leased acreage and
returning such land to its original condition. The fair value of a liability for an
asset retirement obligation is 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
62
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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. See Note 4 for more information regarding our asset retirement obligations.
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 Denburys proportionate interest in such activities and any amounts due
from other partners are included in trade receivables.
f) Proved Reserves. See Note 14 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, is depreciated principally on a straight-line basis
over estimated useful lives. Estimated useful lives are generally as follows: vehicles and
furniture and fixtures 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 receivable.
We follow the sales method of accounting for our oil and natural gas revenue, whereby we
recognize 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 extent that we have an imbalance on a specific property greater than the expected remaining
proved reserves. As of December 31, 2006 and 2005, 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. Derivative financial
instruments are recorded on the balance sheet as either an asset or a liability measured at fair
value. Effective January 1, 2005, we elected to discontinue hedge accounting for our oil and
natural gas derivative contracts and accordingly de-designated our derivative instruments from
hedge accounting treatment. As a result of this change, we began accounting for our oil and
natural gas derivative contracts as speculative contracts in the first quarter of 2005. As
speculative contracts, the changes in the fair value of these instruments are recognized in income
in the period of change.
63
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, trade and accrued production receivables and the derivative hedging
instruments discussed above. Our cash equivalents 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 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.
Restricted Cash and Investments
At December 31, 2006 and 2005, we had approximately $7.6 million and $6.7 million,
respectively, of restricted cash and investments held in escrow accounts for future site
reclamation costs. These balances are recorded at cost and are included in Other assets in the
Consolidated Balance Sheets. The estimated fair market value of these investments at December 31,
2006 and 2005, was virtually the same as amortized cost.
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, stock
appreciation rights (SARs), non-vested restricted stock and any other convertible securities
outstanding.
For each of the three years in the period ended December 31, 2006, there were no adjustments
to net income for purposes of calculating basic and diluted net income per common share. In April
2006, we issued 3,492,595 shares of common stock in a public offering See Note 8, Stockholders
Equity.
64
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following is a reconciliation of the weighted average shares used in the basic and diluted
net income per common share computations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
(In Thousands) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
Weighted average common shares basic |
|
|
116,550 |
|
|
|
111,743 |
|
|
|
109,741 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
6,188 |
|
|
|
6,931 |
|
|
|
4,827 |
|
Restricted stock |
|
|
1,036 |
|
|
|
960 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
123,774 |
|
|
|
119,634 |
|
|
|
114,603 |
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount in 2006 and 2005 excludes 1.4 million and
2.0 million shares of non-vested restricted stock, respectively, that is subject to future vesting
over time. As these restricted shares vest, they will be included in the shares outstanding used
to calculate basic net income per common share (although all restricted stock is issued and
outstanding upon grant). 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 dilution impact of these
shares on our earnings per share calculation may increase in future periods, depending on the
market price of our common stock during those periods. Stock options and SARs to purchase
approximately 128,000 shares in 2006, 184,000 shares in 2005 and 80,000 shares in 2004 were
outstanding but excluded from the diluted net income per common share calculations, as their
exercise prices exceeded the average market price of our common stock during the respective
periods, therefore, their inclusion would be anti-dilutive to the calculations.
Stock-Based Compensation
In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standard (SFAS) No. 123(R), Share Based Payment, which is a revision of
SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes Accounting
Principles Board Opinion 25 (APB 25), Accounting for Stock Issued to Employees, 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) requires all share-based compensation
to employees, including grants of employee stock options, to be recognized in our consolidated
financial statements based on estimated fair value.
We adopted SFAS No. 123(R) on January 1, 2006, using the modified prospective application
method described in the statement. Under the modified prospective method, effective January 1,
2006, we began to recognize compensation expense for the unvested portion of awards outstanding as
of December 31, 2005, over the remaining service periods, and for new awards granted or modified
after January 1, 2006. See Note 9 for further discussion regarding our stock compensation plans.
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
65
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 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
revisions in estimated oil and gas volumes, 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
In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes
(FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with SFAS No. 109, Accounting for Income Taxes.
This interpretation prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to be taken in a tax
return. FIN 48 requires recognition of the impact of a tax position in the Companys financial
statements if that position is more likely than not of being sustained on audit, based on the
technical merits of the position. FIN 48 also provides guidance on derecognition, classification,
interest and penalties, accounting in interim periods, disclosure and transition. The provisions
of FIN 48 are effective as of the beginning of the Companys 2007 fiscal year, with the cumulative
effect of the change in accounting principle recorded as an adjustment to opening retained
earnings. We are still evaluating the potential impact of this interpretation on the Companys
financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157
defines fair value, establishes a framework for measuring fair value in accordance with accounting
principles generally accepted in the United States, and expands disclosures about fair value
measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with
earlier application encouraged. Any amounts recognized upon adoption as a cumulative effect
adjustment will be recorded to the opening balance of retained earnings in the year of adoption.
We have not yet determined the impact of this Statement on the Companys financial condition and
results of operations.
Note 2. Acquisitions and Divestitures
2006 Acquisitions
On January 31, 2006, we completed an acquisition of three producing oil properties that are
future potential CO2 tertiary oil flood candidates: Tinsley Field, approximately 40
miles northwest of Jackson, Mississippi, Citronelle Field in Southwest Alabama, and the smaller
South Cypress Creek Field near the Companys Eucutta Field in Eastern Mississippi. In 2006 we
began our initial tertiary development work at Tinsley Field, consisting primarily of planning,
land and engineering work, with more extensive development and facility construction planned for
2007. The timing of tertiary development at Citronelle Field is uncertain, as we will need to
build a 60- to 70-mile pipeline extension of our Free State CO2 pipeline (pipeline from
Jackson Dome to East Mississippi) before flooding can commence, and South Cypress Creek will
probably be flooded following our initial development of our other East Mississippi properties.
66
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The adjusted purchase price for these properties was approximately $250 million (including the
$25 million of earnest money we had deposited at December 31, 2005, which was included in our
Consolidated Balance Sheet in
Deposits on properties under option or contract), after adjusting for interim net cash flow
between the effective date and closing date of the acquisition, and minor purchase price
adjustments. The adjusted purchase price of $250 million was allocated between proved and unevaluated oil and natural gas properties based on a risk
adjusted analysis of the total estimated value of the proved, probable, and possible reserves
acquired. Based on this analysis, approximately $126 million was assigned to proved properties and
approximately $124 million assigned to unevaluated properties. The unevaluated costs are currently
excluded from the amortization base and will be transferred to the amortization base as we develop
and test the tertiary recovery projects planned in these fields. We currently estimate that this
development will take place over the next two to five years. The acquisition was funded with the
proceeds of $150 million of senior subordinated notes issued in December 2005 and $100 million of
bank financing under the Companys then existing credit facility (repaid in late April 2006 with
proceeds from a $125 million equity offering at that time).
During May 2006, we purchased the Delhi Holt-Bryant Unit (Delhi) in northern Louisiana for
$50 million, plus a 25% reversionary interest to the seller after we have achieved $200 million in
net operating revenue, as defined. Delhi is also a future potential CO2 tertiary oil
flood candidate, one that will require construction of a CO2 pipeline before flooding
can commence, which will likely be an extension of the currently planned CO2 pipeline
from Jackson Dome to Tinsley Field. Our goal is to have this CO2 line installed within
the next two years, with initial oil production from tertiary operations currently anticipated
during 2009. Currently, there is neither significant oil production nor proved oil reserves at
Delhi. The purchase price of approximately $50 million was allocated between proved and
unevaluated oil and natural gas properties based on a risk adjusted analysis of the total estimated
value of the proved, probable, and possible reserves acquired. Based on the analysis,
approximately $1 million was assigned to evaluated properties and approximately $49 million was
assigned to unevaluated properties. The unevaluated costs are currently excluded from the
amortization base and will be transferred to the amortization base over the next three to five
years as we develop and test the tertiary recovery projects planned in this field. The acquisition
was funded with our bank credit facility.
The operating results of the acquired properties were included in our financial statements
beginning in February 2006, except for Delhi, which was included beginning June 2006. We have not
presented any pro forma information for the acquired properties as the pro forma effect was not
material to our results of operations for the years ended December 31, 2006 and 2005.
2006 Purchase Option Contract
During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc. that
gives us the option to purchase their interest in Hastings Field, a strategically significant
potential tertiary flood candidate located near Houston, Texas, between November 1, 2008 and
November 1, 2009. The agreement provides for the parties to agree upon a purchase price at the
time of the exercise of the option, which may be paid in cash or through a volumetric production
payment; failing agreement as to price, the price will be determined by a pre-designated
independent petroleum engineering firm using specified criteria for calculation of the discounted
present value of the proved reserves at that time. As consideration for the option agreement, we
made a payment of $37.5 million in November 2006 and are required to make additional payments
totaling $12.5 million over the next two years. We have recorded this payment and the discounted
present value of the required additional payments, which total $49 million, in Deposits on
properties under option or contract in our December 31, 2006 Consolidated Balance Sheet. Upon
exercise of the option to purchase the Hastings Field, the deposit will be transferred to oil and
natural gas properties. We will evaluate the option for impairment and if circumstances arise that
indicate the future acquisition will not occur, we will recognize expense for this option as
appropriate.
2005 Acquisitions
Our acquisitions in 2005 included the purchase of additional interest and acreage in the
Barnett Shale area ($34.2 million), additional interest in the Eucutta Field ($8.0 million), and
the purchase of two oil fields that may be potential tertiary flood candidates in the future, Lake
St. John ($16.1 million) and Cranfield ($1.1 million).
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
67
Denbury Resources Inc.
Notes to Consolidated Financial Statements
$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 that we received
between April 1 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).
Note
3. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denbury is the general partner and owns an aggregate 9.25% interest in Genesis Energy, L.P.
(Genesis), a publicly traded master limited partnership. Genesis primary business activities
include gathering, marketing, and transportation of crude oil and natural gas, and wholesale
marketing of CO2, primarily in Mississippi, Texas, Alabama and Florida.
We account 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 2006 was $0.8 million, for 2005 was $0.3 million, and for 2004 was $(0.1)
million. Denbury received pro-rata distribution from Genesis of $0.9 million in 2006, $0.5 million
in 2005 and $0.5 million in 2004. We also received $120,000 in each of the last three years in
directors fees for certain officers of Denbury that are board members of Genesis. 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 $11.5 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 in
excess of $25.4 million at December 31, 2006, based on quoted market values of Genesis publicly
traded limited partnership units.
During 2006, we invested a total of $3.0 million in a Louisiana petroleum coke-to-ammonia
project that is in the development stage. All of our investment may later be redeemed, with a
return, or converted to equity after construction financing for the project has been obtained. If
the project is built, we plan to take up to 100% of the CO2 produced from this plant.
Genesis has also invested in this project, with its total commitment not to exceed $1.0 million.
Oil Sales and Transportation Services
Prior to September 2004, including the period prior to our investment in Genesis, we sold
certain of our oil production to Genesis. Beginning in September 2004, we discontinued most of our
direct sales to Genesis and began to transport our crude oil using Genesis common carrier pipeline
to a sales point where it is sold to third party purchasers. For these transportation services, we
pay Genesis a fee for the use of their pipeline and trucking services. We expensed $4.4 million in
2006, $4.0 million in 2005 and $1.2 million in 2004 for these transportation services.
Transportation Leases
In late 2004 and early 2005, we entered into pipeline transportation agreements with Genesis
to transport our crude oil from certain of our fields in Southwest Mississippi, and to transport
CO2 from our main CO2 pipeline to
68
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Brookhaven Field for our tertiary operations. 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, 2006 and
2005, we had $5.9 million and $6.4 million,
respectively, of capital lease obligations with Genesis recorded as liabilities in our Consolidated
Balance Sheets, of which $0.6 million was current in both periods.
CO2
Volumetric Production Payments
During 2003 through 2005, we sold 280.5 Bcf of CO2 to Genesis under three separate
volumetric production payment agreements. We have recorded the net proceeds of these volumetric
production payment sales as deferred revenue and recognize such revenue as CO2 is
delivered under the volumetric production payments. At December 31, 2006, 2005 and 2004 $32.9
million, $37.1 million and $25.8 million, respectively, was recorded as deferred revenue of which
$4.1 million was included in current liabilities at both December 31, 2006 and 2005. We recognized
deferred revenue of $4.2 million, $3.1 million and $2.4 million for the years ended December 31,
2006, 2005 and 2004, respectively, for deliveries under these volumetric production payments. We
provide Genesis with certain processing and transportation services in connection with transporting
CO2 to their industrial customers for a fee of approximately $0.17 per Mcf of
CO2. For these services, we recognized revenues of $4.6 million, $3.5 million, and $2.7
million for the years ended December 31, 2006, 2005 and 2004, respectively.
At December 31, 2006, 2005 and 2004, we had a net receivable from Genesis of $0.1 million,
$1.3 million and $0.7 million, respectively, associated with all of the transactions described
above.
Note 4. Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated with
plugging and abandonment of our oil, natural gas and CO2 wells, removal of equipment and
facilities from leased acreage and land restoration. The fair value of a liability for an asset
retirement is 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.
The following table summarizes the changes in our asset retirement obligations for the years
ended December 31, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
(In Thousands) |
|
2006 |
|
|
2005 |
|
Beginning asset retirement obligation |
|
$ |
27,088 |
|
|
$ |
21,540 |
|
Liabilities incurred and assumed during period |
|
|
10,159 |
|
|
|
3,091 |
|
Revisions in estimated cash flows |
|
|
2,791 |
|
|
|
1,765 |
|
Liabilities settled during period |
|
|
(1,320 |
) |
|
|
(990 |
) |
Accretion expense |
|
|
2,389 |
|
|
|
1,682 |
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
41,107 |
|
|
$ |
27,088 |
|
|
|
|
|
|
|
|
At both December 31, 2006 and 2005, $1.8 million of our asset retirement obligation was
classified in Accounts payable and accrued liabilities under current liabilities in our
Consolidated Balance Sheets. Liabilities incurred and assumed during 2006 and 2005 are primarily
for properties acquired. We have escrow accounts that are legally restricted for certain of our
asset retirement obligations. The balances of these escrow accounts were $7.6 million at December
31, 2006, and $6.7 million at December 31, 2005, and are included in Other assets in our
Consolidated Balance Sheets.
69
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 5. Property and Equipment
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
(In Thousands) |
|
2006 |
|
|
2005 |
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
2,226,942 |
|
|
$ |
1,669,579 |
|
Unevaluated properties |
|
|
293,657 |
|
|
|
46,597 |
|
|
|
|
|
|
|
|
Total |
|
|
2,520,599 |
|
|
|
1,716,176 |
|
Accumulated depletion and depreciation |
|
|
(907,911 |
) |
|
|
(775,390 |
) |
|
|
|
|
|
|
|
Net oil and natural gas properties |
|
|
1,612,688 |
|
|
|
940,786 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 properties and equipment |
|
|
267,483 |
|
|
|
210,046 |
|
Accumulated depletion and depreciation |
|
|
(24,997 |
) |
|
|
(15,544 |
) |
|
|
|
|
|
|
|
Net CO2 properties |
|
|
242,486 |
|
|
|
194,502 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital leases |
|
|
7,985 |
|
|
|
6,997 |
|
Accumulated depletion and depreciation |
|
|
(1,631 |
) |
|
|
(835 |
) |
|
|
|
|
|
|
|
Net capital leases |
|
|
6,354 |
|
|
|
6,162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
35,148 |
|
|
|
27,650 |
|
Accumulated depletion and depreciation |
|
|
(16,908 |
) |
|
|
(13,130 |
) |
|
|
|
|
|
|
|
Net other |
|
|
18,240 |
|
|
|
14,520 |
|
|
|
|
|
|
|
|
Net property and equipment |
|
$ |
1,879,768 |
|
|
$ |
1,155,970 |
|
|
|
|
|
|
|
|
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, 2006 and 2005, and the year in which they were incurred follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
|
Costs Incurred During: |
|
|
|
|
(In Thousands) |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
Prior |
|
|
Total |
|
Property acquisition costs |
|
$ |
193,554 |
|
|
$ |
11,906 |
|
|
$ |
1,244 |
|
|
$ |
411 |
|
|
$ |
207,115 |
|
Exploration and development |
|
|
70,624 |
|
|
|
1,657 |
|
|
|
805 |
|
|
|
2,397 |
|
|
|
75,483 |
|
Capitalized interest |
|
|
11,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
275,237 |
|
|
$ |
13,563 |
|
|
$ |
2,049 |
|
|
$ |
2,808 |
|
|
$ |
293,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
|
Costs Incurred During: |
|
|
|
|
(In Thousands) |
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
Prior |
|
|
Total |
|
Property acquisition costs |
|
$ |
30,622 |
|
|
$ |
2,368 |
|
|
$ |
1,007 |
|
|
$ |
527 |
|
|
$ |
34,524 |
|
Exploration and development |
|
|
6,493 |
|
|
|
2,245 |
|
|
|
1,107 |
|
|
|
2,228 |
|
|
|
12,073 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
37,115 |
|
|
$ |
4,613 |
|
|
$ |
2,114 |
|
|
$ |
2,755 |
|
|
$ |
46,597 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Property acquisition costs for 2006 are primarily associated with our acquisitions of four
CO2 tertiary oil field candidates, Tinsley Field, Citronelle Field, South
Cypress Creek Field and Delhi Field. See Note 2 Acquisitions and Divestitures. Property
acquisition costs for 2005 are primarily associated with our acquisition of Lake St. John
Field. Exploration and development costs for 2006 are primarily associated with our CO2
tertiary oil fields that are under development and did not have proved reserves at December
31, 2006. 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.
Note 6. Notes Payable and Long-Term Indebtedness
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
7.5% Senior Subordinated Notes due 2015 |
|
$ |
150,000 |
|
|
$ |
150,000 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(1,214 |
) |
|
|
(1,409 |
) |
Senior bank loan |
|
|
134,000 |
|
|
|
|
|
Capital lease obligations Genesis |
|
|
5,869 |
|
|
|
6,444 |
|
Capital lease obligations |
|
|
1,189 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
514,844 |
|
|
|
380,035 |
|
Less current obligations |
|
|
671 |
|
|
|
574 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
514,173 |
|
|
$ |
379,461 |
|
|
|
|
|
|
|
|
7.5% Senior Subordinated Notes due 2015
On December 21, 2005, we issued $150 million of 7.5% Senior Subordinated Notes due 2015 (2015
Notes). The 2015 Notes were priced at par and we used the $148.0 million of net proceeds from the
offering to fund a portion of the $250 million oil and natural gas property acquisition, which
closed in January 2006 (see Note 2, Acquisitions and Divestitures). Pending the funding of this
transaction in January 2006, the net proceeds were used to repay the borrowings under our bank
credit facility with the balance temporarily invested in short-term investments and included as
Cash and cash equivalents in our December 31, 2005 Consolidated Balance Sheet.
The 2015 Notes mature on December 15, 2015, and interest on the 2015 Notes is payable each
June 15 and December 15. We may redeem the 2015 Notes at our option beginning December 15, 2010,
at the following redemption prices: 103.75% after December 15, 2010, 102.5% after December 15,
2011, 101.25%, after December 15, 2012 and 100% after December 15, 2013. In addition, prior to
December 15, 2008, we may at our option on one or more occasions redeem up to 35% of the 2015 Notes
at a redemption price of 107.5% with the net cash proceeds from a stock offering. 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 2015
Notes are not subject to any sinking fund requirements. All of our significant subsidiaries fully
and unconditionally guarantee this debt.
7.5% Senior Subordinated Notes due 2013
On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes due 2013 (2013
Notes). The 2013 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 then existing $200
million of 9% Senior Subordinated Notes due 2008, including the Series B notes.
71
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The 2013 Notes mature on April 1, 2013, and interest on the 2013 Notes is payable each April 1
and October 1. We may redeem the 2013 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. 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 2013 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,
we entered into a First Supplemental Indenture dated December 29, 2003, which did not require the
consent of the holders of the 2013 Notes. 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.
Senior Bank Loan
On September 14, 2006, we entered into a Sixth Amended and Restated Credit Agreement with our
nine banks that modified our previous bank credit agreement. The new agreement (i) improves the
credit pricing under the agreement, (ii) extends the term of the credit arrangements by two and
one-half years to September 14, 2011, (iii) increases the borrowing base from $300 million to $500
million, (iv) increases the maximum facility size from $300 million to $800 million, and (v) makes
other minor modifications and corrections. Under the new agreement, the commitment amount remained
at $150 million. However, in December 2006, we increased our commitment amount to $250 million.
The borrowing base represents the amount that can be borrowed from a credit standpoint based on our
assets, as confirmed by the banks, while the commitment amount is the amount the banks have
committed to fund pursuant to the terms of the credit agreement. The banks have the option to
participate in any borrowing request we make in excess of the commitment amount ($250 million), up
to the borrowing base limit ($500 million), although the banks are not obligated to fund any amount
in excess of the commitment amount. The new credit agreement maintains the structure of
semi-annual reviews of the borrowing base and commitment amount on April 1 and October 1.
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 to maintain positive working capital, as defined, (iii) a
minimum interest coverage test and (iv) a prohibition of most debt and corporate guarantees.
Additionally, there is a limitation on the aggregate amount of forecasted production that can be
economically hedged with oil or natural gas derivative contracts. At December 31, 2006, we had
exceeded the hedge limitation of 85% of our forecasted natural gas production and we have obtained
a waiver of this covenant from the banks, which is effective through the end of 2007. Otherwise,
we were in compliance with all of our bank covenants as of December 31, 2006. Borrowings under the
credit facility are generally in tranches that can have maturities up to one year. Interest on any
borrowings is based on the Prime Rate or LIBOR rate plus an applicable margin as determined by the
borrowings outstanding. The facility matures in September 2011.
As of December 31, 2006, we had $134 million of outstanding borrowings under the facility and
$10.5 million in letters of credit secured by the facility. The weighted average interest rate on
these outstanding borrowings was 6.35% at December 31, 2006. The next scheduled redetermination of
the borrowing base will be as of April 1, 2007, based on December 31, 2006 assets and proved
reserves.
72
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Indebtedness Repayment Schedule
At December 31, 2006, our indebtedness, excluding the discount on our senior subordinated
debt, is repayable over the next five years and thereafter as follows:
|
|
|
|
|
(In Thousands) |
|
|
|
|
|
2007 |
|
$ |
671 |
|
2008 |
|
|
736 |
|
2009 |
|
|
1,018 |
|
2010 |
|
|
890 |
|
2011 |
|
|
135,024 |
|
Thereafter |
|
|
377,719 |
|
|
|
|
|
Total indebtedness |
|
$ |
516,058 |
|
|
|
|
|
Note 7. Income Taxes
Our income tax provision is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Current income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
16,033 |
|
|
$ |
26,659 |
|
|
$ |
22,166 |
|
State |
|
|
3,832 |
|
|
|
518 |
|
|
|
763 |
|
|
|
|
|
|
|
|
|
|
|
Total current income tax expense |
|
|
19,865 |
|
|
|
27,177 |
|
|
|
22,929 |
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
97,902 |
|
|
|
44,191 |
|
|
|
12,352 |
|
State |
|
|
9,350 |
|
|
|
10,202 |
|
|
|
4,111 |
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax expense |
|
|
107,252 |
|
|
|
54,393 |
|
|
|
16,463 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
127,117 |
|
|
$ |
81,570 |
|
|
$ |
39,392 |
|
|
|
|
|
|
|
|
|
|
|
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. At December 31, 2006, we have approximately $19.8 million in state net operating loss
carryforwards that begin to expire in 2013. As of December 31, 2006, we have an estimated $41.9
million of enhanced oil recovery credits to carry forward related to our tertiary operations.
These credits will 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, 2006 and 2005, balance sheet dates. We believe that we will be able to
utilize all of our deferred tax assets at December 31, 2006, and therefore have provided no
valuation allowance against our deferred tax assets.
73
Denbury Resources Inc.
Notes to Consolidated Financial Statements
At December 31, 2006 and 2005, our deferred tax assets and liabilities were as follows:
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Loss carryforwards state |
|
$ |
792 |
|
|
$ |
983 |
|
Tax credit carryover |
|
|
14,103 |
|
|
|
14,103 |
|
Enhanced oil recovery credit carryforwards |
|
|
41,856 |
|
|
|
42,127 |
|
Other |
|
|
7,791 |
|
|
|
1,196 |
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
64,542 |
|
|
|
58,409 |
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property and equipment |
|
|
(283,983 |
) |
|
|
(187,883 |
) |
Derivative hedging contracts |
|
|
(10,484 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
(294,467 |
) |
|
|
(187,883 |
) |
|
|
|
|
|
|
|
Total net deferred tax liability |
|
$ |
(229,925 |
) |
|
$ |
(129,474 |
) |
|
|
|
|
|
|
|
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, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Income tax provision calculated using the
federal statutory income tax rate |
|
$ |
115,351 |
|
|
$ |
86,814 |
|
|
$ |
42,644 |
|
State income taxes |
|
|
13,183 |
|
|
|
9,922 |
|
|
|
4,874 |
|
Enhanced oil recovery credits |
|
|
|
|
|
|
(17,142 |
) |
|
|
(7,986 |
) |
Other |
|
|
(1,417 |
) |
|
|
1,976 |
|
|
|
(140 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
127,117 |
|
|
$ |
81,570 |
|
|
$ |
39,392 |
|
|
|
|
|
|
|
|
|
|
|
Note 8. Stockholders Equity
Stock Issuance
On April 25, 2006, we closed on the $125 million sale (net to Denbury) of 3,492,595 shares of
common stock in a public offering. We used the net proceeds from the offering to repay then
current borrowings under our bank credit facility, which were $120 million as of April 25, 2006,
the majority of which was incurred to partially fund our $250 million acquisition of three
properties in January 2006.
Stock Split
On October 19, 2005, stockholders of Denbury Resources Inc. approved an amendment to our
Restated Certificate of Incorporation to increase the number of shares of our authorized common
stock from 100,000,000 shares to 250,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on October 31, 2005, received one additional share of Denbury common
stock for each share of common stock held at that time. Information pertaining to shares and
earnings per share has been retroactively adjusted in the accompanying financial statements and
related notes thereto to reflect the stock split.
Authorized
We are authorized to issue 250 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.
74
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Stock Repurchase Plan
Between August 2003 and June 30, 2005, Denbury 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 Denburys Employee Stock Purchase Plan (see Employee Stock
Purchase Plan below). During 2003, we purchased 200,000 shares at an average cost of $6.39 per
share and reissued 183,676 of those shares under Denburys Employee Stock Purchase Plan. In 2004,
we repurchased into treasury 400,000 shares at an average cost of $9.95 per share and reissued
230,180 treasury shares under the Employee Stock Purchase Plan. In the first six months of 2005,
we repurchased into treasury 200,000 shares under the Plan at an average cost of $15.82 per share
and reissued 130,831 treasury shares under our Employee Stock Purchase Plan. Our repurchase
program expired as of June 30, 2005, and the Board of Directors currently does not plan to renew
the Plan until a significant portion of the treasury shares have been used under our Employee Stock
Purchase Plan. In 2006, all of our share repurchases were associated with shares surrendered to
the Company to cover tax withholding upon the vesting of restricted stock and were not part of a
formal stock repurchase plan.
Employee Stock Purchase Plan
We have an Employee Stock Purchase Plan that is authorized to issue up to 3,500,000 shares of
common stock. As of December 31, 2006, there were 315,106 authorized shares remaining to be issued
under the plan. In accordance with the plan, eligible 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 Denburys common stock at the
end of each quarter. We recognize compensation expense for the 75% company match portion, which
totaled $1.7 million, $1.2 million, and $1.0 million for the years ended December 31, 2006, 2005
and 2004, respectively. This plan is administered by the Compensation Committee of Denburys Board
of Directors.
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 employees compensation, as defined by the
plan, is matched by Denbury at 100% and an employees contribution between 3% and 6% of
compensation is matched by Denbury at 50%. Denburys match is vested immediately. During 2006,
2005 and 2004, Denburys matching contributions were approximately $1.6 million, $1.2 million, and
$1.0 million, respectively, to the 401(k) Plan.
Note 9. Stock Compensation Plans
Incentive Programs
Denbury has two stock compensation plans. The first plan has been in existence since 1995
(the 1995 Plan) and expired in August 2005 (although options granted under the 1995 Plan prior to
that time can remain outstanding for up to 10 years). The 1995 plan only provided for the issuance
of stock options, and in January 2005, we issued stock options under the 1995 Plan that utilized
substantially all of the remaining authorized shares. The second plan, the 2004 Omnibus Stock and
Incentive Plan (the 2004 Plan), has a 10-year term and was approved by the stockholders in May
2004. The 2004 Plan provides for the issuance of incentive and non-qualified stock options,
restricted stock awards, stock appreciation rights (SARs) settled in stock and performance awards
that may be issued to officers, employees, directors and consultants. Awards covering a total of
5.0 million shares of common stock are authorized for issuance pursuant to the 2004 Plan, of which
awards covering no more than 2,750,000 shares may be issued in the form of restricted stock or
performance vesting awards. At December 31, 2006, a total of
1,226,054 shares were available for
future issuance of awards, of which only 471,224 shares may be in the
form of restricted stock
or performance vesting awards.
Denbury has historically granted incentive and non-qualified stock options to its
employees. Effective January 1, 2006, we completely replaced the use of stock options for
employees with SARs settled in stock, as SARs are less dilutive to our stockholders while providing
an employee with essentially the same economic benefits as stock options. The stock options and
SARs generally become exercisable over a four-year vesting period with the specific terms of
vesting determined at the time of grant based on guidelines established by the Board of Directors.
The stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days
after
75
Denbury Resources Inc.
Notes to Consolidated Financial Statements
termination of employment or permanent disability or one year after the death of the
optionee. The stock options and SARs are granted at the fair market value at the time of grant,
which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant. The plan is administered by the Compensation Committee of
Denburys Board of Directors.
During August 2004 through January 2005, the Board of Directors, based on a recommendation by
the Boards Compensation Committee, awarded the officers of Denbury a total of 2,200,000 shares of
restricted stock and the independent directors of Denbury a total of 120,000 shares of restricted
stock, all granted under the 2004 Plan. 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 2,200,000
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 holders separation from
the Company. With respect to the 120,000 restricted shares issued to Denburys independent board
members, the shares vest 20% per year over five years. For these directors 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 the holders separation from the Company. During 2006, a total
of 129,987 shares of restricted stock were granted to officers and certain members of our
management group.
Mr. Worthey, Senior Vice President of Operations, left Denbury effective June 5, 2006. Mr.
Worthey had served as an officer of the Company since September 1, 1992. The Board of Directors
modified certain of his outstanding long-term equity incentives awarded to him during 2003 and
2004. As a result of the modification, Mr. Worthey retained stock options covering 63,090 shares
of Denbury common stock that pursuant to their original terms vest in either January 2007 or
January 2008, and received accelerated vesting of 136,500 shares of restricted stock that
originally were set to vest between mid-August 2006 and mid-August 2008. The options have an
average weighted exercise price of $6.26 per share and were granted in early 2003 and early 2004;
the restricted stock was awarded in August 2004. The compensation cost resulting from the
modifications was approximately $5.3 million and was included in General and administrative
expenses in the Consolidated Statement of Operations for the year ended December 31, 2006. No
significant cash compensation was paid to Mr. Worthey upon separation. As part of Mr. Wortheys
separation, he also entered into non-competition and consulting agreements covering a period of 27
months.
During the third quarter of 2006, our Vice President of Marketing announced his retirement and
departed the Company on August 31, 2006, in connection with which we expensed approximately
$750,000 related to options and restricted stock that he held.
Total compensation expense charged against income for stock-based compensation was $17.2
million (including the $5.3 million resulting from modification of Mr. Wortheys equity awards
discussed above) for the year ended December 31, 2006. Part of this expense, $1.5 million, was
included in Lease operating expenses for stock compensation expense associated with our field
employees, and the remaining $15.7 million was recognized in General and administrative expenses
in the Consolidated Statements of Operations. The total income tax benefit recognized in the
Consolidated Statements of Operations for share-based compensation arrangements was $4.6 million
for the year ended December 31, 2006. Share-based compensation capitalized as part of Oil and
Natural Gas Properties was $1.7 million for the year ended December 31, 2006.
Effective January 1, 2006, we adopted SFAS No. 123(R) to account for our employee stock based
compensation. Prior to 2006, we accounted for stock-based compensation 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
compensation expense for stock options was reflected in net income as long as the stock options had
an exercise price equal to the quoted market price of the underlying common stock on the date of
grant. For restricted stock grants, we recognize compensation expense equal to the intrinsic value
of the stock on the date of grant over the applicable vesting periods. The following table
illustrates the effect on net income and net income per common share for 2004 and 2005 as if we had
applied the fair value recognition and measurement provisions of SFAS No. 123, as amended by SFAS
No. 148, in accounting for our stock-based compensation.
76
Denbury Resources Inc.
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per share amounts |
|
2005 |
|
|
2004 |
|
Net income, as reported |
|
$ |
166,471 |
|
|
$ |
82,448 |
|
Add: stock-based compensation included in reported net
income, net of related tax effects |
|
|
2,765 |
|
|
|
977 |
|
Less: stock-based compensation expense applying fair value
based method, net of related tax effects |
|
|
8,425 |
|
|
|
3,713 |
|
|
|
|
|
|
|
|
Pro-forma net income |
|
$ |
160,811 |
|
|
$ |
79,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share |
|
|
|
|
|
|
|
|
As reported: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.49 |
|
|
$ |
0.75 |
|
Diluted |
|
|
1.39 |
|
|
|
0.72 |
|
Pro forma: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.44 |
|
|
$ |
0.73 |
|
Diluted |
|
|
1.36 |
|
|
|
0.69 |
|
Prior to the adoption of SFAS No. 123(R) on January 1, 2006, we did not assume the
capitalization of any stock-based compensation in our SFAS No. 123 pro forma net income. As a
result, no stock-based compensation expense is reflected as being capitalized in the table above.
Beginning in 2006, an appropriate portion of stock-based compensation associated with our employees
involved in our exploration and drilling activities has been capitalized as part of our Oil and Natural Gas Properties in the Consolidated Balance Sheet. The
effect of applying SFAS No. 123(R) during the year ended December 31, 2006, was to decrease net
income by approximately $6.4 million for stock compensation expense that would only have been
presented in footnote disclosures under the old requirements of SFAS No. 123. The effect on
earnings per share for the year ended December 31, 2006 was a decrease of $0.05 per both basic and
diluted share. Additionally, cash flow from operations was lower and cash flow from financing
activities was higher by approximately $16.6 million for the year ended December 31, 2006,
associated with the tax benefit for tax deductions in excess of recognized compensation expenses
that is now required to be reported as a financing cash flow.
Stock Options and SARs
The fair value of each stock option or SAR award is estimated on the date of grant using the
Black-Scholes option pricing model using the assumptions noted in the following table. The
risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury
yield curve in effect at the time of grant. The expected life of stock options and SARs granted
was derived from examination of our historical option grants and subsequent exercises. The
contractual terms (4-year cliff vesting and 4-year graded vesting) are evaluated separately for the
expected life, as the exercise behavior for each is different. Expected volatilities are based on
the historical volatility of our stock. Implied volatility was not used in this analysis as our
tradable call option terms are short and the trading volume is low. Our dividend yield is zero, as
Denbury does not pay a dividend.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
Weighted average fair value
of options granted |
|
$ 12.64 |
|
$ 6.94 |
|
$ 3.22 |
Risk free interest rate |
|
|
4.52% |
|
|
3.80% |
|
|
3.34% |
Expected life |
|
|
4.9 to 6.9 |
years |
|
5 |
years |
|
5 |
years |
Expected volatility |
|
|
41.1% |
|
|
42.6% |
|
|
46.8% |
Dividend yield |
|
|
|
|
|
|
|
|
|
77
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The
following is a summary of our stock option and SARs activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
Outstanding at beginning of year |
|
|
9,406,072 |
|
|
$ |
8.07 |
|
|
|
8,880,314 |
|
|
$ |
5.25 |
|
|
|
10,652,432 |
|
|
$ |
4.60 |
|
Granted |
|
|
517,155 |
|
|
|
27.16 |
|
|
|
2,483,254 |
|
|
|
16.29 |
|
|
|
2,019,620 |
|
|
|
7.18 |
|
Exercised |
|
|
(2,016,326 |
) |
|
|
5.53 |
|
|
|
(1,797,146 |
) |
|
|
5.37 |
|
|
|
(2,528,568 |
) |
|
|
4.25 |
|
Forfeited |
|
|
(424,441 |
) |
|
|
11.05 |
|
|
|
(160,350 |
) |
|
|
8.86 |
|
|
|
(1,263,170 |
) |
|
|
4.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
7,482,460 |
|
|
|
9.91 |
|
|
|
9,406,072 |
|
|
|
8.07 |
|
|
|
8,880,314 |
|
|
|
5.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year |
|
|
2,369,552 |
|
|
$ |
5.32 |
|
|
|
2,509,635 |
|
|
$ |
4.50 |
|
|
|
3,088,824 |
|
|
$ |
4.81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of stock options and SARs exercised during the years ended
December 31, 2006, 2005 and 2004 was approximately $49.3 million, $24.8 million and $13.2 million,
respectively. The total fair value of stock options and SARs vested during the years ended
December 31, 2006, 2005 and 2004 was approximately $6.0 million, $3.4 million and $1.8 million,
respectively. The aggregate intrinsic value of stock options and SARs outstanding at December 31,
2006, was approximately $133.8 million and these options and SARs have a weighted-average remaining
contractual life of 6.3 years. The aggregate intrinsic value of options exercisable at December
31, 2006, was approximately $53.2 million and these stock options and SARs have a weighted-average
remaining contractual life of 4.0 years.
A summary of the status of our non-vested stock options and SARs as of December 31, 2006, and
the changes during the year ended December 31, 2006, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant-Date |
|
Non-vested stock options and SARs |
|
Shares |
|
|
Fair Value |
|
Non-vested at January 1, 2006 |
|
|
6,896,437 |
|
|
$ |
4.25 |
|
Granted |
|
|
517,155 |
|
|
|
12.64 |
|
Vested |
|
|
(1,876,243 |
) |
|
|
3.20 |
|
Forfeited |
|
|
(424,441 |
) |
|
|
5.02 |
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2006 |
|
|
5,112,908 |
|
|
|
5.41 |
|
|
|
|
|
|
|
|
|
As of December 31, 2006, there was $11.9 million of total compensation cost to be
recognized in future periods related to non-vested stock option and SAR share-based compensation arrangements.
The cost is expected to be recognized over a weighted-average period of 1.2 years. Cash received
from stock option exercises under share-based payment arrangements for the year ended December 31,
2006, 2005 and 2004 was $11.1 million, $9.7 million and $10.7 million, respectively. The tax
benefit realized from the exercises of stock options and SARs totaled $14.7 million for 2006, $8.6
million for 2005, and $4.8 million for 2004.
Restricted Stock
As of December 31, 2006, we had issued 2,449,987 shares of restricted stock pursuant to the
2004 Plan and have recorded deferred compensation expense of $25.1 million, the fair market value
of the shares on the grant dates
net of estimated forfeitures of $2.2 million. This expense is amortized over the applicable
five-year, four-year, or retirement date vesting periods. As of December 31, 2006, there was $14.0
million of unrecognized compensation expense related to non-vested restricted stock grants. This
unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.9
years.
78
Denbury Resources Inc.
Notes to Consolidated Financial Statements
A summary of the status of our non-vested restricted stock grants as of December 31, 2006, and
the changes during the year ended December 31, 2006, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
|
Grant-Date |
|
Non-vested Restricted Stock Grants |
|
Shares |
|
|
Fair Value |
|
Non-vested at January 1, 2006 |
|
|
2,014,000 |
|
|
$ |
10.15 |
|
Granted |
|
|
129,987 |
|
|
|
28.92 |
|
Vested |
|
|
(528,815 |
) |
|
|
10.19 |
|
Forfeited |
|
|
(171,211 |
) |
|
|
10.31 |
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2006 |
|
|
1,443,961 |
|
|
|
11.80 |
|
|
|
|
|
|
|
|
|
The total vesting date fair value of restricted stock vested during the years
ended December 31, 2006 and 2005 was $17.4 million and $7.1 million, respectively.
Note 10. Derivative Instruments and Hedging Activities
Effective January 1, 2005, we elected to discontinue hedge accounting treatment for financial
statement purposes for our oil and natural gas derivative contracts and accordingly de-designated
our derivative instruments from hedge accounting treatment in accordance with SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activites. As a result of this change, we
began accounting for our oil and natural gas derivative contracts as speculative contracts in the
first quarter of 2005. As speculative contracts, the changes in the fair value of these
instruments are recognized in income in the period of change. Additionally, the balance remaining in Accumulated
Comprehensive Loss at December 31, 2004, related to the de-designated derivative contracts was amortized over
the remaining life of the contracts, all of which expired in 2005.
From time to time, we enter into various derivative contracts to economically 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 consisted of price floors, collars and fixed price swaps. Historically, prior to 2005, we
hedged up to 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. Since 2005 and beyond, we have entered into fewer derivative
contracts, primarily because of our strong financial position resulting from our lower levels of
debt relative to our cash flow from operations. We did make an exception in late 2006, when we
swapped 80% to 90% of our forecasted 2007 natural gas production at a weighted average price of
$7.96 per Mcf. We did this to protect our 2007 projected cash flow primarily because we currently
plan to spend more than we expect to generate from cash flows from operations and we did not want
to be exposed to the risk of lower natural gas prices.
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. As of December
31, 2006, we had derivative contracts in place related to the $250 million acquisition that closed
January 31, 2006, on which we entered into contracts to cover 100% of the estimated proved
production for three years at the time we signed the purchase and sale agreement. 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.
79
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following is a summary of the net loss on our commodity contracts that qualified for hedge
accounting treatment, covering those periods prior to our discontinuance of hedge accounting
effective January 1, 2005, and is included in Loss on effective hedge contracts in our
Consolidated Statements of Operations:
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
(In Thousands) |
|
2004 |
|
|
Settlements of hedge contracts Oil |
|
$ |
(50,072 |
) |
Settlements of hedge contracts Gas |
|
|
(20,397 |
) |
|
|
|
|
Loss on effective hedge contracts |
|
$ |
(70,469 |
) |
|
|
|
|
The following is a summary of Commodity derivative expense (income), included in our
Consolidated Statements of Operations. These amounts are associated with derivative contracts not designated as accounting hedges or the ineffective portion of contracts that qualified
as accounting hedges in 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Settlements of derivative contracts oil |
|
$ |
5,302 |
|
|
$ |
|
|
|
$ |
14,088 |
|
Settlements of derivative contracts gas |
|
|
|
|
|
|
16,761 |
|
|
|
|
|
Hedge ineffectiveness on contracts qualifying for hedge
accounting |
|
|
|
|
|
|
|
|
|
|
2,687 |
|
Reclassification of accumulated other comprehensive income
balance |
|
|
|
|
|
|
7,684 |
|
|
|
(955 |
) |
Fair value adjustments to derivative contracts |
|
|
(25,130 |
) |
|
|
4,517 |
|
|
|
(462 |
) |
|
|
|
|
|
|
|
|
|
|
Commodity derivative expense (income) |
|
$ |
(19,828 |
) |
|
$ |
28,962 |
|
|
$ |
15,358 |
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts at December 31, 2006:
Crude Oil Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
NYMEX Contract Prices Per Bbl |
|
Fair Value at |
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2007 - Dec. 2007 |
|
|
2,000 |
|
|
|
58.93 |
|
|
$ |
(4,302 |
) |
Jan. 2008 - Dec. 2008 |
|
|
2,000 |
|
|
|
57.34 |
|
|
|
(6,834 |
) |
Natural Gas Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
NYMEX Contract Prices Per MMBtu |
|
Fair Value at |
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2007 - Dec. 2007 |
|
|
20,000 |
|
|
|
7.99 |
|
|
$ |
7,340 |
|
Jan. 2007 - Dec. 2007 |
|
|
40,000 |
|
|
|
7.96 |
|
|
|
14,252 |
|
Jan. 2007 - Dec. 2007 |
|
|
15,000 |
|
|
|
7.95 |
|
|
|
5,291 |
|
At December 31, 2006, our derivative contracts were recorded at their fair value, which
was a net asset of $15.7 million.
80
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 11. Commitments and Contingencies
We have operating leases for the rental of equipment, office space, and vehicles that totaled
$101.4 million, $37.2 million, and $16.6 million as of December 31, 2006, 2005, and 2004,
respectively. During the last four years, we entered into lease financing agreements for equipment
at certain of our oil and natural gas properties and CO2 source fields. These lease
financings totaled $41.1 million during 2006, $17.3 million during 2005 and $6.9 million during
2004 with associated required monthly payments of $431,000 for the 2006 leases, $223,000 for the
2005 leases and $91,000 for the 2004 leases. Leases entered into prior to 2006 have seven-year
terms and the leases entered into in 2006 have a 10-year term. Rental expense for operating leases
totaled $14.1 million in 2006, $8.2 million in 2005, and $5.8 million in 2004.
In 2005 and 2006, we entered into three 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, 2006, long-term commitments for these items require the following future
minimum rental payments:
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
Operating |
|
(In Thousands) |
|
Leases |
|
|
Leases |
|
2007 |
|
$ |
1,291 |
|
|
$ |
13,056 |
|
2008 |
|
|
1,291 |
|
|
|
12,667 |
|
2009 |
|
|
1,529 |
|
|
|
11,857 |
|
2010 |
|
|
1,291 |
|
|
|
11,527 |
|
2011 |
|
|
1,291 |
|
|
|
10,967 |
|
Thereafter |
|
|
3,335 |
|
|
|
41,304 |
|
|
|
|
|
|
|
|
Total minimum lease payments |
|
|
10,028 |
|
|
$ |
101,378 |
|
|
|
|
|
|
|
|
|
Less: Amount representing interest |
|
|
(2,970 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Present value of minimum lease payments |
|
$ |
7,058 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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 three CO2 volumetric production payments (VPPs) (see Note 3). Based
upon the maximum amounts deliverable as stated in the industrial contracts and the volumetric
production payments, we estimate that we may be obligated to deliver up to 391 Bcf of
CO2 to these customers over the next 17 years, with a maximum volume required in any
given year of approximately 105 MMcf/d. 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 the amount of CO2 that we will ultimately be
required to deliver will be significantly less than the contractual commitment. Given the size of
our proven CO2 reserves at December 31, 2006 (approximately 5.5 Tcf before deducting
approximately 210.5 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. 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
81
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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.
Note 12. 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, 2006, two purchasers each
accounted for 10% or more of our oil and natural gas revenues: Marathon Ashland Petroleum LLC (28%)
and Hunt Crude Oil Supply Co. (18%). For the year ended December 31, 2005, we had three
significant purchasers that each accounted for 10% or more of our oil and natural gas revenues:
Marathon Ashland Petroleum LLC (28%), Hunt Crude Oil Supply Co. (20%) and Sunoco, Inc. (13%). For
the year ended December 31, 2004, two purchasers each accounted for 10% or more of our oil and
natural gas revenues: Hunt Crude Oil Supply Co. (21%) and Genesis (14%).
Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
2006 |
|
2005 |
Accounts payable |
|
$ |
57,637 |
|
|
$ |
53,306 |
|
Accrued exploration and development costs |
|
|
36,830 |
|
|
|
23,635 |
|
Accrued lease operating expense |
|
|
8,178 |
|
|
|
5,435 |
|
Hastings purchase option current |
|
|
6,794 |
|
|
|
|
|
Accrued compensation |
|
|
6,361 |
|
|
|
5,287 |
|
Accrued interest |
|
|
5,233 |
|
|
|
4,582 |
|
Taxes payable |
|
|
4,447 |
|
|
|
1,374 |
|
Asset retirement obligations current |
|
|
1,776 |
|
|
|
1,791 |
|
Other |
|
|
11,855 |
|
|
|
9,430 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
139,111 |
|
|
$ |
104,840 |
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Interest paid, net of amounts capitalized |
|
$ |
21,514 |
|
|
$ |
16,622 |
|
|
$ |
18,099 |
|
Interest capitalized |
|
|
11,333 |
|
|
|
1,649 |
|
|
|
|
|
Income taxes paid |
|
|
4,210 |
|
|
|
21,000 |
|
|
|
20,726 |
|
During 2006, we capitalized $11.0 million of interest on our significant unevaluated
properties, primarily related to the two recent acquisitions. Additionally, we capitalized $0.3
million in 2006 and $1.6 million in 2005, of interest relating to the construction of our
CO2 pipeline to East Mississippi. We recorded a non-cash increase to property and debt
in the amount of $1.2 million in 2006, $2.4 million in 2005 and $4.6 million in 2004, related to
capital leases. In 2004, we issued 2,300,000 shares of restricted stock with a market value of
$23.3 million on the date of grant. In 2005, we issued 20,000 shares of restricted stock with a
market value of $0.3 million on the date of grant. In 2006, we issued 129,987 shares of restricted
stock with a market value of $3.8 million on the date of grant. See Note 9 Stock Compensation
Plans Restricted Stock.
In November 2006, we entered into an agreement for the option to purchase an oil property for
an upfront payment of $37.5 million, plus required additional payments totaling $12.5 million
during the next 2 years. We have accrued the discounted present value of these required additional
payments ($11.4 million) and recorded this amount plus the upfront payment in Deposits on
properties under option or contract on our December 31, 2006 Consolidated Balance Sheet.
Additionally, the upfront payment of $37.5 million is recorded on our December 31, 2006
Consolidated Statement of Cash Flow Investing Activities.
82
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Fair Value of Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
2006 |
|
2005 |
|
|
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
|
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
7.5% Senior Subordinated Notes due 2013 |
|
$ |
223,786 |
|
|
$ |
227,250 |
|
|
$ |
223,591 |
|
|
$ |
228,375 |
|
7.5% Senior Subordinated Notes due 2015 |
|
|
150,000 |
|
|
|
152,250 |
|
|
|
150,000 |
|
|
|
152,250 |
|
Senior Bank Loan |
|
|
134,000 |
|
|
|
134,000 |
|
|
|
|
|
|
|
|
|
The fair values of our senior subordinated notes are based on quoted market prices. The
carrying value of our Senior Bank Loan is approximately fair value based on the fact that it is
subject to short-term floating interest rates that approximate the rates available to us for those
periods. 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 13. Condensed Consolidating Financial Information
Since December 29, 2003, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors of
our subordinated debt. Our subordinated debt is fully and unconditionally guaranteed jointly and
severally by all of Denbury Resources Inc.s subsidiaries other than minor subsidiaries. The
results of our equity interest in Genesis are reflected through the equity method by one of our
subsidiaries, Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary
co-obligor are 100% owned, directly or indirectly, by Denbury Resources Inc. The following is
condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and
significant subsidiaries:
83
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, 2006 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Co-obligor) |
|
|
Co-obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
392,372 |
|
|
$ |
180,476 |
|
|
$ |
3,662 |
|
|
$ |
(393,241 |
) |
|
$ |
183,269 |
|
Property and equipment |
|
|
|
|
|
|
1,879,742 |
|
|
|
26 |
|
|
|
|
|
|
|
1,879,768 |
|
Investment in subsidiaries (equity method) |
|
|
709,611 |
|
|
|
|
|
|
|
709,020 |
|
|
|
(1,407,991 |
) |
|
|
10,640 |
|
Other assets |
|
|
154,076 |
|
|
|
64,391 |
|
|
|
154 |
|
|
|
(152,461 |
) |
|
|
66,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,256,059 |
|
|
$ |
2,124,609 |
|
|
$ |
712,862 |
|
|
$ |
(1,953,693 |
) |
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
590,602 |
|
|
$ |
3,037 |
|
|
$ |
(393,241 |
) |
|
$ |
200,398 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
835,627 |
|
|
|
214 |
|
|
|
(152,461 |
) |
|
|
833,380 |
|
Stockholders equity |
|
|
1,106,059 |
|
|
|
698,380 |
|
|
|
709,611 |
|
|
|
(1,407,991 |
) |
|
|
1,106,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and stockholders equity |
|
$ |
1,256,059 |
|
|
$ |
2,124,609 |
|
|
$ |
712,862 |
|
|
$ |
(1,953,693 |
) |
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, 2005 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Co-obligor) |
|
|
Co-obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
222,858 |
|
|
$ |
297,575 |
|
|
$ |
2,577 |
|
|
$ |
(223,827 |
) |
|
$ |
299,183 |
|
Property and equipment |
|
|
|
|
|
|
1,155,923 |
|
|
|
47 |
|
|
|
|
|
|
|
1,155,970 |
|
Investment in subsidiaries (equity method) |
|
|
506,862 |
|
|
|
|
|
|
|
505,540 |
|
|
|
(1,001,573 |
) |
|
|
10,829 |
|
Other assets |
|
|
154,288 |
|
|
|
37,120 |
|
|
|
169 |
|
|
|
(152,490 |
) |
|
|
39,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
884,008 |
|
|
$ |
1,490,618 |
|
|
$ |
508,333 |
|
|
$ |
(1,377,890 |
) |
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
346 |
|
|
$ |
376,194 |
|
|
$ |
1,351 |
|
|
$ |
(223,827 |
) |
|
$ |
154,064 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
619,713 |
|
|
|
120 |
|
|
|
(152,490 |
) |
|
|
617,343 |
|
Stockholders equity |
|
|
733,662 |
|
|
|
494,711 |
|
|
|
506,862 |
|
|
|
(1,001,573 |
) |
|
|
733,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
884,008 |
|
|
$ |
1,490,618 |
|
|
$ |
508,333 |
|
|
$ |
(1,377,890 |
) |
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, 2006 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Co-obligor) |
|
|
Co-obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
11,219 |
|
|
$ |
731,516 |
|
|
$ |
20 |
|
|
$ |
(11,219 |
) |
|
$ |
731,536 |
|
Expenses |
|
|
11,581 |
|
|
|
400,657 |
|
|
|
1,719 |
|
|
|
(11,219 |
) |
|
|
402,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(362 |
) |
|
|
330,859 |
|
|
|
(1,699 |
) |
|
|
|
|
|
|
328,798 |
|
Equity in net earnings of subsidiaries |
|
|
202,749 |
|
|
|
|
|
|
|
204,445 |
|
|
|
(406,418 |
) |
|
|
776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
202,387 |
|
|
|
330,859 |
|
|
|
202,746 |
|
|
|
(406,418 |
) |
|
|
329,574 |
|
Income tax provision (benefit) |
|
|
(70 |
) |
|
|
127,189 |
|
|
|
(2 |
) |
|
|
|
|
|
|
127,117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
202,457 |
|
|
$ |
203,670 |
|
|
$ |
202,748 |
|
|
$ |
(406,418 |
) |
|
$ |
202,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, 2005 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Co-obligor) |
|
|
Co-obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
313 |
|
|
$ |
560,079 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
560,392 |
|
Expenses |
|
|
485 |
|
|
|
310,974 |
|
|
|
1,206 |
|
|
|
|
|
|
|
312,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(172 |
) |
|
|
249,105 |
|
|
|
(1,206 |
) |
|
|
|
|
|
|
247,727 |
|
Equity in net earnings of subsidiaries |
|
|
166,576 |
|
|
|
|
|
|
|
167,378 |
|
|
|
(333,640 |
) |
|
|
314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
166,404 |
|
|
|
249,105 |
|
|
|
166,172 |
|
|
|
(333,640 |
) |
|
|
248,041 |
|
Income tax provision (benefit) |
|
|
(67 |
) |
|
|
82,041 |
|
|
|
(404 |
) |
|
|
|
|
|
|
81,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
166,471 |
|
|
$ |
167,064 |
|
|
$ |
166,576 |
|
|
$ |
(333,640 |
) |
|
$ |
166,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 (benefit) |
|
|
(65 |
) |
|
|
30,082 |
|
|
|
9,375 |
|
|
|
|
|
|
|
39,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
82,448 |
|
|
$ |
67,258 |
|
|
$ |
82,554 |
|
|
$ |
(149,812 |
) |
|
$ |
82,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, 2006 |
|
|
|
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 |
|
$ |
|
|
|
$ |
460,841 |
|
|
$ |
969 |
|
|
$ |
|
|
|
$ |
461,810 |
|
Cash flow from investing activities |
|
|
(150,864 |
) |
|
|
(856,625 |
) |
|
|
(2 |
) |
|
|
150,864 |
|
|
|
(856,627 |
) |
Cash flow from financing activities |
|
|
150,864 |
|
|
|
283,601 |
|
|
|
|
|
|
|
(150,864 |
) |
|
|
283,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
(112,183 |
) |
|
|
967 |
|
|
|
|
|
|
|
(111,216 |
) |
Cash, beginning of period |
|
|
1 |
|
|
|
164,408 |
|
|
|
680 |
|
|
|
|
|
|
|
165,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
1 |
|
|
$ |
52,225 |
|
|
$ |
1,647 |
|
|
$ |
|
|
|
$ |
53,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, 2005 |
|
|
|
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 |
|
$ |
(5,298 |
) |
|
$ |
365,714 |
|
|
$ |
544 |
|
|
$ |
|
|
|
$ |
360,960 |
|
Cash flow from investing activities |
|
|
(150,000 |
) |
|
|
(383,666 |
) |
|
|
(21 |
) |
|
|
150,000 |
|
|
|
(383,687 |
) |
Cash flow from financing activities |
|
|
155,298 |
|
|
|
149,479 |
|
|
|
|
|
|
|
(150,000 |
) |
|
|
154,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
|
|
|
|
131,527 |
|
|
|
523 |
|
|
|
|
|
|
|
132,050 |
|
Cash, beginning of period |
|
|
1 |
|
|
|
32,881 |
|
|
|
157 |
|
|
|
|
|
|
|
33,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
1 |
|
|
$ |
164,408 |
|
|
$ |
680 |
|
|
$ |
|
|
|
$ |
165,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 in cash |
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 14. 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
86
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Property acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
137,891 |
|
|
$ |
63,509 |
|
|
$ |
22,271 |
|
Unevaluated |
|
|
205,506 |
|
|
|
32,874 |
|
|
|
3,459 |
|
Exploration |
|
|
43,564 |
|
|
|
45,652 |
|
|
|
23,987 |
|
Development |
|
|
440,827 |
|
|
|
237,201 |
|
|
|
128,351 |
|
Asset retirement obligations |
|
|
12,803 |
|
|
|
4,559 |
|
|
|
3,174 |
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred (1) |
|
$ |
840,591 |
|
|
$ |
383,795 |
|
|
$ |
181,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Capitalized general and administrative costs that directly relate to exploration and
development activities were $7.6 million, $5.1 million, and $5.1 million for the years
ended December 31, 2006, 2005 and 2004, 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, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Oil, natural gas and related product sales |
|
$ |
716,557 |
|
|
$ |
549,055 |
|
|
$ |
444,777 |
|
Loss on effective hedge contracts |
|
|
|
|
|
|
|
|
|
|
(70,469 |
) |
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
716,557 |
|
|
|
549,055 |
|
|
|
374,308 |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs |
|
|
167,271 |
|
|
|
108,550 |
|
|
|
87,107 |
|
Production taxes and marketing expenses |
|
|
36,351 |
|
|
|
27,582 |
|
|
|
18,737 |
|
Depletion, depreciation and amortization |
|
|
135,269 |
|
|
|
90,631 |
|
|
|
90,913 |
|
CO2 depletion, depreciation and amortization (1) |
|
|
6,281 |
|
|
|
3,894 |
|
|
|
3,405 |
|
Commodity derivative expense (income) |
|
|
(19,828 |
) |
|
|
28,962 |
|
|
|
15,358 |
|
|
|
|
|
|
|
|
|
|
|
Net operating income |
|
|
391,213 |
|
|
|
289,436 |
|
|
|
158,788 |
|
Income tax provision |
|
|
151,008 |
|
|
|
95,224 |
|
|
|
51,289 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and natural gas producing activities |
|
$ |
240,205 |
|
|
$ |
194,212 |
|
|
$ |
107,499 |
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization per BOE |
|
$ |
10.54 |
|
|
$ |
8.69 |
|
|
$ |
7.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents an allocation of the depletion, depreciation and amortization of our CO2 properties associated with our tertiary oil producing activities. |
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 few years.
87
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
Oil |
|
|
Gas |
|
|
Oil |
|
|
Gas |
|
|
Oil |
|
|
Gas |
|
|
|
(MBBL) |
|
|
(MMCF) |
|
|
(MBBL) |
|
|
(MMCF) |
|
|
(MBBL) |
|
|
(MMCF) |
|
Balance at beginning of year |
|
|
106,173 |
|
|
|
278,367 |
|
|
|
101,287 |
|
|
|
168,484 |
|
|
|
91,266 |
|
|
|
221,887 |
|
Revisions of previous estimates |
|
|
4,351 |
|
|
|
(22,279 |
) |
|
|
(3,613 |
) |
|
|
(12,047 |
) |
|
|
(3,271 |
) |
|
|
2,898 |
|
Revisions due to price changes |
|
|
(2 |
) |
|
|
(3,116 |
) |
|
|
872 |
|
|
|
1,268 |
|
|
|
492 |
|
|
|
25 |
|
Extensions and discoveries |
|
|
4,587 |
|
|
|
65,582 |
|
|
|
1,214 |
|
|
|
117,512 |
|
|
|
1,575 |
|
|
|
61,158 |
|
Improved recovery (1) |
|
|
5,044 |
|
|
|
|
|
|
|
13,276 |
|
|
|
|
|
|
|
18,863 |
|
|
|
|
|
Production |
|
|
(8,372 |
) |
|
|
(30,322 |
) |
|
|
(7,305 |
) |
|
|
(21,424 |
) |
|
|
(7,044 |
) |
|
|
(30,094 |
) |
Acquisition of minerals in place |
|
|
14,424 |
|
|
|
643 |
|
|
|
442 |
|
|
|
24,574 |
|
|
|
429 |
|
|
|
5,304 |
|
Sales of minerals in place |
|
|
(20 |
) |
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
(1,023 |
) |
|
|
(92,694 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
|
126,185 |
|
|
|
288,826 |
|
|
|
106,173 |
|
|
|
278,367 |
|
|
|
101,287 |
|
|
|
168,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year |
|
|
59,640 |
|
|
|
151,681 |
|
|
|
55,998 |
|
|
|
94,573 |
|
|
|
53,804 |
|
|
|
144,750 |
|
Balance at end of year |
|
|
83,703 |
|
|
|
176,648 |
|
|
|
59,640 |
|
|
|
151,681 |
|
|
|
55,998 |
|
|
|
94,573 |
|
|
|
|
(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 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 reductions in oil and
gas prices can 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, |
|
|
2006 |
|
2005 |
|
2004 |
Oil (NYMEX) |
|
$ |
61.05 |
|
|
$ |
61.04 |
|
|
$ |
43.45 |
|
Natural Gas (Henry Hub) |
|
|
5.63 |
|
|
|
10.08 |
|
|
|
6.18 |
|
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.
88
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Future cash inflows |
|
$ |
8,185,682 |
|
|
$ |
8,197,957 |
|
|
$ |
4,742,276 |
|
Future production costs |
|
|
(2,697,206 |
) |
|
|
(2,069,015 |
) |
|
|
(1,509,280 |
) |
Future development costs |
|
|
(565,488 |
) |
|
|
(525,877 |
) |
|
|
(340,879 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows before taxes |
|
|
4,922,988 |
|
|
|
5,603,065 |
|
|
|
2,892,117 |
|
Future income taxes |
|
|
(1,519,179 |
) |
|
|
(1,944,430 |
) |
|
|
(906,221 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
3,403,809 |
|
|
|
3,658,635 |
|
|
|
1,985,896 |
|
10% annual discount for estimated timing of cash flows |
|
|
(1,566,468 |
) |
|
|
(1,574,186 |
) |
|
|
(856,700 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
1,837,341 |
|
|
$ |
2,084,449 |
|
|
$ |
1,129,196 |
|
|
|
|
|
|
|
|
|
|
|
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, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Beginning of year |
|
$ |
2,084,449 |
|
|
$ |
1,129,196 |
|
|
$ |
1,124,127 |
|
Sales of oil and natural gas produced, net of production costs |
|
|
(512,935 |
) |
|
|
(412,923 |
) |
|
|
(339,250 |
) |
Net changes in sales prices |
|
|
(552,772 |
) |
|
|
1,261,231 |
|
|
|
352,830 |
|
Extensions and discoveries, less applicable future development
and production costs |
|
|
124,787 |
|
|
|
461,936 |
|
|
|
151,014 |
|
Improved recovery (1) |
|
|
117,342 |
|
|
|
204,116 |
|
|
|
190,033 |
|
Previously estimated development costs incurred |
|
|
124,207 |
|
|
|
110,424 |
|
|
|
55,091 |
|
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production |
|
|
(324,608 |
) |
|
|
(261,730 |
) |
|
|
(197,959 |
) |
Accretion of discount |
|
|
321,548 |
|
|
|
164,329 |
|
|
|
156,637 |
|
Acquisition of minerals in place |
|
|
182,374 |
|
|
|
44,807 |
|
|
|
9,003 |
|
Sales of minerals in place |
|
|
(222 |
) |
|
|
|
|
|
|
(300,481 |
) |
Net change in income taxes |
|
|
273,171 |
|
|
|
(616,937 |
) |
|
|
(71,849 |
) |
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
1,837,341 |
|
|
$ |
2,084,449 |
|
|
$ |
1,129,196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 5.5 Tcf at
December 31, 2006 (includes 210.5 Bcf of reserves dedicated to three volumetric production payments
with Genesis), 4.6 Tcf at December 31, 2005 (includes 237.1 Bcf of reserves dedicated to three
volumetric production payments with Genesis), and 2.7 Tcf at December 31, 2004 (includes 178.7 Bcf
of reserves dedicated to two volumetric production payments with Genesis). We make reference to
the gross amount of proved reserves as that is the amount that is available both for Denburys
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.
89
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 15. Unaudited Quarterly Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Thousands, Except Per Share Amounts |
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
178,906 |
|
|
$ |
193,247 |
|
|
$ |
192,044 |
|
|
$ |
167,339 |
|
Expenses |
|
|
107,398 |
|
|
|
119,978 |
|
|
|
97,237 |
|
|
|
78,125 |
|
Net income |
|
|
43,778 |
|
|
|
44,262 |
|
|
|
59,294 |
|
|
|
55,123 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
0.39 |
|
|
|
0.38 |
|
|
|
0.50 |
|
|
|
0.46 |
|
Diluted |
|
|
0.37 |
|
|
|
0.36 |
|
|
|
0.48 |
|
|
|
0.45 |
|
Cash flow from operations |
|
|
102,512 |
|
|
|
106,417 |
|
|
|
135,365 |
|
|
|
117,516 |
|
Cash flow used for investing activities (1) |
|
|
(347,684 |
) |
|
|
(205,495 |
) |
|
|
(143,349 |
) |
|
|
(160,099 |
) |
Cash flow provided by financing activities (2) |
|
|
110,067 |
|
|
|
99,906 |
|
|
|
6,096 |
|
|
|
67,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
113,362 |
|
|
$ |
127,983 |
|
|
$ |
141,858 |
|
|
$ |
177,189 |
|
Expenses |
|
|
69,754 |
|
|
|
67,491 |
|
|
|
83,249 |
|
|
|
92,171 |
|
Net income |
|
|
30,067 |
|
|
|
40,672 |
|
|
|
38,546 |
|
|
|
57,186 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
0.27 |
|
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.51 |
|
Diluted |
|
|
0.26 |
|
|
|
0.34 |
|
|
|
0.32 |
|
|
|
0.48 |
|
Cash flow from operations |
|
|
66,629 |
|
|
|
88,385 |
|
|
|
76,287 |
|
|
|
129,659 |
|
Cash flow used for investing activities (3) |
|
|
(59,614 |
) |
|
|
(117,530 |
) |
|
|
(75,840 |
) |
|
|
(130,703 |
) |
Cash flow provided by financing activities (4) |
|
|
2,688 |
|
|
|
11,719 |
|
|
|
11,227 |
|
|
|
129,143 |
|
|
|
|
(1) |
|
In January 2006, we acquired three oil properties for
approximately $250 million (including the $25 million of earnest
money paid in the fourth quarter of 2005). In May 2006, we
acquired an oil property for $50 million, plus a reversionary
interest. In November 2006, we entered into an agreement for the
option to purchase an oil property for an upfront payment of $37.5
million, plus required additional payments totaling $12.5 million.
(See Note 2. Acquisitions and Divestitures.) |
|
(2) |
|
In April, we sold $125 million (net to Denbury) of common stock in
a public offering (see Note 8. Stockholders Equity Stock
Issuance). We had net borrowings of $100 million and $64 million
in the first and fourth quarters of 2006, respectively, and net
repayments of $30 million in the second quarter of 2006, all under
our senior bank loan. |
|
(3) |
|
In November 2005, we made a $25 million deposit of earnest money
associated with a pending acquisition of oil properties (see Note
2. Acquisitions and Divestitures). |
|
(4) |
|
In December 2005, we issued $150 million of 7.5% Senior
Subordinated Notes due 2015 (see Note 6. Notes Payable and
Long-Term Indebtedness). |
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
There have been no changes in accountants nor any disagreements with accountants.
Item 9A. Controls and Procedures
Disclosure 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 Commissions 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 as of December 31, 2006, in ensuring that material information required to be disclosed
in this annual report is accumulated and communicated to them and our management to allow timely
decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During 2005 and 2006, information was reported on our whistleblower hotline regarding
misconduct by oilfield vendors and certain employees, including alleged improper billings and
payments by certain vendors to, or
90
Denbury Resources Inc.
on behalf of employees, misuse of Company property, services and operational information by
employees, and the failure by certain employees to properly report transactions with the Company.
During 2005 and 2006, at the direction of the Audit Committee of our Board of Directors, and in
conjunction with outside counsel retained by the Audit Committee, investigations were undertaken
regarding these matters. These investigations are substantially complete. As a result of our
investigations, we have dismissed eight employees, taken disciplinary action against another
employee, and terminated all future business with certain vendors. The estimated amount of
improper vendor billings and payments and misuse of Company property and services is
inconsequential to our previously issued financial statements and to the financial statements
contained in this report on Form 10-K. We further believe that these matters have not, and will
not, materially adversely affect our financial condition, results of operations or business. We
believe that our whistleblower hotline was effective in alerting us to improper vendor and employee
conduct and allowing us to remedy the matter.
Controls and policies in place to prevent these occurrences were overridden by employee
misconduct in the vendor approval and payment process and in adherence to the Companys Code of
Business Conduct and Ethics. As a result of our investigation, we have, and are continuing, to
implement certain improvements to strengthen our internal controls (see also Item 9A. Controls and
Procedures Disclosure Controls and Procedures contained in our 2005 Form 10-K for further
information) and to improve our management practices and policies. Various management changes have
been made, combined with an emphasis upon both strengthening our internal controls and improving
management oversight and enforcement of Company policies and procedures at the field level.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Except as disclosed below, information as to Item 10 will be set forth in the Proxy Statement
(Proxy Statement) for the Annual Meeting of Shareholders to be held May 15, 2007, (Annual
Meeting) and is incorporated herein by reference.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 and the rules thereunder require the
Companys executive officers and directors, and persons who beneficially own more than ten percent
(10%) of a registered class of the Companys 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 aware of one filing that was not timely
made by Mr. Gareth Roberts, President and CEO, who failed to timely file a Form 5 reporting the
transfer of shares as a gift to his minor children.
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 as to Item 11 will be set forth 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 Item 12 will be set forth in the Proxy Statement for the Annual Meeting and
is incorporated herein by reference.
91
Denbury Resources Inc.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and
is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Information as to Item 14 will be set forth 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 53. 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). |
|
|
|
|
|
2(b)
|
|
|
|
Stock Purchase Agreement made as of July 19, 2004, between Denbury Resources Inc. and
Newfield 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)
|
|
|
|
Certificate of Amendment of Restated Certificate of Incorporation of Denbury Resources Inc.
filed
with the Delaware Secretary of State on October 20, 2005 (incorporated by reference as Exhibit
3(a) of our Form 10-Q filed November 8, 2005). |
|
|
|
|
|
3(c)
|
|
|
|
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 $150 million of 7.5% Senior Subordinated Notes due 2015 among Denbury
Resources Inc., certain of its subsidiaries, and JP Morgan Chase Bank, as trustee
(incorporated by reference as Exhibit 4.1 of our Form 8-K filed December 9, 2005). |
|
|
|
|
|
4(b)
|
|
|
|
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 as Exhibit 4(a) to our Registration Statement No. 333-105233-
04 on Form S-4, filed May 14, 2003). |
|
|
|
|
|
4(c)
|
|
|
|
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)
|
|
|
|
Purchase and Sale Agreement dated as of November 9, 2005, by and among Merit Management
Partners I, L. P., Merit Energy Partners III, L.P. and Merit Energy Partners D-III, L.P., and
Denbury Onshore, LLC. (incorporated by reference as Exhibit 10.1 of our Form 8-K filed
February 3, 2006). |
|
|
|
|
|
10(b)
|
|
|
|
Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower,
Denbury Resources Inc., as Parent Guarantor and JPMorgan Chase Bank, N.A., as Administrative
Agent, and certain other financial institutions, dated September 14, 2006 (incorporated by
reference as Exhibit 10.1 of our Form 8-K filed September 19, 2006). |
|
|
|
|
|
10(c) *
|
|
|
|
Amendment for Increased Commitment from $150 million to $250 million to Sixth Amended and
Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, Denbury Resources Inc, |
92
Denbury Resources Inc.
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Exhibit |
|
|
|
|
as
Parent Guarantor, Bank One, N.A. as Administrative Agent, and certain other financial
institutions dated as of December 22, 2006. |
|
|
|
|
|
10(d)
|
|
**
|
|
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(e)
|
|
**
|
|
Denbury Resources Inc. Stock Purchase Plan, as amended (incorporated by reference as Exhibit
4(g) of our 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(f)
|
|
**
|
|
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(g)
|
|
**
|
|
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, amended March
2, 2001 and May 11, 2005). |
|
|
|
|
|
10(h)
|
|
**
|
|
Denbury Resources Severance Protection Plan, dated December 6, 2000 (incorporated by
reference as Exhibit 10(f) of our Form 10-K for the year ended December 31, 2000). |
|
|
|
|
|
10(i)
|
|
**
|
|
Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan as amended (incorporated by
reference as Exhibit 10(g) of our Form 10-K for the year ended December 31, 2004). |
|
|
|
|
|
10(j) |
|
**
|
|
Description of cash bonus compensation arrangements for employees and officers (incorporated
by reference as exhibit 10 (l) of our Form 10-K for the year ended December 31, 2005). |
|
|
|
|
|
10(k)*
|
|
**
|
|
Description of equity and other long-term award grant practices for employees and officers. |
|
|
|
|
|
10(l)*
|
|
**
|
|
Description of non-employee directors compensation arrangements. |
|
|
|
|
|
10(m)
|
|
**
|
|
2004 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. (incorporated by reference
as Exhibit 10(k) of our Form 10-K for the year ended December 31, 2004). |
|
|
|
|
|
10(n)
|
|
**
|
|
2004 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. (incorporated by reference as
Exhibit 10(l) of our Form 10-K for the year ended December 31, 2004). |
|
|
|
|
|
10(o)
|
|
**
|
|
2004 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. (incorporated by reference
as Exhibit 10(m) of our Form 10-K for the year ended December 31, 2004). |
|
|
|
|
|
10(p)
|
|
**
|
|
2005 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. (incorporated by reference as Exhibit 10(n) of our Form 10-K for
the year ended December 31, 2004). |
|
|
|
|
|
10(q)
|
|
**
|
|
2005 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. (incorporated by reference as Exhibit 10(o) of our From 10-K for the
year ended December 31, 2004). |
|
|
|
|
|
10(r)
|
|
**
|
|
2005 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. (incorporated by reference as Exhibit 10(p) of our Form 10-K for the
year ended December 31, 2004). |
|
|
|
|
|
10(s)
|
|
**
|
|
2005 form of non-qualified stock option agreement that cliff 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. (incorporated by reference as Exhibit 10(q) of
our Form 10-K for the year ended December 31, 2004). |
|
|
|
|
|
10(t)
|
|
**
|
|
2006 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 and Incentive Plan for
Denbury Resources Inc. (incorporated by reference as Exhibit 10(v) of our Form 10-K for the
year ended December 31, 2005). |
|
|
|
|
|
10(u)
|
|
**
|
|
2006 form of stock appreciation rights agreement that 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. (incorporated by reference as Exhibit 10 (w) of our Form 10-K for
the year ended December 31, 2005). |
93
Denbury Resources Inc.
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Exhibit |
10(v)
|
|
**
|
|
2006 form of stock appreciation rights agreement that cliff vests 100% four years from the
date of grant, for grants to directors pursuant to 2004 Omnibus Stock and Incentive Plan for
Denbury Resources Inc. (incorporated by reference as Exhibit 10 (x) of our Form 10-K for the
year ended December 31, 2005). |
|
|
|
|
|
10(w)
|
|
**
|
|
2006 form of restricted stock award that vests 25% per annum, for grants to new employees and
officers on their hire date pursuant to 2004 Omnibus and Incentive Plan for Denbury Resources
Inc. (incorporated by reference as Exhibit 10 (y) of our Form 10-K for the year ended December
31, 2005). |
|
|
|
|
|
10(x)
|
|
**
|
|
2006 form of restricted stock award 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. (incorporated by reference as Exhibit 10 (z) of our Form 10-K for the
year ended December 31, 2005). |
|
|
|
|
|
10(y)*
|
|
**
|
|
2007 form of restricted stock award to officers that cliff vests on March 31, 2010 pursuant to
2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
|
|
10(z)*
|
|
**
|
|
2007 form of performance share awards to officers pursuant to 2004 Omnibus Stock and Incentive
Plan for Denbury Resources Inc. |
|
|
|
|
|
10(aa)*
|
|
**
|
|
2007 form of restricted stock award to directors that cliff vests after three years pursuant
to 2004 Omnibus Stock and Incentive Plan. |
|
|
|
|
|
10(bb)
|
|
**
|
|
Form of deferred payment cash award that cliff vests 100% four years from the date of
grant for grants to employees and officers (incorporated by reference as Exhibit 10 (bb) of
our Form 10-K for the year ended December 31, 2005). |
|
|
|
|
|
10(cc)
|
|
|
|
Form of deferred payment cash award
that vests 25% per annum,
for grants to new employees and officers on their date of hire (incorporated by reference as Exhibit 10(aa) of
our Form 10-K for the year ended December 31, 2005). |
|
|
|
|
|
16
|
|
|
|
Letter from Deloitte & Touche LLP to the Securities and Exchange Commission dated May 24,
2005, regarding changes in certifying accountant, pursuant to Item 304(a)(3) of Regulation S-K
(incorporated by reference as Exhibit 16.1 of our Form 8-K/A filed May 24, 2005). |
|
|
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21*
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List of subsidiaries of Denbury Resources Inc. |
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23(a)*
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Consent of PricewaterhouseCoopers LLP. |
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23(b)*
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Consent of DeGolyer and MacNaughton. |
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31(a)*
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Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002. |
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31(b)*
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Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002. |
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32*
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Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |
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99*
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The summary of DeGolyer and MacNaughtons Report as of December 31, 2006, on oil and gas
reserves (SEC Case) dated February 14, 2007. |
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* |
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Filed herewith. |
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Compensation arrangements. |
94
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.
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DENBURY RESOURCES INC.
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February 28, 2007 |
/s/ Phil Rykhoek
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Phil Rykhoek |
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Sr. Vice President and Chief Financial Officer |
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February 28, 2007 |
/s/ Mark C. Allen
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Mark C. Allen |
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Vice President and Chief Accounting Officer |
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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.
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February 28, 2007 |
/s/ Gareth Roberts
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Gareth Roberts |
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Director, President and Chief Executive Officer
(Principal Executive Officer) |
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February 28, 2007 |
/s/ Phil Rykhoek
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Phil Rykhoek |
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Sr. Vice President and Chief Financial Officer
(Principal Financial Officer) |
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February 28, 2007 |
/s/ Mark C. Allen
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Mark C. Allen |
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Vice President and Chief Accounting Officer
(Principal Accounting Officer) |
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February 28, 2007 |
/s/ Ron Greene
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Ron Greene |
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Director |
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February 28, 2007 |
/s/ David I. Heather
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David I. Heather |
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Director |
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February 28, 2007 |
/s/ Randy Stein
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Randy Stein |
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Director |
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95
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February 28, 2007 |
/s/ Wieland Wettstein
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Wieland Wettstein |
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Director |
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February 28, 2007 |
/s/ Greg McMichael
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Greg McMichael |
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Director |
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February 28, 2007 |
/s/ Donald Wolf
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Donald Wolf |
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Director |
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96