e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2007 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, 2007
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
of incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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5100 Tennyson Parkway,
Suite 1200, Plano, TX
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75024 |
(Address of principal executive offices)
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(Zip Code) |
Registrants telephone number, including area code: (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 |
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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 N 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, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company)
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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 $3,233,003,475.
The number of shares outstanding of the registrants Common
Stock as of January 31, 2008, was 245,193,057.
DOCUMENTS INCORPORATED BY REFERENCE
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Document: |
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Incorporated as to: |
1.
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Notice and Proxy Statement for
the Annual Meeting of Shareholders
to be held May 15, 2008.
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1. |
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Part III, Items 10, 11, 12, 13, 14 |
Denbury Resources Inc.
2007
Annual Report on Form 10-K
Table of Contents
2
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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Bcfe
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One billion 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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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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MMcf/d
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One million cubic feet of natural
gas or CO2
per day. |
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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%. PV-10 Value is a
non-GAAP measure and its use is further discussed in footnote 3 to the table on page 20. |
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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 Mississippi,
Louisiana, Texas and Alabama. 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, 2007, we had
686 employees, 420 of whom were employed in field operations or at the field offices. Our employee
count does not include the approximately 660 employees of Genesis Energy, Inc. as of December 31,
2007, 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 2007, we continued to focus on carbon dioxide (CO2) enhanced oil recovery.
We continued the expansion of our Phase I and Phase II tertiary floods and initiated tertiary
projects at Lockhart Crossing, our first Louisiana field in Phase I (see description of the various
phases below), Tinsley Field in Phase III, and Cranfield Field in Phase IV. We increased our
potential tertiary flood candidates during 2007 with the acquisition of significant positions in
Oyster Bayou, Fig Ridge and Gillock Fields, Phases VII and VIII, adding to our inventory of future
tertiary floods. In addition to our development, expansion and acquisition of new floods, we also
made the strategic decision to divest our natural gas assets in South Louisiana that did not
contain future CO2 potential in order to further narrow our focus on CO2
enhanced oil recovery and our core assets. During the last eight years, we have learned a
considerable amount about tertiary operations and working with 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, the location of 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 approximately 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 project
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 CO2 reserves and pipeline 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.
Tertiary Recovery Phases
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 NEJD
CO2 Pipeline that we acquired in 2001. The most significant fields in this area are
Little Creek, Mallalieu, McComb and Brookhaven. We further expanded our Phase I area by developing
Lockhart Crossing Field in South Louisiana during 2007. Lockhart Crossing, although a relatively
small field, is the first of three fields to be CO2 flooded in Louisiana and our first
flood outside the state of Mississippi. Phase II, which began with the early 2006 completion of
the Free State CO2 Pipeline to East Mississippi, includes Eucutta, Soso, Martinville and
Heidelberg Fields. Tinsley Field, located northwest of
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Denbury Resources Inc.
Jackson, Mississippi, acquired in January 2006, is our Phase III and is serviced by that
portion of the Delta CO2 Pipeline completed in January 2008. 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. Flooding in Phase V will begin in 2009 upon completion of the Delta
CO2 Pipeline from Tinsley to Delhi. Citronelle Field in Southwest Alabama, another
field acquired in 2006, is our Phase VI which will require an extension to the Free State
CO2 Pipeline, the timing of which is uncertain at this time. Our last two currently
existing phases will require completion of our proposed 300-mile Green Pipeline, which will run
from Southern Louisiana to near Houston, Texas, and is scheduled for completion in late 2009 or
2010. Hastings Field, a field on which we acquired a purchase option in late 2006, is our Phase
VII and the Seabreeze Complex, acquired in 2007, will be our Phase VIII.
Jackson Dome. In February 2001, we acquired approximately 800 Bcf of proved producing
CO2 reserves for $42 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 15 additional CO2 producing wells,
significantly increasing our estimated proved CO2 reserves to approximately 5.6 Tcf as
of December 31, 2007, which is almost enough for our existing and currently planned phases of
operations. The estimate of 5.6 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 proved CO2 reserves prepared
by DeGolyer and 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 four development wells and one exploratory
well during 2008.
During the fourth quarter of 2007, we produced an average of 533 MMcf/d of CO2, a
35% increase over one year ago. We sold an average of 99 MMcf/d of CO2 to commercial
users, and we used an average of 434 MMcf/d for our tertiary activities. We estimate that our
current daily CO2 deliverability is around 700 MMcf/d. By year-end 2008, we estimate
that our planned tertiary operations will require approximately 800 MMcf/d, which we believe we can
attain with our planned 2008 Jackson Dome projects. Our geoscientists are using a 100-square-mile
3-D seismic survey to locate additional structures that are expected to contain CO2.
During 2007, we drilled our first previously undrilled structure based on our 100-square-mile
seismic survey and re-entered a previously drilled well on another structure. The successful
testing of this undrilled structure and our successful re-entry and testing of this previously
drilled well, along with our development work at DRI Ice Field, increased our confidence that
significant volumes of additional CO2 can be developed in the Jackson Dome area beyond
our proved reserve base. We plan to continue our CO2 drilling activity in 2008 and
beyond, with additional development of DRI Ice Field to increase our deliverability of
CO2 and additional testing of undrilled structures to potentially increase our proved
reserves, as our CO2 deliverability and reserves requirements will continue to grow as
we expand our planned tertiary projects and acquire additional tertiary projects.
Man-made CO2 sources. We entered into two additional agreements and committed to
purchase (if the plants are built) 100% of the man-made (anthropogenic) CO2
production, from two proposed solid carbon gasification projects scheduled to be
completed in 2011 and 2012. These projects are in addition to our 2006 agreement for the Faustina
plant, proposed to be located near Donaldsonville, Louisiana, that will convert petroleum coke into
ammonia. As a by-product of the gasification of solid carbon, large quantities of CO2
are produced. Assuming these three projects are built, the total volume of CO2 expected
to be produced is estimated to be between 750 and 850 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. These agreements potentially allow us to add the equivalent volume of an additional
three to four Tcf of CO2 over the terms of our contracts. Construction of these plants
has not yet begun, so we are not certain whether these plants will be built, although it appears
likely that some gasification plants will be built in this area, if not these particular three. We
are in discussions with several other entities that are considering other types of solid carbon
gasification plants. These plants may convert petroleum coke, coal, biomass or combinations of all
three into a variety of products including ammonia, methanol, synthetic diesel fuel or for
electrical power generation. The cost
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Denbury Resources Inc.
of 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, and
we believe that there could potentially be a type of carbon credit in the United States that could
significantly lower our cost for this CO2. 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 Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson
Dome source field (see above). Construction of our Free State Pipeline was completed in 2006 and
it is currently transporting CO2 to our three existing Phase II tertiary fields in East
Mississippi (Eucutta, Soso and Martinville) and will also be used for our proposed projects at
Heidelberg, South Cypress Creek and other fields in Phase II. We continued our expansion of our
CO2 pipeline infrastructure with the completion of the first segment of our Delta
Pipeline between Jackson Dome and Tinsley Field in January 2008, and the reconditioning and
conversion of the natural gas pipeline we acquired from Southern Natural Gas Company in 2006 to
CO2 service which we will use to transport CO2 to our Phase IV fields,
Cranfield and Lake St. John Fields. Although neither of these pipeline projects were completed
during 2007, during January 2008 we placed the Delta Pipeline in service between Jackson Dome and
Tinsley Field and expect to make our first deliveries of CO2 to Cranfield during the
second quarter of 2008. During 2008, we plan to further extend our Delta Pipeline by building a 24
68-mile extension from Tinsley Field to Delhi Field with completion of this segment anticipated
around year-end 2008.
In late 2006, we purchased an option to acquire Hastings Field, a potential tertiary flood
located near Houston, Texas. We plan to build a 24 pipeline, named the Green Pipeline, to
transport CO2 to Hastings Field and our 2007 Southeast Texas acquisitions, Oyster Bayou,
Fig Ridge and Gillock Fields. The Green Pipeline will go from the southern end of our existing
NEJD CO2 pipeline that terminates near Donaldsonville, Louisiana, to Hastings Field,
near Houston, Texas, estimated to be between 300 and 320 miles. Based on our latest estimates,
this pipeline is expected to cost between $700 million and $750 million. Our efforts in 2007 were
focused on engineering design and right-of-way acquisitions. We acquired approximately 100-plus
miles of the necessary 300-plus miles of right-of-way in 2007 and completed a substantial portion
of our engineering design. In addition, we signed a letter of intent with a steel mill to
manufacture the 24 pipe and thereby locked-in the pipe purchase price. Although our definitive
schedules are still in flux, our goal is to begin construction of the Green Pipeline around
year-end 2008 and hope to have it completed around year-end 2009. Initially, we anticipate
transporting CO2 from our natural source at Jackson Dome on this line, but ultimately we
expect that it will be used to ship predominately man-made (anthropogenic) sources of
CO2.
Overall economics. Initially, our tertiary operations were generally 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, 2007, was approximately $9.75 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
$15.00 to $20.00 per BOE over the life of each field (at todays prices), again depending on the
field itself.
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 $90 million in 2008 in the Jackson Dome area with
the intent to add additional CO2 reserves and deliverability for future operations.
Approximately $27 million in capital
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Denbury Resources Inc.
expenditures is budgeted in 2008 for our Phase II properties (East Mississippi) and
approximately $27 million for Phase III properties (Tinsley), plus an additional $180 million for
properties in other phases, plus an additional $235 million for our Delta and Green CO2
Pipelines, making our combined CO2 related expenditures just over 72% of our $900
million 2008 capital budget.
Our Tertiary Oil Fields With Proved Tertiary Reserves
At December 31, 2007, we had total tertiary-related proved oil reserves of approximately 69.5
MMBbls, consisting of 2.7 MMBbls at Little Creek Field (and surrounding smaller fields), 11.5
MMBbls at Mallalieu Field, 15.3 MMBbls at McComb and Smithdale Fields, 18.7 MMBbls at Brookhaven
Field, 10.2 MMBbls at Eucutta Field, 9.8 MMBbls at Soso Field, and 1.3 MMBbls at Martinville Field.
Overall, our production from tertiary operations has 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 17,428 Bbls/d during the fourth quarter of 2007. We expect this production to continue to
increase for several years as we expand our tertiary operations to additional fields.
With regard to our proved tertiary reserves, we added 12.7 MMBbls of tertiary-related proved
oil reserves during the year, primarily oil reserves at Soso, Martinville and minor incremental
barrels at various fields in the Phase I area. Previously, we booked most proved 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 proved. 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 proved oil reserves, even though
we believe that these formations have a similar risk profile. We anticipate booking significant
amounts of proven tertiary oil reserves during 2008 with initial response expected at Tinsley and
Lockhart Crossing Fields and possibly at Cranfield Field.
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 6,304 Bbls/d
for the fourth quarter 2007. In contrast to many of our existing fields, Mallalieu Field was not
waterflooded prior to CO2 injection. Therefore, we believe that the tertiary recovery
of oil from 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 $16.6 million was invested in this field during 2007 to drill, re-enter or
recomplete wells in efforts to improve production.
From inception through December 31, 2007, we had net positive cash flow (revenue less
operating expenses and capital expenditures) from Mallalieu Field of $253.2 million, plus the
fields have a PV-10 Value of $719.8 million, using December 31, 2007, NYMEX pricing of $95.98 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
increased since that time, averaging 1,388 Bbls/d in the fourth quarter of 2007. During 2007, we
continued the expansion of our operations within McComb Field, expanding the production facilities,
and completing our installation of the facilities necessary to raise the injection pressure
throughout the field. Although we encountered injection issues, which initially limited our
CO2 injections at McComb, the increased injection pressure has resulted in significant
increases in CO2 injections at McComb Field. Since we increased the CO2
injections, we have seen increased amounts of water production which is generally the precursor for
increasing oil production. During 2007, nearby Smithdale Field saw significant production
increases. Oil production increased from less than 100 Bbls/d in 2006 to an average of 708
Bbls/d in the fourth quarter of 2007. Smithdale development was slower than expected due to a
larger percentage of re-entry failures than we have experienced in our other fields. The reservoir
at Smithdale is very channelized and thus the drilling of replacement wells for the re-entry
failures was postponed until we were able to complete our evaluation of a 2007 3-D seismic survey
covering McComb and Smithdale Fields. By utilizing the 3-D seismic data, our geoscientists are
able to locate wells in optimal positions within the channels at Smithdale to maximize the aerial
coverage and sweep of the CO2 project.
From inception through December 31, 2007, 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
8
Denbury Resources Inc.
these fields of $113.3 million, although the fields have a PV-10 Value of $713.1 million, using
December 31, 2007, 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 and 2007 as
additional patterns have been developed. Brookhaven Field has three discrete reservoirs that are
being simultaneously CO2 flooded. Significant incremental work on CO2
injection wells is required to improve injection rates and to ensure the CO2 is entering
the proper intervals. Injection of CO2 in certain wells has been less than originally
anticipated and thus additional injection pumps were installed on certain wells to increase
injection rates. Our oil production here during the fourth quarter of 2007 averaged 2,507 Bbls/d.
From inception through December 31, 2007, 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 $44.8 million, although the field has a PV-10 Value of
$793.8 million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX
pricing.
Little Creek Area. During the fourth quarter of 2007, production averaged 1,957 Bbls/d from
the Little Creek area, which includes 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, 2007, 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 $153.9 million, plus the fields have a PV-10 Value of $132.3 million, using
December 31, 2007, NYMEX pricing.
Eucutta Field. The oil response we have experienced in Eucutta has confirmed the results of
the pilot project that was performed in the early 1980s. 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 2008 include the development of the
remaining patterns and expansion of our CO2 facilities. At December 31, 2007, we had
10.2 MMBbls of proved reserves in the Eucutta Field attributable to the CO2 flood with a
corresponding PV-10 Value of $456.0 million using year-end prices. The proved reserve estimate is based on
a 13% recovery factor, which is lower than was achieved in the pilot program in the 1980s, and
therefore we expect upward reserve revisions here in the future. Eucutta is analogous to Heidelberg
Field in that the majority of its historical production was produced from the Eutaw formation.
From inception through December 31, 2007, 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 Eucutta of $40.3 million, although the field has a PV-10 Value of $456.0
million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX pricing.
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. As expected, we saw our first
tertiary production in Soso Field during early 2007 from the Bailey.
9
Denbury Resources Inc.
In 2007 we continued the development of additional patterns in both the Rodessa and Bailey
intervals, and by the fourth quarter of 2007 response in the Bailey continued to increase, and
initial response from the Rodessa was also achieved. During the fourth quarter of 2007, production
at Soso had increased to 1,109 Bbls/d. From inception through December 31, 2007, 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 Soso of $93.2 million, although the
field has a PV-10 Value of $363.5 million attributed to the tertiary recovery reserves, using
December 31, 2007, NYMEX pricing.
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 Mooringsport well
responded, although the average rate for the quarter was only 24 Bbls/d. The tertiary oil rate has
increased to approximately 883 Bbls/d during the fourth quarter of 2007 including initial response
in the Rodessa. Although we booked minimal proved reserves in 2006 from the one responding well in
the Mooringsport, we booked additional reserves, approximately 1.5 MMBbls at December 31, 2007, in
the Mooringsport and the Rodessa IX reservoir. There are several additional Rodessa reservoirs
that will be developed following completion of the CO2 flood in the Rodessa IX.
From inception through December 31, 2007, 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 Martinville of $10.8 million, although the field has a PV-10 Value of
$65.8 million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX pricing.
The Wash Fred 8500 reservoir in the Martinville Field contains a low oil gravity (thick oil),
15o 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, and fluid handling and processing of
the CO2 and this heavy crude have continued to hamper the development of this flood.
Although we have seen indications of CO2 response, the ability to produce and process
this heavy crude with the associated CO2 production is proving very difficult. We are
evaluating various ideas and scenarios to address the processing issues we are experiencing. If we
can resolve these issues, this field could 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 Proved Tertiary Reserves
During 2007, we commenced tertiary operations at a small field, Lockhart Crossing (Phase I),
our first Louisiana flood, reconditioned the pipeline necessary to transport CO2 to
Cranfield Field in West Mississippi (Phase IV), and initiated CO2 injections at Tinsley
Field (Phase III).
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. Although injections were limited throughout 2007, we
completed unitization of the entire field, constructed a substantial portion of our CO2
recycling facilities, and expanded the CO2 flood throughout the west fault block of the
field. Construction of the first segment of our larger Delta Pipeline was completed in January
2008 with a resultant increase in injection rates thereafter. Although we only had limited
injections during 2007, we did observe increasing reservoir pressures, and we plan to continue that
re-pressuring process during 2008 with the higher
10
Denbury Resources Inc.
injection rates. Once the reservoir pressure increases to our target amount, we expect to see our
initial tertiary oil production, most likely in the third or fourth quarter of 2008. If the
production response is significant and occurs before year-end, we anticipate booking a portion of
the forecasted proved reserves at Tinsley in 2008.
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 planned future CO2
tertiary oil flood that will require construction of a CO2 pipeline before flooding can
commence, an extension of the larger, Delta Pipeline constructed from Jackson Dome to Tinsley
Field. Our goal is to have this segment of the Delta Pipeline installed by around year-end 2008,
with initial oil production from tertiary operations currently anticipated during 2009. As of
December 31, 2007, there was no significant oil production nor 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 on September 1, 2008, or September 1, 2009, with an effective
date of January 1 of the following year, 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 upon execution of the agreement and made an
additional $7.5 million payment in 2007, and are required to make an additional payment of $5
million by November 2008. 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 2,800
Bbls/d gross, 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 the Green Pipeline to transport CO2 to this field (see CO2 pipelines
above). Based on our latest 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 Green Pipeline.
Oyster Bayou, Fig Ridge and Gillock Fields. During 2007, we acquired an interest in three
additional fields in Southeast Texas with significant tertiary potential. The Oyster Bayou and Fig
Ridge Fields are located in close proximity to each other and are located very close to the planned
route of the Green Pipeline. We acquired the majority interest in Oyster Bayou Field and a
significant interest in Fig Ridge Field. We plan to start the unitization hearings required at
Oyster Bayou Field during 2008. Because of current lack of majority interest at Fig Ridge Field,
we will need the cooperation of other operators and lease owners to form the necessary unit, and we
have initiated those discussions. Our acquisitions in Gillock Field include an acquisition of 99+%
(subject to a 20% preferential right election) of the South Gillock Unit, 99+% of the Southeast
Gillock unit and the acquisition of a key lease in the Gillock Field. The Gillock acquisitions are
located near the proposed Green Pipeline and Hastings Field. Denbury continues to evaluate other
potential acquisition candidates in Southeast Texas and in Louisiana in proximity to our proposed
Green Pipeline.
Overall Tertiary Economics to Date. Through December 31, 2007, we have invested a total of
$1.0 billion on tertiary oil fields (including the allocated acquisition costs), and received
$758.9 million in net operating income (revenue less operating expenses), or net unrecovered cash
flow of $250.8 million, the deficit primarily due to the significant funds expended on acquisitions
during 2006. Of our total spending, approximately $351.3 million was spent to date on fields that
had little or no proved reserves at December 31, 2007 (i.e., significant incremental proved
reserves are anticipated during 2008 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 $371.0 million as of December 31, 2007, including
$180.3 million associated with CO2 pipelines. At year-end 2007, the proved oil reserves
in our tertiary recovery oil fields had a PV-10 Value of $3.2 billion, using December 31, 2007,
NYMEX pricing of $95.98 per barrel. In addition, there are significant probable and potential
reserves at several other fields for which tertiary operations are under way or planned.
11
Denbury Resources Inc.
Texas Barnett Shale
We currently own approximately 55,649 gross acres and 40,240 net acres of leases in the
Barnett Shale area in North Central Texas, of which approximately 19,984 gross acres and 19,398 net
acres are in the more tested northern areas of Parker and Wise counties, with the remainder in
Erath County 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, 2007, we have
invested a total of $423.9 million on the Barnett Shale area (including acquisition costs) and have
received $204.8 million in net operating income (revenue less operating expenses), or net negative
cash flow of $219.1 million. At December 31, 2007, we had approximately 368.5 Bcfe of proved
reserves in the Barnett Shale area with a PV-10 Value of approximately $717.2 million, using
December 31, 2007, Henry Hub indicative cash pricing of $6.80 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. During 2007, we drilled and completed
45 horizontal wells, increasing our net Barnett Shale production from approximately 35.4 MMcfe/d in
the fourth quarter of 2006 to approximately 76.4 MMcfe/d during the fourth quarter of 2007.
Horizontal wells in the Barnett Shale were initially drilled by spacing horizontal wells
approximately 1,500 apart and drilling 3,000 to 4,500 laterals. As our development progressed we
began testing wells at various spacings of 750 and subsequently 500 along with other operators in
the Barnett. Initial production rates and early production data indicated that we are not
efficiently draining the reservoir on the larger initial well spacing, and thus we began developing
our acreage position on 500 well spacing which significantly increased the number of future well
locations that we can drill. Our year-end reserves included 85 proved undeveloped locations and an
additional 88 probable undeveloped locations based on 500 well spacing. We have recently begun
testing well spacings less than 500 but the results of this additional downspacing is inconclusive
at this time. If our testing of the Barnett Shale on tighter well spacing is successful, it would
significantly increase our number of future locations. We expect production in this area to grow
modestly during 2008 as we plan to drill approximately 45 to 50 horizontal wells, all of which are
scheduled for Parker and Wise Counties. Including seismic costs and pipeline infrastructure costs,
our planned 2008 capital expenditures in the Barnett Shale area are estimated to make up $157
million of our current $900 million capital budget for 2008.
We have completed a review of our 2006 drilling and completion work in our southern acreage,
primarily Erath County. As a result of this review, we have determined to no longer pursue the
development of this southern acreage position and will seek to divest these assets.
East Mississippi Fields Without Proved 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. Historically, this was our area with the highest production and
most proved reserves, and while still significant, it is no longer our largest. Production during
the fourth quarter of 2007 averaged approximately 12,530 BOE/d from this area (25% of our Company
total), and we had proved reserves of 50.6 MMBOE as of December 31, 2007 (26% 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 12,072 BOE/d in 2005, 12,743 BOE/d in 2006 and 12,479 BOE/d
during 2007. For 2008, we expect our budget in this region for conventional operations to be
around $60 million, about the same as in 2007, representing approximately 7% of our current 2008
exploration and development budget of $900 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 2007 produced an average of 7,770 BOE/d, 4% more
than the 2006 fourth quarter average of 7,444 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, and most of the past and current production comes from the
Eutaw, Selma Chalk and Christmas sands at depths of 3,500 to 5,000.
The majority of the oil production at Heidelberg is from six waterflood units that produce
from the Eutaw formation (at approximately 4,400). Most of our recent development at Heidelberg
has been in the Selma Chalk, a natural gas reservoir at around 3,700, 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
12
Denbury Resources Inc.
Heidelberg to a peak quarterly average of 17.3 MMcf/d in the fourth quarter of 2007, averaging
16.3 MMcf/d during 2007. During late 2006 and early 2007, we drilled our first horizontal wells in
West Heidelberg Field where vertical wells were generally uneconomic. The horizontal wells have
performed very well and thus we expect to be able to expand our Selma Chalk development throughout
West Heidelberg Field. During 2007, we drilled 13 horizontal Selma Chalk wells, two of which were
located in West Heidelberg, and we plan to drill 12 horizontal wells during 2008.
Our capital program for 2008 includes $39 million for construction of the pipeline necessary
to transport CO2 from the Free State Pipeline to Heidelberg Field, construction of the
initial phase of the CO2 recycle facilities and initial development of a CO2
flood in West Heidelberg Field. The initial phase of our CO2 project in Heidelberg will
be conducted in the WHEOUP Unit in West Heidelberg. The reservoir associated with the WHEOUP unit
is the Eutaw formation, the same formation we are CO2 flooding at Eucutta Field. Thus
we expect the results at Heidelberg to be very similar to the results at Eucutta Field. Although
similar in many respects, the Eutaw reservoir at Heidelberg contains two to three times the
potential oil reserves as the Eutaw at Eucutta. Our forecasts do not include any production
response from the CO2 project at Heidelberg in 2008, but we do expect to see a
production response in 2009.
Sale of Louisiana Natural Gas Assets
In October 2007 we entered into an agreement to sell our Louisiana natural gas assets to a
privately held company for approximately $180 million (before closing adjustments) plus any amounts
received in the future from a net profits interest. In late December 2007, we closed on
approximately 70% of that sale with net proceeds of approximately $108.6 million (including
estimated final purchase price adjustments), and closed on the remaining 30% on February 20, 2008,
with net proceeds at the second closing of approximately $48.9 million. The operating net revenue,
net of capital expenditures, between the August 1, 2007, effective date and the respective closing
dates were adjustments to the purchase price, along with other minor closing adjustments. The
potential net profits interest relates to a well in the South Chauvin Field and is only earned if
operating income from that well exceeds certain levels, which we believe could potentially increase
the ultimate sales price by up to 10%.
Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82%
natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth
quarter production and approximately 4% of our total proved reserve quantities as of December 31,
2006.
13
Denbury Resources Inc.
Field Summaries
Denbury operates in five primary areas: Eastern Mississippi, Western Mississippi, Texas,
Alabama and Louisiana. Our 14 largest fields (listed below) constitute approximately 94% of our
total proved reserves on a BOE basis and on a PV-10 Value basis. Within these 14 fields, we own a
weighted average 95% 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 four primary field offices located in Laurel, Mississippi; McComb, Mississippi;
Brandon, Mississippi; and Cleburne, Texas.
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves as of December 31, 2007 (1) |
2007 Avg. Daily Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
Average Net |
|
|
Oil |
|
Natural Gas |
|
|
|
|
|
BOE |
PV-10 Value(2) |
Oil |
|
Gas |
|
Revenue |
|
|
(MBbls) |
|
(MMcf) |
|
MBOEs |
|
% of total |
|
(000s) |
|
(Bbls/d) |
|
(Mcf/d) |
|
Interest |
|
Mississippi
CO2 Floods |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
18,700 |
|
|
|
|
|
|
|
18,700 |
|
|
|
9.6 |
% |
|
$ |
793,813 |
|
|
|
2,048 |
|
|
|
|
|
|
|
81.2 |
% |
McComb Area |
|
|
15,275 |
|
|
|
|
|
|
|
15,275 |
|
|
|
7.9 |
% |
|
|
713,080 |
|
|
|
1,912 |
|
|
|
|
|
|
|
78.8 |
% |
Mallalieu Area |
|
|
11,547 |
|
|
|
|
|
|
|
11,547 |
|
|
|
5.9 |
% |
|
|
719,778 |
|
|
|
5,852 |
|
|
|
|
|
|
|
76.7 |
% |
Eucutta |
|
|
10,172 |
|
|
|
|
|
|
|
10,172 |
|
|
|
5.2 |
% |
|
|
456,003 |
|
|
|
1,646 |
|
|
|
|
|
|
|
83.5 |
% |
Soso |
|
|
9,798 |
|
|
|
|
|
|
|
9,798 |
|
|
|
5.0 |
% |
|
|
363,542 |
|
|
|
586 |
|
|
|
|
|
|
|
77.2 |
% |
Little Creek Area |
|
|
2,749 |
|
|
|
|
|
|
|
2,749 |
|
|
|
1.4 |
% |
|
|
132,311 |
|
|
|
2,014 |
|
|
|
|
|
|
|
83.2 |
% |
Martinville |
|
|
1,282 |
|
|
|
|
|
|
|
1,282 |
|
|
|
0.7 |
% |
|
|
65,827 |
|
|
|
709 |
|
|
|
|
|
|
|
78.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Mississippi CO2 Floods |
|
|
69,523 |
|
|
|
|
|
|
|
69,523 |
|
|
|
35.7 |
% |
|
|
3,244,354 |
|
|
|
14,767 |
|
|
|
|
|
|
|
79.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Mississippi |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heidelberg (East & West) |
|
|
24,666 |
|
|
|
59,087 |
|
|
|
34,514 |
|
|
|
17.7 |
% |
|
|
728,126 |
|
|
|
4,942 |
|
|
|
16,286 |
|
|
|
80.6 |
% |
Tinsley |
|
|
2,632 |
|
|
|
|
|
|
|
2,632 |
|
|
|
1.4 |
% |
|
|
81,029 |
|
|
|
1,042 |
|
|
|
15 |
|
|
|
67.6 |
% |
Sharon |
|
|
|
|
|
|
11,842 |
|
|
|
1,974 |
|
|
|
1.0 |
% |
|
|
32,057 |
|
|
|
4 |
|
|
|
4,491 |
|
|
|
94.3 |
% |
S. Cypress Creek |
|
|
1,850 |
|
|
|
654 |
|
|
|
1,959 |
|
|
|
1.0 |
% |
|
|
45,050 |
|
|
|
247 |
|
|
|
39 |
|
|
|
86.6 |
% |
Eucutta |
|
|
1,854 |
|
|
|
|
|
|
|
1,854 |
|
|
|
1.0 |
% |
|
|
47,367 |
|
|
|
444 |
|
|
|
22 |
|
|
|
64.4 |
% |
Other Mississippi |
|
|
7,047 |
|
|
|
3,641 |
|
|
|
7,654 |
|
|
|
3.9 |
% |
|
|
199,488 |
|
|
|
2,117 |
|
|
|
1,246 |
|
|
|
37.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Mississippi |
|
|
38,049 |
|
|
|
75,224 |
|
|
|
50,587 |
|
|
|
26.0 |
% |
|
|
1,133,117 |
|
|
|
8,796 |
|
|
|
22,099 |
|
|
|
63.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Newark (Barnett Shale) |
|
|
17,160 |
|
|
|
265,575 |
|
|
|
61,423 |
|
|
|
31.5 |
% |
|
|
717,213 |
|
|
|
1,758 |
|
|
|
46,751 |
|
|
|
80.5 |
% |
Other Texas |
|
|
340 |
|
|
|
1,407 |
|
|
|
574 |
|
|
|
0.3 |
% |
|
|
23,943 |
|
|
|
270 |
|
|
|
1,527 |
|
|
|
72.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Texas |
|
|
17,500 |
|
|
|
266,982 |
|
|
|
61,997 |
|
|
|
31.8 |
% |
|
|
741,156 |
|
|
|
2,028 |
|
|
|
48,278 |
|
|
|
80.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana |
|
|
634 |
|
|
|
2,238 |
|
|
|
1,007 |
|
|
|
0.5 |
% |
|
|
42,378 |
|
|
|
380 |
|
|
|
1,303 |
|
|
|
70.8 |
% |
Louisiana sold (3) |
|
|
422 |
|
|
|
12,434 |
|
|
|
2,494 |
|
|
|
1.3 |
% |
|
|
59,556 |
|
|
|
801 |
|
|
|
24,861 |
|
|
|
45.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Louisiana |
|
|
1,056 |
|
|
|
14,672 |
|
|
|
3,501 |
|
|
|
1.8 |
% |
|
|
101,934 |
|
|
|
1,181 |
|
|
|
26,164 |
|
|
|
48.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama & Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Citronelle |
|
|
8,784 |
|
|
|
|
|
|
|
8,784 |
|
|
|
4.5 |
% |
|
|
159,796 |
|
|
|
1,150 |
|
|
|
|
|
|
|
62.7 |
% |
Other Alabama |
|
|
66 |
|
|
|
1,730 |
|
|
|
354 |
|
|
|
0.2 |
% |
|
|
4,766 |
|
|
|
3 |
|
|
|
600 |
|
|
|
2.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Alabama and other |
|
|
8,850 |
|
|
|
1,730 |
|
|
|
9,138 |
|
|
|
4.7 |
% |
|
|
164,562 |
|
|
|
1,153 |
|
|
|
600 |
|
|
|
11.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company Total |
|
|
134,978 |
|
|
|
358,608 |
|
|
|
194,746 |
|
|
|
100.0 |
% |
|
$ |
5,385,123 |
|
|
|
27,925 |
|
|
|
97,141 |
|
|
|
67.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The reserves were prepared using constant prices and costs in accordance with the
guidelines of SFAS No. 69 based on the prices received on a field-by-field basis as of
December 31, 2007. The prices at that date were a NYMEX oil price of $95.98 per Bbl adjusted to
prices received by field and a Henry Hub natural gas average price of $6.80 per MMBtu
also adjusted to prices received by field. |
|
(2) |
|
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure of
Discounted Future Net Cash Flows (Standardized Measure) in that PV-10 Value is a pre-tax
number and the Standardized Measure is an after-tax number. The information used to calculate
PV-10 Value is derived directly from data determined in accordance with SFAS No. 69. The
Standardized Measure was $3,539,617 at December 31, 2007. A comparison of PV-10 to the
Standardized Measure is included in the table on page 20 as well as further information
regarding our use of this non-GAAP measure. |
|
(3) |
|
Reserves in the Louisiana sold category are associated with the portion of the Louisiana
divestiture that closed in February 2008. |
14
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 or natural 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, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
Undeveloped |
|
Total |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Mississippi |
|
|
109,630 |
|
|
|
88,911 |
|
|
|
266,204 |
|
|
|
46,046 |
|
|
|
375,834 |
|
|
|
134,957 |
|
Louisiana |
|
|
36,805 |
|
|
|
35,212 |
|
|
|
4,560 |
|
|
|
3,881 |
|
|
|
41,365 |
|
|
|
39,093 |
|
Texas |
|
|
39,190 |
|
|
|
34,186 |
|
|
|
41,200 |
|
|
|
24,790 |
|
|
|
80,390 |
|
|
|
58,976 |
|
Alabama |
|
|
35,209 |
|
|
|
21,860 |
|
|
|
72,113 |
|
|
|
14,638 |
|
|
|
107,322 |
|
|
|
36,498 |
|
Other |
|
|
2,680 |
|
|
|
816 |
|
|
|
38,710 |
|
|
|
9,687 |
|
|
|
41,390 |
|
|
|
10,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
223,514 |
|
|
|
180,985 |
|
|
|
422,787 |
|
|
|
99,042 |
|
|
|
646,301 |
|
|
|
280,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denburys net undeveloped acreage that is subject to expiration over the next three years, if
not renewed, is approximately 22% in 2008, 26% in 2009 and 14% in 2010.
Productive Wells
The following table sets forth our gross and net productive oil and natural gas wells at
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Natural |
|
|
|
|
Producing Oil Wells |
|
Gas Wells |
|
Total |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
553 |
|
|
|
530.6 |
|
|
|
187 |
|
|
|
171.0 |
|
|
|
740 |
|
|
|
701.6 |
|
Louisiana |
|
|
19 |
|
|
|
15.1 |
|
|
|
7 |
|
|
|
6.0 |
|
|
|
26 |
|
|
|
21.1 |
|
Texas |
|
|
14 |
|
|
|
12.3 |
|
|
|
159 |
|
|
|
152.1 |
|
|
|
173 |
|
|
|
164.4 |
|
Alabama |
|
|
155 |
|
|
|
122.0 |
|
|
|
32 |
|
|
|
19.2 |
|
|
|
187 |
|
|
|
141.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
741 |
|
|
|
680.0 |
|
|
|
385 |
|
|
|
348.3 |
|
|
|
1,126 |
|
|
|
1,028.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
37 |
|
|
|
3.4 |
|
|
|
18 |
|
|
|
4.2 |
|
|
|
55 |
|
|
|
7.6 |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
0.3 |
|
|
|
4 |
|
|
|
0.3 |
|
Alabama |
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
1.7 |
|
|
|
11 |
|
|
|
1.7 |
|
Other |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
40 |
|
|
|
3.4 |
|
|
|
33 |
|
|
|
6.2 |
|
|
|
73 |
|
|
|
9.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
590 |
|
|
|
534.0 |
|
|
|
205 |
|
|
|
175.2 |
|
|
|
795 |
|
|
|
709.2 |
|
Louisiana |
|
|
19 |
|
|
|
15.1 |
|
|
|
7 |
|
|
|
6.0 |
|
|
|
26 |
|
|
|
21.1 |
|
Texas |
|
|
14 |
|
|
|
12.3 |
|
|
|
163 |
|
|
|
152.4 |
|
|
|
177 |
|
|
|
164.7 |
|
Alabama |
|
|
155 |
|
|
|
122.0 |
|
|
|
43 |
|
|
|
20.9 |
|
|
|
198 |
|
|
|
142.9 |
|
Other |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
781 |
|
|
|
683.4 |
|
|
|
418 |
|
|
|
354.5 |
|
|
|
1,199 |
|
|
|
1,037.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
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, |
|
|
2007 |
|
2006 |
|
2005 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Exploratory Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
9 |
|
|
|
6.2 |
|
|
|
10 |
|
|
|
8.5 |
|
|
|
12 |
|
|
|
7.1 |
|
Non-productive(3) |
|
|
4 |
|
|
|
3.4 |
|
|
|
8 |
|
|
|
6.8 |
|
|
|
1 |
|
|
|
0.6 |
|
Development Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
101 |
|
|
|
96.8 |
|
|
|
90 |
|
|
|
82.7 |
|
|
|
81 |
|
|
|
74.3 |
|
Non-productive(3)(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
114 |
|
|
|
106.4 |
|
|
|
108 |
|
|
|
98.0 |
|
|
|
94 |
|
|
|
82.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
development 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 2007, 2006 and 2005, an additional 23, 14, and 5 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, 2007, we had three purchasers that
each accounted for 10% or more of our oil and natural gas revenues: Marathon Ashland Petroleum LLC
(43%), Hunt Crude Oil Supply Co. (19%) and Crosstex Energy Field Services Inc. (16%). For the
16
Denbury Resources Inc.
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%).
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, thereby impacting 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 Phase I 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, 2007, the discount for our oil
production from Heidelberg Field averaged $11.10 per Bbl and for our Eastern Mississippi properties
as a whole the discount averaged $9.46 per Bbl relative to NYMEX oil prices. For our Phase I
fields in Southwest Mississippi, we averaged a premium of $4.36 per Bbl over NYMEX oil prices
during 2007. Our Texas Barnett Shale properties averaged $20.79 per Bbl below NYMEX prices during
2007, 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, 2007, we averaged $0.36 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 $0.78 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
17
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 regulation of the size of drilling, spacing 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 which 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.
Federal Energy Legislation
The Energy Independence and Security Act of 2007 (Public Law No. 110-140) became law on
December 19, 2007. Among other provisions, the Act supports research and development in
alternative and renewable fuels sources, energy storage for transportation and electric power, and
carbon capture and sequestration. The Act does not repeal certain tax incentives for expenditures
by companies engaged in the exploration and production of oil, gas and other
18
Denbury Resources Inc.
minerals, nor does it impose new excise taxes specifically on certain companies engaged in the
exploration and production of oil, gas and other minerals, both of which had been proposed in
earlier versions of the legislation. As a result of this new legislation, in 2008 Congress may
decide to revisit legislation to repeal existing incentives or impose new taxes on the exploration
and production of oil, gas and other minerals, and/or create new incentives for alternative energy
sources. Congress may also consider legislation to reduce emissions of carbon dioxide or other
gases. If enacted, such legislation could reduce the demand for and uses of oil, gas and other
minerals and/or increase the costs incurred by the Company in its exploration and production
activities.
Natural Gas Gathering Regulations
State regulation of natural gas gathering facilities generally include various safety,
environmental and, in some circumstances, nondiscriminatory-take requirements. Although such
regulation has not generally been affirmatively applied by state agencies, natural gas gathering
may receive greater regulatory scrutiny in the future.
Federal, State or Indian Leases
Our operations on federal, state or Indian oil and gas leases are subject to numerous
restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to
certain on-site security regulations and other permits and authorizations issued by the Bureau of
Land Management, Minerals Management Service (MMS) and other agencies.
Environmental Regulations
Public interest in the protection of the environment has increased dramatically in recent
years. Our oil and natural gas production and saltwater disposal operations, and our processing,
handling and disposal of hazardous materials such as hydrocarbons and naturally occurring
radioactive materials are subject to stringent regulation. We could incur significant costs,
including cleanup costs resulting from a release of hazardous material, third-party claims for
property damage and personal injuries, fines and sanctions, as a result of any violations or
liabilities under environmental or other laws. Changes in or more stringent enforcement of
environmental laws could also result in additional operating costs and capital expenditures.
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, 2007, 2006 and 2005.
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
19
Denbury Resources Inc.
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. During 2007, we provided oil and gas reserve estimates for
2006 to the United States Energy Information Agency. The information provided was substantially
the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2006.
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 and our
Heidelberg waterfloods in East Mississippi account for approximately 78% of our proved undeveloped
oil reserves. We consider these reserves to be lower risk than other proved undeveloped reserves
that require drilling at locations offsetting existing production because all of these proved
undeveloped reserves are associated with secondary recovery or tertiary recovery operations in
fields and reservoirs that historically produced substantial volumes of oil under primary
production. The main reason these reserves are classified as undeveloped is because they require
significant additional capital associated with drilling/re-entering wells or additional facilities
in order to produce the reserves and/or are waiting for a production response to the water or
CO2 injections. Our proved undeveloped natural gas reserves associated with our Selma
Chalk play at Heidelberg and the Barnett Shale play account for approximately 97% of our proved
undeveloped natural gas reserves. Our current plans for 2008 include drilling 55 to 65 new wells
in these two primary natural gas plays.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2007 |
|
2006 |
|
2005 |
ESTIMATED PROVED RESERVES: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
134,978 |
|
|
|
126,185 |
|
|
|
106,173 |
|
Natural gas (MMcf) |
|
|
358,608 |
|
|
|
288,826 |
|
|
|
278,367 |
|
Oil equivalent (MBOE) |
|
|
194,746 |
|
|
|
174,322 |
|
|
|
152,568 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PERCENTAGE OF TOTAL MBOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved producing |
|
|
56 |
% |
|
|
48 |
% |
|
|
40 |
% |
Proved non-producing |
|
|
13 |
% |
|
|
17 |
% |
|
|
16 |
% |
Proved undeveloped |
|
|
31 |
% |
|
|
35 |
% |
|
|
44 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
REPRESENTATIVE OIL AND GAS PRICES:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil NYMEX |
|
$ |
95.98 |
|
|
$ |
61.05 |
|
|
$ |
61.04 |
|
Natural gas Henry Hub |
|
|
6.80 |
|
|
|
5.63 |
|
|
|
10.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PRESENT VALUES: (thousands)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Discounted estimated future net cash flow before
income taxes
(PV-10 Value)(3) |
|
$ |
5,385,123 |
|
|
$ |
2,695,199 |
|
|
$ |
3,215,478 |
|
Standardized measure of discounted estimated future net
cash flow after income taxes |
|
|
3,539,617 |
|
|
|
1,837,341 |
|
|
|
2,084,449 |
|
|
|
|
(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
SFAS No. 69, discounted at 10% per annum. |
|
(3) |
|
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that
PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. The
information used to calculate PV-10 Value is derived directly from data determined in
accordance with SFAS No. 69. The difference between these two amounts, the discounted estimated
future income tax, was $1,845,506 at December 31, 2007, $857,858 at December 31, 2006, and
$1,131,029 at December 31, 2005. We believe that PV-10 Value is a useful supplemental
disclosure to the Standardized Measure because the Standardized Measure can be impacted by a
companys unique tax situation, and it is not practical to calculate the Standardized Measure
on a property by property basis. Because of this, PV-10 Value is a widely used measure within
the industry and is commonly used by securities analysts, banks and credit rating agencies to
evaluate the estimated future net cash flows from proved reserves on a comparative basis
across companies or specific properties. PV-10 Value is commonly used by us and others in our
industry to evaluate properties that are bought and sold and to assess the potential return on
investment in our oil and gas properties. PV-10 Value is not a measure of financial or
operating performance under GAAP, nor should it be considered in isolation or as a substitute
for the Standardized Measure. Our PV-10 Value and the Standardized Measure do not purport to
represent the fair value of our oil and natural gas reserves. See Note 15 to our Consolidated
Financial Statements for additional disclosures about the Standardized Measure. |
20
Denbury Resources Inc.
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 15, Supplemental Oil and Natural Gas Disclosures, to the Consolidated
Financial Statements.
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 72% of our 2008 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, 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 69% of our December 31,
2007 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:
|
|
|
the level of consumer demand for oil and natural gas; |
|
|
|
|
the domestic and foreign supply of oil and natural gas; |
|
|
|
|
the ability of the members of the Organization of Petroleum Exporting Countries
(OPEC) to agree to and maintain oil price and production controls; |
|
|
|
|
the price of foreign oil and natural gas; |
|
|
|
|
domestic governmental regulations and taxes; |
|
|
|
|
the price and availability of alternative fuel sources; |
|
|
|
|
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
21
Denbury Resources Inc.
financial condition, results of
operations, oil and natural gas reserves and the carrying values of our oil and natural gas
properties. If the oil and natural gas industry experiences significant price declines, we may,
among other things, be unable to meet our financial obligations or make planned expenditures.
Since the end of 1998, oil prices have gone from near historic low prices to historic highs.
At the end of 1998, NYMEX oil prices were at historic lows of approximately $12.00 per Bbl, but
have generally increased since that time, albeit with fluctuations. For 2007, NYMEX oil prices
were high throughout the year, averaging approximately $72.45 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 had 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 and 2006, averaging $6.33 per Bbl and $6.41 per Bbl, respectively. In 2007, our differential
improved to $2.65 per Bbl, as a large portion of our oil production was sold at markets that were
priced favorably to the West Texas Intermediate NYMEX price, due to lack of available storage
capacity in the mid-continent area, an oversupply of crude from Canada, capacity/transportation
issues moving the crude out of the Cushing, Oklahoma area and unanticipated refinery outages. This
positive trend in 2007 began to reverse in the fourth quarter of 2007, when our NYMEX differential
averaged $7.27 per Bbl due to the significant increase in liquids extracted from our Barnett Shale
production, which is recorded as oil production but is sold at a significant discount to the NYMEX
oil price. 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. NYMEX natural gas
prices averaged $8.97 per MMBtu during 2005, $6.97 per MMBtu during
2006, and $7.09 per MMBtu
during 2007.
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 |
|
|
|
|
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 equipment used in our tertiary facilities, drilling rigs and other equipment, as
demand for rigs and equipment has increased along with higher commodity prices. 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.
22
Denbury Resources Inc.
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 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 2,392 BOE/d net to the acquired interests
during the fourth quarter of 2007, and have proved reserves of approximately 13.4 MMBOEs. 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:
|
|
|
unexpected drilling conditions; |
|
|
|
|
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;
|
23
Denbury Resources Inc.
|
|
|
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.
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, 2007, three purchasers each accounted for more than 10% of our
oil and natural gas revenues and in the aggregate, for 78% 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
effect 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.
24
Denbury Resources Inc.
As of December 31, 2007, approximately 31% 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.
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, 2008, we had outstanding $525 million (principal amount) of 7.5%
subordinated notes and $111 million of bank debt. Our bank credit line has approximately $379
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, 2008. 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; |
|
|
|
|
our business may not generate sufficient cash flow from operations to enable us to
continue to meet our obligations under our indebtedness; |
|
|
|
|
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; |
|
|
|
|
our interest expense may increase in the event of increases in interest rates,
because certain of our borrowings are at variable rates of interest; |
|
|
|
|
our vulnerability to general adverse economic and industry conditions may increase,
potentially restricting us from making acquisitions, introducing new technologies or
exploiting business opportunities; |
25
Denbury Resources Inc.
|
|
|
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 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
A special meeting of the stockholders was held on November 19, 2007, for the purposes of:
(i) approving an amendment to our Restated Certificate of Incorporation to increase the number
of shares of our authorized common stock from 250,000,000 shares to 600,000,000 shares; (ii)
approving an amendment to our Restated Certificate of Incorporation to split our common shares
2-for-1; and (iii) granting authority to the Company to extend the solicitation period in the
event that the special meeting is postponed or adjourned for any reason. At the record date,
October 8, 2007, 122,094,117 shares of common stock were outstanding and entitled to one vote
per share upon all matters submitted at the meeting. Holders of 111,215,370 shares of common
stock, representing approximately 91% of the total issued and outstanding shares of common
stock, were present in person or by proxy at the meeting to cast their vote. All matters were
approved as listed below.
With respect to the amendment to our Restated Certificate of Incorporation to increase the
number of shares of our authorized common stock from 250,000,000 shares to 600,000,000 shares, the
votes were cast as follows:
|
|
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
81,736,700
|
|
|
29,443,451 |
|
|
|
35,219 |
|
26
Denbury Resources Inc.
With respect to approving an amendment to our Restated Certificate of Incorporation to split
our common shares 2-for-1, the votes were cast as follows:
|
|
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
111,049,257 |
|
|
138,146 |
|
|
|
27,967 |
|
With respect to approving an amendment to grant authority to extend the solicitation
period in the event that the special meeting is postponed or adjourned for any reason, the
votes were cast as follows:
|
|
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
61,637,858 |
|
|
48,565,777 |
|
|
|
1,011,735 |
|
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 sale prices are adjusted to reflect the 2-for-1 stock
split on December 5, 2007. On April 25, 2006, we closed the $125 million sale (net to Denbury) of
6,985,190 shares (3,492,595 pre-split basis) of common stock in a public offering. As of January
31, 2008, the number of record holders of Denburys common stock
was 943. Management believes,
after inquiry, that the number of beneficial owners of Denburys common stock is in excess of
10,500. On January 31, 2008, the last reported sale price of Denburys common stock, as reported
on the NYSE, was $25.30 per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
|
High |
|
Low |
|
High |
|
Low |
First Quarter |
|
$ |
15.310 |
|
|
$ |
12.980 |
|
|
$ |
16.325 |
|
|
$ |
11.785 |
|
Second Quarter |
|
|
19.380 |
|
|
|
14.835 |
|
|
|
18.300 |
|
|
|
12.955 |
|
Third Quarter |
|
|
23.380 |
|
|
|
18.275 |
|
|
|
17.900 |
|
|
|
13.265 |
|
Fourth Quarter |
|
|
30.560 |
|
|
|
22.405 |
|
|
|
15.465 |
|
|
|
12.975 |
|
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 2007.
27
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, 2007, 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, 2002, and that dividends were reinvested.
Cumulative Total Return on $100 Investment
(December 31, 2002 December 31, 2007)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
2002 |
|
|
2003 |
|
|
2004 |
|
|
2005 |
|
|
2006 |
|
|
2007 |
|
|
Denbury |
|
|
$ |
100.00 |
|
|
|
$ |
123.10 |
|
|
|
$ |
242.92 |
|
|
|
$ |
403.19 |
|
|
|
$ |
491.86 |
|
|
|
$ |
1,053.10 |
|
|
|
S&P 500 |
|
|
|
100.00 |
|
|
|
|
128.68 |
|
|
|
|
142.69 |
|
|
|
|
149.70 |
|
|
|
|
173.34 |
|
|
|
|
182.87 |
|
|
|
Dow Jones
Exploration and
Production |
|
|
|
100.00 |
|
|
|
|
131.06 |
|
|
|
|
185.94 |
|
|
|
|
307.40 |
|
|
|
|
323.91 |
|
|
|
|
465.35 |
|
|
|
28
Denbury Resources Inc.
Item 6. Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
(In thousands, unless otherwise noted) |
|
2007 |
|
2006 |
|
2005 |
|
2004(1) |
|
2003 |
Consolidated Statements of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
971,950 |
|
|
$ |
732,312 |
|
|
$ |
560,706 |
|
|
$ |
382,836 |
|
|
$ |
333,270 |
|
Net income |
|
|
253,147 |
|
|
|
202,457 |
(2) |
|
|
166,471 |
|
|
|
82,448 |
|
|
|
56,553 |
(3) |
Net income per common share (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
1.05 |
|
|
|
0.87 |
(2) |
|
|
0.74 |
|
|
|
0.38 |
|
|
|
0.26 |
(3) |
Diluted |
|
|
1.00 |
|
|
|
0.82 |
(2) |
|
|
0.70 |
|
|
|
0.36 |
|
|
|
0.25 |
(3) |
Weighted average number of common
shares outstanding (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
240,065 |
|
|
|
233,101 |
|
|
|
223,485 |
|
|
|
219,482 |
|
|
|
215,525 |
|
Diluted |
|
|
252,101 |
|
|
|
247,547 |
|
|
|
239,267 |
|
|
|
229,206 |
|
|
|
221,856 |
|
Consolidated Statements of Cash
Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used by): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
570,214 |
|
|
$ |
461,810 |
|
|
$ |
360,960 |
|
|
$ |
168,652 |
|
|
$ |
197,615 |
|
Investing activities |
|
|
(762,513 |
) |
|
|
(856,627 |
) |
|
|
(383,687 |
) |
|
|
(93,550 |
) |
|
|
(135,878 |
) |
Financing activities |
|
|
198,533 |
|
|
|
283,601 |
|
|
|
154,777 |
|
|
|
(66,251 |
) |
|
|
(61,489 |
) |
Production (Daily): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
27,925 |
|
|
|
22,936 |
|
|
|
20,013 |
|
|
|
19,247 |
|
|
|
18,894 |
|
Natural gas (Mcf) |
|
|
97,141 |
|
|
|
83,075 |
|
|
|
58,696 |
|
|
|
82,224 |
|
|
|
94,858 |
|
BOE (6:1) |
|
|
44,115 |
|
|
|
36,782 |
|
|
|
29,795 |
|
|
|
32,951 |
|
|
|
34,704 |
|
Unit Sales Price
(excluding impact of derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
69.80 |
|
|
$ |
59.87 |
|
|
$ |
50.30 |
|
|
$ |
36.46 |
|
|
$ |
27.47 |
|
Natural gas (per Mcf) |
|
|
6.81 |
|
|
|
7.10 |
|
|
|
8.48 |
|
|
|
6.24 |
|
|
|
5.66 |
|
Unit Sales Price
(including impact of derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
68.84 |
|
|
$ |
59.23 |
|
|
$ |
50.30 |
|
|
$ |
27.36 |
|
|
$ |
24.52 |
|
Natural gas (per Mcf) |
|
|
7.66 |
|
|
|
7.10 |
|
|
|
7.70 |
|
|
|
5.57 |
|
|
|
4.45 |
|
Costs per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
14.34 |
|
|
$ |
12.46 |
|
|
$ |
9.98 |
|
|
$ |
7.22 |
|
|
$ |
7.06 |
|
Production taxes and marketing expenses |
|
|
3.05 |
|
|
|
2.71 |
|
|
|
2.54 |
|
|
|
1.55 |
|
|
|
1.17 |
|
General and administrative |
|
|
3.04 |
|
|
|
3.20 |
|
|
|
2.62 |
|
|
|
1.78 |
|
|
|
1.20 |
|
Depletion, depreciation and amortization |
|
|
12.17 |
|
|
|
11.11 |
|
|
|
9.09 |
|
|
|
8.09 |
|
|
|
7.48 |
|
Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
134,978 |
|
|
|
126,185 |
|
|
|
106,173 |
|
|
|
101,287 |
|
|
|
91,266 |
|
Natural gas (MMcf) |
|
|
358,608 |
|
|
|
288,826 |
|
|
|
278,367 |
|
|
|
168,484 |
|
|
|
221,887 |
|
MBOE (6:1) |
|
|
194,746 |
|
|
|
174,322 |
|
|
|
152,568 |
|
|
|
129,369 |
|
|
|
128,247 |
|
Carbon dioxide (MMcf) (5) |
|
|
5,641,054 |
|
|
|
5,525,948 |
|
|
|
4,645,702 |
|
|
|
2,664,633 |
|
|
|
1,613,840 |
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,771,077 |
|
|
$ |
2,139,837 |
|
|
$ |
1,505,069 |
|
|
$ |
992,706 |
|
|
$ |
982,621 |
|
Total long-term liabilities |
|
|
1,102,066 |
|
|
|
833,380 |
|
|
|
617,343 |
|
|
|
368,128 |
|
|
|
434,845 |
|
Stockholders equity (6) |
|
|
1,404,378 |
|
|
|
1,106,059 |
|
|
|
733,662 |
|
|
|
541,672 |
|
|
|
421,202 |
|
|
|
|
(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 $0.01. In April 2003, we
recorded a pre-tax charge of $17.6 million associated with an early debt retirement. |
|
(4) |
|
On December 5, 2007, and 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 splits. |
|
(5) |
|
Based on a gross working interests basis and includes reserves dedicated to volumetric
production payments of 182.3 Bcf at December 31, 2007, 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 15 to the Consolidated Financial Statements). |
|
(6) |
|
We have never paid any dividends on our common stock. |
29
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 in the
Barnett Shale play near Fort Worth, Texas, onshore Louisiana and Alabama, and properties in
Southeast 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 four primary field offices located in Laurel, Mississippi; McComb, Mississippi;
Brandon, Mississippi; and Cleburne, Texas.
2007 Overview
Operating Results. During 2007, we set a corporate record for annual cash flow from
operations of $570.2 million, a 23% increase over the $461.8 million of cash flow from operations
generated during 2006. Our 2007 net income of $253.1 million was 25% higher than our $202.5
million of net income during 2006, even after including a $64.2 million decrease in pre-tax income
between the respective periods from non-cash fair value adjustments associated with our commodity
derivative contracts. Record high production levels, higher oil prices, and $25.8 million of
incremental net cash receipts on our derivative contracts contributed to the positive results,
partially offset by higher overall expenses, lower natural gas prices, and the effect of the $64.2
million differential in non-cash fair value adjustments associated with our commodity derivative
contracts (see Results of Operations Oil and Natural Gas Revenues).
Our fourth quarter 2007 average production rate of 50,371 BOE/d and our 2007 average
production of 44,115 BOE/d were Company quarterly and annual production records, with significant
increases in our tertiary oil and Barnett Shale production, partially offset by production declines
in our Louisiana onshore properties. Higher oil prices further improved 2007 results, as our
average realized per BOE commodity price was 11% higher than during 2006, resulting in 13% higher
revenues in 2007, together with 20% higher revenues due to higher production levels.
Excluding any impact of our commodity derivative income and expense items, our aggregate
expenses increased 33% during 2007 as compared to expenses during 2006 due to (i) higher overall
industry costs, (ii) a higher percentage of operations related
to tertiary operations, which generally have higher operating costs per BOE (see Results of
Operations CO2 Operations for
a more thorough discussion), (iii) higher average debt
levels to finance our $42 million acquisition on March 31, 2007 (see 2007 Acquisitions below) and
continued spending in excess of cash flow from operations (see Capital Resources and Liquidity),
and (iv) higher compensation expense resulting from additional employees and increased salaries
which we consider necessary in order to remain competitive in the industry, partially offset by
approximately $6.0 million of non-recurring charges to earnings in 2006 related to the departure
and retirement of two vice presidents.
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 2007, our
proved reserves increased from 174.3 MMBOE as of December 31, 2006, to 194.7 MMBOE as of December
31, 2007, replacing approximately 250% of our 2007 production, almost entirely from organic growth.
The most significant reserve additions during 2007 were in the Barnett Shale (22.8 MMBOE) and in
our tertiary operations (12.7 MMBOE). While we booked more proved tertiary reserves in 2007 than
in 2006 (6.0 MMBOE), these reserve quantity additions were less than we expect to recognize during
the next few years, presuming we have a production response from the tertiary floods we started in
2007 and expect to start in 2008 and 2009 (see Results of Operations Depletion, Depreciation and
Amortization for a review of our reserve changes during 2007 and a discussion of our proved
tertiary reserves).
While overall costs were higher in the 2007 periods than in the comparable 2006 periods,
during 2007 the rate of inflation in our industry appears to have moderated, and in some cases, we
are beginning to see modest cost reductions. Likewise, although oilfield goods and services are
still in tight supply, there have been signs of improvement in overall availability; but some
supply issues persist, including long lead times for certain goods and services, such as
compressors used in our tertiary recycling facilities and construction services for pipelines. It
is difficult to forecast price trends and supply and service availability, which if adverse, can
significantly impact both operating costs and capital expenditures, as well as cause delays in
achieving our anticipated production targets.
30
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Tertiary 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
2007, we replaced 164% of our CO2 production, increasing our proved CO2
reserves slightly, from approximately 5.5 Tcf as of December 31, 2006 to approximately 5.6 Tcf as
of December 31, 2007 (quantities are on a 100% working interest basis see CO2
Operations CO2 Resources for further information).
Oil production from our tertiary operations increased to an average of 14,767 BOE/d in 2007, a
47% increase over 2006 tertiary production level of 10,070 BOE/d, with fourth quarter 2007 tertiary
production averaging 17,428 BOE/d. Production from our Phase II operations in Eastern Mississippi
(Soso, Eucutta and Martinville Fields) contributed 2,888 BOE/d (approximately 61%) to the increase
over the prior years tertiary production level, with the balance of the increase coming from our
Phase I fields, except for Little Creek Field which is on a gradual decline. In addition to
further development of oil fields we already own and which are slated for tertiary flooding, we are
continuing to buy additional oil fields that are candidates for future tertiary flood activity (see
2007 Acquisitions below).
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.
Sale of Louisiana Natural Gas Assets. In October 2007, we entered into an agreement to sell
our Louisiana natural gas assets to a privately held company for approximately $180 million (before
closing adjustments) plus any amounts received in the future from a net profits interest in a well.
In late December 2007, we closed on approximately 70% of that sale with net proceeds of
approximately $108.6 million (including estimated final purchase price adjustments), and closed on
the remaining 30% on February 20, 2008, with net proceeds at the second closing of approximately
$48.9 million. The operating net revenue, net of capital expenditures, between the August 1, 2007,
effective date and the respective closing dates was an adjustment to the purchase price, along with
other minor closing adjustments. The potential net profits interest relates to a well in the South
Chauvin Field and is only earned if operating income from that well exceeds certain levels, which
we believe could potentially increase the ultimate sales price by up to 10%.
Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82%
natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth
quarter production and approximately 4% of our total proved reserve quantities as of December 31,
2006.
Genesis Transactions. On July 25, 2007, Genesis Energy, L.P. (Genesis), a master limited
partnership of which Denbury is the general partner, closed on a previously announced acquisition
in which they acquired several energy related businesses from the Davison family of Ruston,
Louisiana, for total consideration of approximately $623 million (net of cash acquired at closing
and subject to final purchase price adjustments). The acquisition agreement provided that Genesis
deliver $560 million of consideration, half in common units at an agreed value of $20.8036 per unit
(as compared to a value of $24.52 per unit for accounting purposes) and half in cash, subject to
specified purchase price adjustments. In conjunction with that acquisition, we exercised our right
to maintain our pro rata (7.4%) ownership of common units, acquiring 1,074,882 additional common
units for approximately $22.4 million, in addition to our capital contribution of an additional
$6.2 million as general partner to maintain our 2% general partners interest.
In order to maintain our pro rata (7.4%) common unit ownership interest in Genesis, we
acquired an additional 734,732 common units in a December 2007 Genesis public offering at $21.29
per unit, the public offering price of $22.00 per unit, less the underwriting discount. Our total
cost for the units, including the 2% general partner portion of the offering, was $20.0 million.
The Company has reached substantial agreement and is in the process of finalizing the business
issues with Genesis and its lenders as to the terms of the transactions with Genesis involving the
Companys NEJD and Free State CO2 Pipelines, including a long-term transportation
service arrangement for the Free State line and a 20-year financing lease for the NEJD system. In
these transactions, Denbury expects to receive from Genesis $225 million in cash and $25 million of
Genesis common limited partnership units at the average closing price of the units on the thirty
days prior to closing. The Company anticipates capitalizing these transactions for accounting
purposes and currently projects that it will initially pay Genesis approximately $30 million per
annum under the financing lease and transportation services agreement (and a lesser pro-rated amount for
2008), with future payments for the NEJD pipeline payments fixed at $20.7 million per year during
the term of the financing lease, and the payments relating to
31
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
the Free State Pipeline dependant on the volumes of CO2 transported therein.
While the business terms of the transactions have been substantially completed, closing remains
subject to finalization of legal issues and completion and delivery of closing documentation.
Currently, we will also consider similar transactions with Genesis for the new CO2
pipeline we have constructed from Jackson Dome to Tinsley Field and are constructing from Tinsley
Field to Delhi Field (the Delta Pipeline), once that pipeline is completed, forecasted at this
time to be completed in late 2008 or early 2009, or potentially we could divide that pipeline into
two segments and two separate transactions. If in future periods Genesis is able to complete
additional acquisitions of non-Denbury related assets of sufficient size and with acceptable
returns, we would consider additional dropdowns with Genesis of certain of our existing or planned
assets provided that such transactions can generate qualified income for a master limited
partnership, which may depend in part on the degree to which we ship man-made CO2 on
such lines and the status of man-made CO2 as qualified income.
2007 Acquisitions. On March 30, 2007, we completed an acquisition of six producing oil and
natural gas fields, two of which are future potential CO2 tertiary oil flood candidates,
collectively called the Seabreeze Complex, located near Houston, Texas, at a cost of approximately
$39.4 million. Tertiary operations are not expected to commence at these fields until 2010 or
2011, following anticipated completion of the 300 mile CO2 pipeline from Louisiana to
Hastings Field (also near Houston). The acquisition was funded with bank financing under our
existing credit facility. At the time of acquisition, these fields had estimated proved
conventional reserves of approximately 525 MBOE and produced an average of 759 BOE/d during the
fourth quarter of 2007. We operate all of these fields and own the majority of the working
interests.
We also purchased East and South Gillock Fields in 2007, small future CO2 tertiary
oil flood candidates, also located near Houston, Texas, at a cost of approximately $3.5 million.
The conventional reserves and production associated with these fields was negligible at the time of
the acquisition.
April 2007 Debt Issuance. On April 3, 2007, we issued $150 million of 7.5% Senior
Subordinated Notes due 2015 as an additional issuance under our existing indenture governing our
December 2005 sale of $150 million of 7.5% Senior Subordinated Notes due 2015. The notes were
issued at 100.5% of par, which equates to an effective yield to maturity of 7.4%. The net proceeds
from the issuance were approximately $149.2 million, which we used to repay a portion of the
outstanding borrowings under our bank credit facility.
Capital Resources and Liquidity
Our current 2008 capital exploration and development budget is approximately $900 million,
excluding any potential acquisitions. The current 2008 program includes an estimated $245 million
to acquire pipe and right-of-ways for our proposed CO2 pipeline from Louisiana to Texas
(the Green Pipeline) and another $80 million for the segment of the Delta CO2 Pipeline
from Tinsley to Delhi Fields. We expect to spend an additional $450 million constructing the Green
Pipeline during 2009, making our current anticipated total cost for that line approximately $700
million. Currently, over 50% of the remaining portion of our 2008 budget is expected to be spent
on other tertiary related operations, over 25% in the Barnett Shale area, and the balance in other
areas. Based on oil and natural gas commodity futures prices as of late February 2008 and our
current 2008 production forecasts, our 2008 capital budget is forecasted to be $125 million to $175
million greater than our anticipated cash flow from operations. We plan to fund most of this
deficit with cash generated by the anticipated drop-down transaction with Genesis (see 2007
Overview Genesis Transactions) and our recently completed sale of Louisiana natural gas assets
(see 2007 Overview Sale of Louisiana Natural Gas Assets). We could potentially also generate
additional funds of up to $150 million through transactions with Genesis whereby we could
drop-down our Delta CO2 Pipeline, or portions thereof, to Genesis (see 2007 Overview
Genesis Transactions).
If the Delta Pipeline drop-down to Genesis is not consummated, or if there is still a
shortfall in excess of the cash generated by our recently completed Louisiana property sale and
proposed drop-down of pipelines to Genesis described above, we would likely fund the deficit with
bank debt. In addition, if commodity prices were to significantly decrease from current levels, we
could also reduce our capital spending during 2008 commensurately, in addition to using bank debt
to fund the deficit.
As of February 28, 2008, we had $111 million of bank debt outstanding on a $500 million
borrowing base, leaving us significant incremental borrowing capacity, more than we currently plan
or desire to use. Further, we believe that we could significantly increase our bank borrowing base
if desired, and anticipate increasing it at our April 1, 2008 redetermination.
32
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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
cost inflation in our industry in recent years, many of our recent year budget increases have
related to escalating costs rather than additional projects. Even though there are signs that the
rate of this inflationary trend is subsiding, if costs do rise or we spend more than our estimated
amounts, we will either have to increase our capital budget or consider deferring a portion of our
planned projects.
We 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 of existing production,
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.
Amendment to our bank credit facility. On March 31, 2007, we amended our Sixth Amended and
Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative
agent. The amendment (i) increased the commitment amount that the banks are committed to fund from
$250 million to $350 million, (ii) reconfirmed the borrowing base of $500 million, (iii) authorized
last springs $150 million subordinated debt offering (see 2007 Overview April 2007 Debt
Issuance), and (iv) authorized us to enter into a sale-leaseback type transaction for our
CO2 pipelines, not to exceed $300 million, with Genesis, in the type of transaction
contemplated and discussed above (see 2007 Overview Genesis Transactions). With regard to our
bank credit facility, 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 by us in excess of the commitment amount
($350 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 February 28, 2008, we had outstanding
$525 million (principal amount) of 7.5% subordinated notes and $111 million of bank debt.
Sources and Uses of Capital Resources
Capital Expenditure Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands |
|
2007 |
|
|
2006 |
|
|
2005 |
|
Oil and gas exploration and development |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
$ |
313,258 |
|
|
$ |
245,350 |
|
|
$ |
147,773 |
|
Geological, geophysical and acreage |
|
|
22,829 |
|
|
|
31,590 |
|
|
|
25,519 |
|
Facilities |
|
|
118,003 |
|
|
|
98,890 |
|
|
|
65,018 |
|
Recompletions |
|
|
141,264 |
|
|
|
120,438 |
|
|
|
70,056 |
|
Capitalized interest |
|
|
18,305 |
|
|
|
11,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas exploration and development expenditures |
|
|
613,659 |
|
|
|
507,327 |
|
|
|
308,366 |
|
Oil and gas property acquisitions |
|
|
49,077 |
|
|
|
319,000 |
|
|
|
70,870 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
662,736 |
|
|
|
826,327 |
|
|
|
379,236 |
|
CO2 source field capital expenditures, including capitalized interest |
|
|
171,182 |
|
|
|
63,586 |
|
|
|
78,726 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
833,918 |
|
|
$ |
889,913 |
|
|
$ |
457,962 |
|
|
|
|
|
|
|
|
|
|
|
Our 2007 capital expenditures have been funded with $570.2 million of cash flow from
operations, $150.0 million from our issuance of subordinated debt in April, $135.8 million from
sales proceeds, and $16.0 million of net bank borrowings, with the excess proceeds used for other
purposes, including the $48.5 million incremental investment in Genesis.
Our 2006 expenditures were funded with $461.8 million of cash flow from operations, $139.8
million of equity issued and $134.0 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.
33
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Off-Balance Sheet Arrangements
Commitments and Obligations
At December 31, 2007, 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 2007
totaled $143.8 million (including $98.5 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, 2007, 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 $80.0
million in debt and $5.3 million in letters of credit at December 31, 2007. 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, 2007. We do not have any material transactions with related parties other
than sales of production, transportation arrangements, 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. The anticipated conveyance of
our CO2 pipelines to Genesis would require payments over a minimum of 20 years and is
not included in the commitment table below (see 2007 Overview Genesis Transactions). If
consummated, we anticipate capitalizing these transactions for accounting purposes, and currently
project that we will initially pay Genesis approximately
$30 million per annum under the lease financing and
transportation agreement (and a lesser pro-rated amount for 2008), with future payments for the
NEJD Pipeline fixed at $20.7 million per year during the 20-year
service term of the financing lease, and
the payments relating to the Free State Pipeline dependant on the volumes of CO2
transported thereon, with a minimum annual payment for the Free State Pipeline of $1.2 million.
We currently have long-term commitments to purchase manufactured CO2 from three
proposed gasification plants, if these plants are built, two proposed by the developers of Faustina
Hydrogen Products LLC and another by Rentech Inc. If all three plants are built, these synthetic
sources are currently anticipated to provide us with an aggregate of 750 MMcf/d to 850 MMcf/d of
CO2 by 2013. The base price of CO2 per Mcf from these synthetic sources is
currently expected to be 1.5 to 2.0 times higher than our most recent all-in cost of CO2
from our natural sources (Jackson Dome) using current oil prices and assuming comparable
compression levels. These predicted synthetic CO2 prices are expected to be competitive
with the cost of our natural CO2 after adjusting for our share of potential carbon
emissions credits using estimated current prices of CO2 carbon credit futures. If all
three plants are built, the aggregate purchase obligation for this CO2 would be around
$190 million per year, assuming a $90 per barrel oil price and comparable compression levels,
before any potential savings from our share of carbon emissions credits. All of the contracts have
price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on
any of these plants, and their construction is contingent on the satisfactory resolution of various
issues, including financing; although based on their public representations, the initial Faustina
plant is currently scheduled to begin construction during 2008, with completion scheduled in late
2010 or 2011. These amounts are not included in the table below as these payments are contingent
on the plants being built.
34
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
A summary of our obligations at December 31, 2007, is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
Amounts in Thousands |
|
Total |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
Thereafter |
|
Contractual Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated debt (a) |
|
$ |
525,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
525,000 |
|
Senior Bank Loan (a) |
|
|
150,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150,000 |
|
|
|
|
|
|
|
|
|
Estimated interest payments on
subordinated debt and Senior Bank Loan (a) |
|
|
301,705 |
|
|
|
48,613 |
|
|
|
48,612 |
|
|
|
48,613 |
|
|
|
45,879 |
|
|
|
39,375 |
|
|
|
70,613 |
|
Operating lease obligations |
|
|
143,768 |
|
|
|
17,580 |
|
|
|
17,128 |
|
|
|
16,745 |
|
|
|
16,185 |
|
|
|
14,957 |
|
|
|
61,173 |
|
Capital lease obligations (b) |
|
|
8,738 |
|
|
|
1,291 |
|
|
|
1,529 |
|
|
|
1,291 |
|
|
|
1,291 |
|
|
|
1,242 |
|
|
|
2,094 |
|
Capital expenditure obligations (c) |
|
|
166,041 |
|
|
|
113,628 |
|
|
|
50,658 |
|
|
|
1,755 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts payment (d) |
|
|
23,914 |
|
|
|
23,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hastings Field purchase option |
|
|
5,000 |
|
|
|
5,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Cash Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future development costs on proved oil and gas
reserves, net of capital obligations (e) |
|
|
530,778 |
|
|
|
179,033 |
|
|
|
143,053 |
|
|
|
103,168 |
|
|
|
41,940 |
|
|
|
21,250 |
|
|
|
42,334 |
|
Future development cost on proved CO2
reserves, net of capital obligations (f) |
|
|
133,894 |
|
|
|
46,794 |
|
|
|
11,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76,100 |
|
Asset retirement obligations (g) |
|
|
100,530 |
|
|
|
2,685 |
|
|
|
2,251 |
|
|
|
3,762 |
|
|
|
1,285 |
|
|
|
747 |
|
|
|
89,800 |
|
|
Total |
|
$ |
2,089,368 |
|
|
$ |
438,538 |
|
|
$ |
274,231 |
|
|
$ |
175,334 |
|
|
$ |
256,580 |
|
|
$ |
77,571 |
|
|
$ |
867,114 |
|
|
|
|
|
(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 $7.0 million to Genesis under capital leases in
place at December 31, 2007, primarily for transportation of crude oil and CO2, $1.5
million for our office in Laurel, Mississippi, and auto leases for $0.2 million.
Approximately $2.3 million of these payments represents interest. |
|
(c) |
|
Represents future minimum cash commitments under contracts in place as of December 31, 2007,
primarily for pipe, drilling rig services and well related costs. As is common in our
industry, we commit to make certain expenditures on a regular basis as part of our ongoing
development and exploration program. These commitments generally relate to projects that
occur during the subsequent several months and are usually part of our normal operating
expenses or part of our capital budget, which for 2008 is currently set at $900 million. In
certain cases we have the ability to terminate contracts for equipment in which case we would
only be liable for the cost incurred by the vendor up to that point; however, as we currently
do not anticipate cancelling those contracts these amounts include our estimated payments
under those contracts. We also 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, 2007. 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, 2007, was a $23.3 million net liability. 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, 2007 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 the table above. |
|
(f) |
|
Represents projected capital costs as scheduled in our December 31, 2007 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 $41.3 million, as determined under SFAS No.
143, and is further discussed in Note 4 to the Consolidated Financial Statements. |
During November 2006 we entered into an agreement that gives us an option on September 1,
2008, and September 1, 2009, to be effective on the following January 1st, to purchase
an 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
35
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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, to date we have paid $45 million under this option and have
a remaining payment due in November 2008 of $5.0 million. 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 totaling 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. The above table does not include the commitments related to Hastings Field if the
purchase option is exercised by us, as the obligation is at our option. The above table does
include the remaining $5.0 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 562 Bcf of
CO2 to these customers over the next 20 years; however, since the group as a whole has
historically taken less CO2 than the maximum allowed in their contracts, based on the
current level of deliveries, we project that our commitment would likely be reduced to
approximately 268 Bcf. The maximum volume required in any given year is approximately 142 MMcf/d,
although based on our current level of deliveries this would likely be reduced to approximately 72
MMcf/d. Given the size of our proven CO2 reserves at December 31, 2007 (approximately
5.6 Tcf before deducting approximately 182.3 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. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999,
our interest in tertiary operations has increased to the point that approximately 72% of our
current 2008 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
CO2 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 NEJD
CO2 Pipeline that we acquired in 2001. The most significant fields in this area are
Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which began with the early 2006
completion of the Free State CO2 Pipeline to East Mississippi, includes Eucutta, Soso,
Martinville and Heidelberg Fields. Tinsley Field located northwest of Jackson, Mississippi,
acquired in January 2006, is our Phase III and is serviced by that portion of the Delta
CO2 Pipeline completed in January 2008. 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.
Flooding in Phase V will begin in 2009 upon completion of the Delta CO2 Pipeline from
Tinsley to Delhi. Citronelle Field in Southwest Alabama, another field acquired in 2006, is our
Phase VI which will require an extension to the Free State CO2 Pipeline, the timing of
which is uncertain at this time. Our last two currently existing phases will require completion of
our proposed Green Pipeline, a 300-mile CO2 pipeline which will run from Southern
Louisiana to near Houston, Texas, and is scheduled for completion in late 2009 or 2010. Hastings
Field, a field on which we acquired a purchase option in late 2006 (see Commitments and
Contingencies), is our Phase VII, and the Seabreeze Complex, acquired in 2007, will be our Phase
VIII (see 2007 Overview 2007 Acquisitions).
CO2 Resources. Since we acquired the CO2 source field located near
Jackson, Mississippi, in 2001, we have continued to develop the field and have increased the proven
CO2 reserves from approximately 800 Bcf at the time
36
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
of the acquisition to approximately
5.6 Tcf as of December 31, 2007. During 2007, our proven CO2 reserves increased
approximately 5%, or 295 Bcf (excluding 2007 production). The estimate of 5.6 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 and 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 for Denburys tertiary recovery
programs, Genesis, 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 2.4 Tcf of CO2 to develop and produce the proved tertiary recovery
reserves we have recorded at December 31, 2007, in Phases I and II.
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 February 20, 2008, we estimate
that we are capable of producing approximately 700 MMcf/d of CO2, over six 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 five more wells planned for 2008, in order to
further increase our production capacity and potentially increase our proven CO2
reserves. Our drilling activity at Jackson Dome will continue beyond 2008 as our current forecasts
for the existing eight phases suggest that we will need approximately 1.4 Bcf/d of CO2
production by 2012.
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 2005, 2006 and 2007 was approximately 242
million, 342 million and 493 million cubic feet per day, respectively, of which approximately 73%
in 2005, 75% in 2006 and 81% in 2007 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 $0.21 per Mcf in operating expenses to produce our CO2
during 2007, more than our 2006 average of $0.19 per Mcf and our 2005 average of $0.16 per
Mcf, with the higher costs each year primarily due to higher oil costs, which impacts the amount we
pay royalty owners for the CO2, and higher operating costs. Our estimated total cost
per thousand cubic feet of CO2 during 2007 was approximately $0.29, after inclusion of
depreciation and amortization expense related to the CO2 production, as compared to
approximately $0.28 during 2006 and $0.25 during 2005.
Man-Made CO2 Sources. In addition to our natural source of CO2, we are
in discussions with the owners of several possible gasification plants which, if built, will
convert coal or petroleum coke into various other fuels, with CO2 being a significant
by-product of the process. We expect these plants to provide us with significant additional
sources of CO2 in the future which would enable us to further expand our tertiary
operations, although the earliest source of this manufactured CO2 is not expected to be
available to us until late 2010 or 2011. We have entered into long-term commitments to purchase
manufactured CO2 from three proposed plants (see Commitments and Obligations), which,
if all three plants are built, are currently anticipated to provide us with an aggregate of 750
MMcf/d to 850 MMcf/d of CO2 by 2013. While we are uncertain as to whether these three
specific plants will be built, we anticipate that some gasification plants will be built within the
next several years. If correct in our assumptions, we believe that we are a likely purchaser of
CO2 produced from such plants built in our area of operations because of the scale of
our tertiary operations, the CO2 pipeline infrastructure that we are continuing to
develop, and the large natural source of CO2 (Jackson Dome), which can act as a swing
CO2 producer if needed.
Overview of Tertiary Economics. When we began our tertiary operations several years ago, they
were generally economic at oil prices below $20 per Bbl, although the economics 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, 2007, are approximately $9.75 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 $15.00 to $20.00 per BOE over the life of each field (at todays prices), again
depending on the field itself.
37
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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
our financial results and certain operating statistics.
First, there is a significant delay between the initial capital expenditures on these fields
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). Further, we may spend significant amounts of
capital before we can recognize any proven reserves from fields we flood (see Analysis of
CO2 Tertiary Recovery Operating Activities below). Even after a field has proven
reserves, there will usually be significant amounts of additional capital required to fully develop
the field.
Second, 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. 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 because of
little or minimal related oil production at that time. Commencing in 2008, we plan to capitalize
the cost of
CO2
and related operating costs until production commences, which may
slightly
reduce our cost per BOE (see Note 1 to the Consolidated Financial Statements,
Significant Accounting Policies Tertiary Injection Costs). 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 and Analysis of
CO2 Tertiary Recovery Operating Activities below).
Analysis of CO2 Tertiary Recovery Operating Activities. We currently have tertiary
operations ongoing at almost all Phase I fields, and Soso, Martinville and Eucutta Fields in Phase
II, and we are currently injecting CO2 at Tinsley Field in Phase III. We project that
our oil production from our CO2 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, 2007, we had approximately 69.5 MMBbls of proven oil reserves related to tertiary
operations (48.3 MMBbls 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 added 12.7 MMBbls of tertiary-related proved oil reserves during 2007, primarily initial
proven tertiary oil reserves at Soso and Martinville Fields (Phase II). Prior to 2006, we booked
most of our 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. The
magnitude of proven reserves that we can book in any given year will depend on our progress with
new floods and the timing of the production response.
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 14,767 Bbls/d during 2007.
Tertiary oil production represented approximately 53% of our total corporate oil production during
2007 and approximately 33% 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. While we may have
temporary fluctuation in oil production related to tertiary operations, this does not indicate any
issue with the proved
38
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
and potential oil reserves recoverable with CO2, because the historical correlation
between oil production and CO2 injections remains high. A detailed discussion of each of
our tertiary oil fields and the development of each is included on
pages 8 10 under Our
Tertiary Oil Fields With Proved Tertiary Reserves. Following is a chart with our tertiary oil
production by field for 2005 and 2006, and by quarter for 2007. In 2007, we saw continued improved
response from our newer Phase II floods at Martinville, Eucutta and Soso Fields, most of which were
initiated during 2006. In addition, we continue to see improved response at most of our other
floods in Phase I, except for Little Creek Field, which is a mature flood and is expected to
continue to gradually decline over the next several years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
|
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Year Ended December 31, |
Tertiary Oil Field |
|
2007 |
|
2007 |
|
2007 |
|
2007 |
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
1,422 |
|
|
|
1,794 |
|
|
|
2,452 |
|
|
|
2,507 |
|
|
|
|
2,048 |
|
|
|
833 |
|
|
|
31 |
|
Little Creek area |
|
|
2,117 |
|
|
|
1,974 |
|
|
|
2,011 |
|
|
|
1,957 |
|
|
|
|
2,014 |
|
|
|
2,739 |
|
|
|
3,529 |
|
Mallalieu area |
|
|
5,470 |
|
|
|
5,802 |
|
|
|
5,823 |
|
|
|
6,304 |
|
|
|
|
5,852 |
|
|
|
5,210 |
|
|
|
4,739 |
|
McComb area |
|
|
1,811 |
|
|
|
1,884 |
|
|
|
1,853 |
|
|
|
2,096 |
|
|
|
|
1,912 |
|
|
|
1,235 |
|
|
|
916 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
320 |
|
|
|
521 |
|
|
|
1,101 |
|
|
|
883 |
|
|
|
|
709 |
|
|
|
6 |
|
|
|
|
|
Eucutta |
|
|
614 |
|
|
|
1,338 |
|
|
|
2,035 |
|
|
|
2,572 |
|
|
|
|
1,646 |
|
|
|
47 |
|
|
|
|
|
Soso |
|
|
25 |
|
|
|
370 |
|
|
|
826 |
|
|
|
1,109 |
|
|
|
|
586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
11,779 |
|
|
|
13,683 |
|
|
|
16,101 |
|
|
|
17,428 |
|
|
|
|
14,767 |
|
|
|
10,070 |
|
|
|
9,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 five years we have leased certain equipment
that qualifies for operating lease treatment representing an underlying aggregate cost of
approximately $98.5 million as of December 31, 2007. These leases have been an attractive method
of financing due to their low imputed interest rates, which are fixed for seven to ten years.
Also, the cost to produce our CO2 has gradually increased (see CO2
Resources above), all of which resulted in an increase in our tertiary operating cost per
BOE from $12.00 per BOE during 2005, to $17.69 per BOE in 2006, to
$19.77 per BOE in 2007. The absolute
amount of operating expenses related to tertiary operations increased from $40.4 million during
2005, to $65.0 million during 2006, to $106.5 million during 2007.
Through December 31, 2007, we have invested a total of $1.0 billion on fields currently being
flooded (including allocated acquisition costs) and have $250.8 million in unrecovered net cash
flow (revenue less operating expenses and capital expenditures). Of this total, approximately
$351.3 million (35%) was spent on fields which had little or no proved reserves at December 31,
2007 (i.e., fields for which significant incremental proved reserves are anticipated during 2008
and beyond). The proved oil reserves in our CO2 fields have a PV-10 Value of $3.2
billion, using December 31, 2007, constant NYMEX pricing of $95.98 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, 2007, we had a balance of approximately $371.0 million of unrecovered
net cash flows for our CO2 producing properties and CO2 pipelines.
CO2 Source-Related Capital Budget for 2008. Tentatively, we plan to spend
approximately $90 million in 2008 in the Jackson Dome area with the intent to add additional
CO2 reserves and deliverability for future operations. Approximately $235 million in
capital expenditures is budgeted in 2008 at the oil field level in Phases I through V, plus an
additional $325 million for our Delta and Green CO2 Pipelines, making our combined
CO2 related expenditures just over 72% of our $900 million 2008 capital budget.
Operating Results
Net income and cash flow from operations have increased each year during the last three years.
Production increased 23% between 2005 and 2006, and 20% between 2006 and 2007, which, coupled with
higher prices, resulted in record annual net income and cash flow.
39
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands, Except Per Share Amounts |
|
2007 |
|
2006 |
|
2005 |
|
Net income |
|
$ |
253,147 |
|
|
$ |
202,457 |
|
|
$ |
166,471 |
|
Net income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.05 |
|
|
$ |
0.87 |
|
|
$ |
0.74 |
|
Diluted |
|
|
1.00 |
|
|
|
0.82 |
|
|
|
0.70 |
|
Cash flow from operations |
|
$ |
570,214 |
|
|
$ |
461,810 |
|
|
$ |
360,960 |
|
Certain of our operating statistics for each of the last three years are set forth in the
following chart:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
27,925 |
|
|
|
22,936 |
|
|
|
20,013 |
|
Mcf/d |
|
|
97,141 |
|
|
|
83,075 |
|
|
|
58,696 |
|
BOE/d (1) |
|
|
44,115 |
|
|
|
36,782 |
|
|
|
29,795 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
711,457 |
|
|
$ |
501,176 |
|
|
$ |
367,414 |
|
Natural gas sales |
|
|
241,331 |
|
|
|
215,381 |
|
|
|
181,641 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
952,788 |
|
|
$ |
716,557 |
|
|
$ |
549,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas derivative contracts (in thousands) (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlements of derivative contracts |
|
$ |
20,480 |
|
|
$ |
(5,302 |
) |
|
$ |
(16,761 |
) |
Non-cash fair value adjustment income (expense) |
|
|
(39,077 |
) |
|
|
25,130 |
|
|
|
(12,201 |
) |
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and gas derivative contracts |
|
$ |
(18,597 |
) |
|
$ |
19,828 |
|
|
$ |
(28,962 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
230,932 |
|
|
$ |
167,271 |
|
|
$ |
108,550 |
|
Production taxes and marketing expenses (3) |
|
|
49,091 |
|
|
|
36,351 |
|
|
|
27,582 |
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
280,023 |
|
|
$ |
203,622 |
|
|
$ |
136,132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
13,630 |
|
|
$ |
9,376 |
|
|
$ |
8,119 |
|
CO2 operating expenses |
|
|
4,214 |
|
|
|
3,190 |
|
|
|
2,251 |
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
9,416 |
|
|
$ |
6,186 |
|
|
$ |
5,868 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit sales price including impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
68.84 |
|
|
$ |
59.23 |
|
|
$ |
50.30 |
|
Gas price per Mcf |
|
|
7.66 |
|
|
|
7.10 |
|
|
|
7.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit sales price excluding impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
69.80 |
|
|
$ |
59.87 |
|
|
$ |
50.30 |
|
Gas price per Mcf |
|
|
6.81 |
|
|
|
7.10 |
|
|
|
8.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas operating revenues and expenses per BOE (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
59.17 |
|
|
$ |
53.37 |
|
|
$ |
50.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas lease operating expenses |
|
$ |
14.34 |
|
|
$ |
12.46 |
|
|
$ |
9.98 |
|
Oil and gas production taxes and marketing expenses |
|
|
3.05 |
|
|
|
2.71 |
|
|
|
2.54 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
17.39 |
|
|
$ |
15.17 |
|
|
$ |
12.52 |
|
|
|
|
|
(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. We do not apply hedge accounting for our oil and natural gas derivative
contracts; see Note 10 to the |
40
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
Consolidated Financial Statements and Critical Accounting Policies and
Estimates Oil and Gas Derivative Contracts below. |
|
(3) |
|
For 2007, 2006 and 2005, includes transportation expenses paid to Genesis of $6.0 million,
$4.4 million and $4.0 million, respectively. |
|
(4) |
|
For 2007, 2006 and 2005, includes deferred revenue of $4.4 million, $4.2 million and $3.1
million, respectively, associated with volumetric production payments and transportation
income of $5.2 million, $4.6 million and $3.5 million, respectively, both from Genesis. |
Production. Average daily production by area for 2005 and 2006, and each of the quarters of 2007
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 |
|
2007 |
|
2007 |
|
2007 |
|
2007 |
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
Mississippi CO2 floods |
|
|
11,779 |
|
|
|
13,683 |
|
|
|
16,101 |
|
|
|
17,428 |
|
|
|
|
14,767 |
|
|
|
10,070 |
|
|
|
9,215 |
|
Mississippi non-CO2 floods |
|
|
12,738 |
|
|
|
12,525 |
|
|
|
12,131 |
|
|
|
12,530 |
|
|
|
|
12,479 |
|
|
|
12,743 |
|
|
|
12,072 |
|
Texas |
|
|
6,989 |
|
|
|
9,048 |
|
|
|
10,695 |
|
|
|
13,488 |
|
|
|
|
10,074 |
|
|
|
4,868 |
|
|
|
2,145 |
|
Onshore Louisiana |
|
|
5,591 |
|
|
|
5,391 |
|
|
|
5,546 |
|
|
|
5,638 |
|
|
|
|
5,542 |
|
|
|
7,937 |
|
|
|
6,164 |
|
Alabama and other |
|
|
1,208 |
|
|
|
1,269 |
|
|
|
1,247 |
|
|
|
1,287 |
|
|
|
|
1,253 |
|
|
|
1,164 |
|
|
|
199 |
|
|
|
|
|
|
|
Total Company |
|
|
38,305 |
|
|
|
41,916 |
|
|
|
45,720 |
|
|
|
50,371 |
|
|
|
|
44,115 |
|
|
|
36,782 |
|
|
|
29,795 |
|
|
|
|
|
As outlined in the above table, average production in 2007 increased 20% (7,333 BOE/d) over
2006 levels, and 2006 production increased 23% over average levels in 2005. The production
increases in 2007 were primarily from increased oil production from our tertiary operations and
increased production from the Barnett Shale, partially reduced by declines in production from our
onshore Louisiana properties. During 2006, the most significant production increases were from the
Barnett Shale and our acquisition of Tinsley and Citronelle Fields in January 2006, which
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 decreased slightly each year
from the prior year (before giving effect to the January 2006 acquisition related increase noted
above), as this area is on a gradual decline from normal depletion, partially offset by drilling
activity developing the Selma Chalk natural gas reservoir in the Heidelberg area.
See CO2 Operations above for a discussion of the tertiary related production.
The general decrease in onshore Louisiana production in 2007 is due primarily to the expected
relatively rapid depletion of wells in this area as we have focused less of our spending and
activity in this area than we have historically. We closed on the divesture of these assets,
excluding any oil fields that could have tertiary oil potential, in December 2007 and February 2008
(see 2007 Overview Sale of Louisiana Natural Gas Assets). The increase in production during
2006 in this area was a result of a higher level of activity during 2005 and early 2006 before the
decision was made to sell the properties in this area.
Our production in the Barnett Shale area during 2007 increased 4,690 BOE/d (97% increase) over
our 2006 level, and during 2006 increased 2,723 BOE/d (127% increase) over our 2005 level,
primarily as a result of higher drilling activity levels than in 2005. We drilled and completed 45
wells during 2007 and 46 wells during 2006, as compared to 23 wells drilled during 2005, and plan
to drill 45 to 50 wells during 2008. We had four rigs working in the area during most of the first quarter of 2007, but in the
second quarter reduced our rig count in this area to three, which we retained for the remainder of
2007. During the fourth quarter of 2007, we processed our natural gas through a different gas
plant, increasing the amount of liquids we recovered by 2,469 BOE/d, the primary reason for
41
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
the increased production that quarter. We believe that our fourth quarter of 2007 production has
peaked, or is near its peak, from this area, based on the anticipated level of future drilling
activity. These wells are characterized by steep decline rates in their first year of production
(typically 50% to 60%), followed by a gradual leveling-off of production and a resultant slow
decline rate, giving them an overall long production life. The Texas property acquisition we made
late in the first quarter of 2007 (see 2007 Overview 2007 Acquisitions) contributed
approximately 524 BOE/d to the 2007 average production from this area.
Our production for 2007 was 63% oil as compared to 62% during 2006 and 67% in 2005, as the
recent increases in natural gas production in the Barnett Shale area and fluctuating natural gas
production in Louisiana have generally been matched by increases in our tertiary oil production.
Oil and Natural Gas Revenues. Our oil and natural gas revenues have increased for each of the
last two years, as both overall commodity prices and production were higher. The increase in
production in 2007 increased oil and natural gas revenues by $142.9 million, or 20%, while the
increase in overall commodity prices increased revenues by $93.4 million, or 13%, over the prior
years levels. The increase in production in 2006 increased oil and natural gas revenues by $128.8
million, or 23%, while the increase in overall commodity prices increased revenues by $38.7
million, or 6%, over the prior years levels.
Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX
differentials were as follows during 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2007 |
|
2006 |
|
2005 |
Net Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
69.80 |
|
|
$ |
59.87 |
|
|
$ |
50.30 |
|
Gas price per Mcf |
|
|
6.81 |
|
|
|
7.10 |
|
|
|
8.48 |
|
Price per BOE |
|
|
59.17 |
|
|
|
53.37 |
|
|
|
50.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(2.65 |
) |
|
$ |
(6.41 |
) |
|
$ |
(6.33 |
) |
Natural Gas per Mcf |
|
|
(0.28 |
) |
|
|
0.13 |
|
|
|
(0.49 |
) |
Our oil NYMEX differential during 2007 was the lowest in our corporate history. The improved
NYMEX differential during 2007 was related to higher prices received for both our light sweet
barrels and our sour barrels primarily as a result of NYMEX (WTI) prices being depressed due to
lack of available storage capacity in the mid-continent area, an oversupply of crude from Canada,
capacity/transportation issues in moving crude oil out of the Cushing, Oklahoma, area and
unanticipated refinery outages. This trend reversed itself by the fourth quarter of 2007, with
average NYMEX oil differentials during that quarter of $(7.27) per Bbl, higher than our historical
averages due to the significant increase in liquids extracted from our natural gas production in
the Barnett Shale which is recorded as oil production, but sells at a significant discount to NYMEX
(see also Results of Operations Production above).
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during a month as most of our natural gas is sold on an index price that is set near the
first of the month. While the percentage change in the above table is quite large, these
differentials are very seldom more than a dollar above or below the NYMEX amount.
Oil and Natural Gas Derivative Contracts. During 2007, we had significant
fluctuations in our pre-tax income related to non-cash fair value adjustments in our oil and
natural gas derivative
contracts (expense of $35.2 million in the first quarter, income of $13.3 million in the
second quarter, expense of $5.4 million in the third quarter and expense of $11.8 million in the
fourth quarter), while at the same time, during each quarter in 2007 we had net positive cash
receipts on the settlements of our commodity derivative contracts, aggregating $20.5 million during
the year, all related to our 2007 natural gas swaps, partially offset by payments on our oil swaps.
In comparison, 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. During 2005, we made payments on our derivative contracts of $16.8 million related
to a natural gas collar.
42
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition
and Results of Operations
Changing commodity prices cause fluctuations in the mark-to-market value adjustments of our
derivative contracts. During 2007, we expensed $24.6 million related to our natural gas swaps,
primarily offsetting the gain we recognized on the same swaps in late 2006 as the swaps had expired
by the end of 2007. We also expensed $14.5 million related to our oil swaps as a result of the
increasing oil price. 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. See also Market Risk
Management and Note 10 to the Consolidated Financial Statements for more discussion of our oil and
natural gas derivative contracts.
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) higher
overall industry costs, (iii) increased personnel and related costs, (iv) higher fuel and energy
costs to operate our properties, and (v) increasing lease payments for certain of our tertiary
operating facilities and equipment.
During
2007, operating costs averaged $14.34 per BOE, up from $12.46 per BOE during 2006, and $9.98
per BOE in 2005. Operating expenses for our tertiary operations were $106.5 million in 2007, up
from $65.0 million during 2006, and $40.4 million during 2005, all 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. Further, the sale of our Louisiana natural gas properties
(see 2007 Overview Sale of Louisiana Natural Gas Properties) will further increase our
corporate average operating cost per BOE in the future. If the sold properties were excluded from
our operating results for the entire year of 2007, our operating costs would have been
approximately $15.47 per BOE, approximately $1.13 per BOE higher than as reported.
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. Transportation and plant processing fees were approximately $6.9 million higher in 2007
than in 2006 and approximately $0.8 million higher in 2006 than in 2005, largely associated with
the incremental production and incremental plant processing fees related to our Barnett Shale
production.
General and Administrative Expenses
During the last three years, general and administrative (G&A) expenses have increased on a
gross basis, while fluctuating on a per BOE basis as outlined below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Net G&A expense (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Gross G&A expense |
|
$ |
115,519 |
|
|
$ |
96,479 |
|
|
$ |
64,622 |
|
State franchise taxes |
|
|
2,915 |
|
|
|
1,825 |
|
|
|
1,454 |
|
Operator labor and overhead recovery charges |
|
|
(59,145 |
) |
|
|
(47,667 |
) |
|
|
(32,452 |
) |
Capitalized exploration and development costs |
|
|
(10,317 |
) |
|
|
(7,623 |
) |
|
|
(5,084 |
) |
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
48,972 |
|
|
$ |
43,014 |
|
|
$ |
28,540 |
|
|
|
|
|
|
|
|
|
|
|
Average G&A cost per BOE |
|
$ |
3.04 |
|
|
$ |
3.20 |
|
|
$ |
2.62 |
|
Employees as of December 31 |
|
|
686 |
|
|
|
596 |
|
|
|
460 |
|
Gross
G&A expenses increased $19.0 million, or 20% between 2006 and 2007, and $31.9 million, or 49%,
between 2005 and 2006. The increases are primarily due to higher compensation and personnel
related costs caused by an increase in the number of employees, and higher wages as a result of
average salary increases of between 5% and 10% during 2006 and 2007, which we consider necessary in
order to remain competitive in our industry. During 2006, we increased our employee count by 30%,
and we further increased our employee count 15% during 2007. Partially offsetting these overall
compensation increases were $6.0 million of non-recurring charges related to the retirement and
departure of two vice presidents during 2006. The adoption of SFAS No. 123(R) in January 2006
43
Denbury Resources Inc.
Managements Discussion and Analysis of Financial
Condition and Results of Operations
increased gross G&A expense by approximately $8.9 million during 2006, representing the non-cash
charge for stock compensation (stock options and stock appreciation rights) pertaining to personnel
charged to G&A. Stock compensation expense reflected in gross G&A was $12.2 million during 2007,
$18.9 million during 2006 and $4.2 million during 2005.
Higher operator overhead recovery charges resulting from incremental activity helped to
partially offset the increase in gross G&A. 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, increased drilling activity and
increased compensation expense (including the allocation of that portion of stock compensation
charged to lease operating expense), the amount we recovered as operator labor and overhead charges
increased by 24% between 2006 and 2007, and 47% between 2005 and 2006. Capitalized exploration and
development costs increased each year primarily due to additional personnel and increased
compensation costs, and the adoption of SFAS No. 123(R) in January 2006.
The net effect of the increases in gross G&A expenses, operator overhead recoveries and
capitalized exploration costs was a 14% increase in net G&A expense between 2006 and 2007, and a
51% increase in net G&A expense between 2005 and 2006. On a per BOE basis, G&A decreased 5% in
2007 as compared to 2006 as the higher production more than offset the increase in gross costs, but
G&A per BOE increased 22% in 2006 as compared to 2005 levels.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE data |
|
2007 |
|
|
2006 |
|
|
2005 |
|
Cash interest expense |
|
$ |
49,205 |
|
|
$ |
33,787 |
|
|
$ |
18,800 |
|
Non-cash interest expense |
|
|
2,010 |
|
|
|
1,121 |
|
|
|
827 |
|
Less: Capitalized interest |
|
|
(20,385 |
) |
|
|
(11,333 |
) |
|
|
(1,649 |
) |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
30,830 |
|
|
$ |
23,575 |
|
|
$ |
17,978 |
|
|
|
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
5,532 |
|
|
$ |
6,379 |
|
|
$ |
3,532 |
|
|
|
|
|
|
|
|
|
|
|
Average net cash interest expense per BOE (1) |
|
$ |
1.43 |
|
|
$ |
1.26 |
|
|
$ |
1.28 |
|
Average debt outstanding |
|
$ |
672,376 |
|
|
$ |
455,603 |
|
|
$ |
248,825 |
|
Average interest rate (2) |
|
|
7.3 |
% |
|
|
7.4 |
% |
|
|
7.6 |
% |
|
|
|
(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. |
Interest expense has increased each of the last two years corresponding to our increase in
average debt levels as we used debt to fund a $250 million acquisition in January 2006, other lower
cost acquisitions in 2006 and 2007, and to fund a portion of our capital spending, which in 2007
was significantly in excess of our cash flow from operations. These increases in cash interest
have been partially offset by higher interest amounts capitalized on our significant unevaluated
properties, primarily related to our 2006 acquisition, continued expansion of our tertiary
operations and construction of our CO2 pipelines. The average interest rate has been
relatively unchanged because our subordinated debt, which was 89% of the total 2007 average debt,
82% of the total 2006 average debt, and 93% of the total 2005 average debt, is a fixed interest
rate.
44
Denbury Resources Inc.
Managements Discussion and Analysis of Financial
Condition and Results of Operations
Depletion, Depreciation and Amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE data |
|
2007 |
|
|
2006 |
|
|
2005 |
|
Depletion and depreciation of oil and natural gas properties |
|
$ |
174,356 |
|
|
$ |
132,880 |
|
|
$ |
88,949 |
|
Depletion and depreciation of CO2 assets |
|
|
11,609 |
|
|
|
8,375 |
|
|
|
5,334 |
|
Asset retirement obligations |
|
|
2,977 |
|
|
|
2,389 |
|
|
|
1,682 |
|
Depreciation of other fixed assets |
|
|
6,958 |
|
|
|
5,521 |
|
|
|
2,837 |
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
195,900 |
|
|
$ |
149,165 |
|
|
$ |
98,802 |
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.02 |
|
|
$ |
10.08 |
|
|
$ |
8.34 |
|
CO2 assets and other fixed assets |
|
|
1.15 |
|
|
|
1.03 |
|
|
|
0.75 |
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
12.17 |
|
|
$ |
11.11 |
|
|
$ |
9.09 |
|
|
|
|
|
|
|
|
|
|
|
Our proved reserves increased from 152.6 MMBOE as of December 31, 2005, to 174.3 MMBOE as of
December 31, 2006, and further increased to 194.7 MMBOE as of December 31, 2007. 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 per BOE increased 10% between 2006 and 2007, and 22% between 2005 and 2006, primarily
due to capital spending and increased costs. We added approximately 22.8 MMBOE and 17.8 MMBOE of
reserves in the Barnett Shale and approximately 12.7 MMBOE and 6.0 MMBOE in our tertiary oil
properties during 2007 and 2006, respectively, and only minor amounts elsewhere. Further, as a
result of rising industry costs, we not only exceeded our cost estimates on our projects over the
last two years, but also increased our future development costs on our proved undeveloped reserves
to reflect these rising costs.
In general, 2006 was a transition year for us with regard to recording proved 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 tertiary flood) and
thus it was not necessary to have a production response to CO2 injections before we
recognized proved reserves. Conversely, since that time, most of our new floods 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. During 2006, two of our most significant new floods were
Soso and Martinville Fields (Phase II), for which reserves were not booked until 2007 after we had
a significant production response. During 2007, we initiated floods at Lockhart Crossing (Phase
I), Tinsley (Phase III) and Cranfield (Phase IV) that will not result in additional proved reserves
until we have a production response, which is expected in 2008. We expect this same delay factor
to continue in the future with regard to recording most of our projected proved tertiary reserves,
although we expect our proved reserves to increase more rapidly in the future because of the
projected size and magnitude of the potential reserves from projects either started or planned.
We allocated approximately $33.9 million of the $39.4 million adjusted purchase price of our
March 31, 2007 Seabreeze acquisition, $124 million of our $250 million January 2006 acquisition
costs for Tinsley, Citronelle and South Cypress Creek Fields, and virtually all of the second
quarter 2006 $50 million Delhi acquisition costs to unevaluated properties to reflect the
significant potential reserves associated with future tertiary floods that we considered to be part
of these acquisitions. As a result, these acquisitions did not materially impact 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 for our CO2 and other fixed assets increased in both 2006 and 2007 as
a result of the building of our 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 4.6 Tcf as of December 31, 2005, to 5.5 Tcf as of December
31, 2006, and 5.6 Tcf as of December 31, 2007 (100% working interest basis before amounts
attributable to Genesis volumetric production payments see CO2 Operations -
CO2 Resources).
45
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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, 2005, 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, and
as of December 31, 2007, we estimated our retirement obligations to be $100.6 million ($41.3
million present value), with an estimated salvage value of $67.3 million, the increase related to
our recent acquisitions, increased activity and higher cost estimates due to the inflation in our
industry, partially offset by a decrease in our obligation of approximately $9.4 million, ($9.2
million present value) related to the sale of most of our Louisiana natural gas properties in late
2007. DD&A is calculated on the increase in retirement obligations recorded as incremental oil
and natural gas and CO2 properties, net of its 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 2005, 2006 or 2007.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE amounts |
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Current income tax expense |
|
$ |
30,074 |
|
|
$ |
19,865 |
|
|
$ |
27,177 |
|
Deferred income tax provision |
|
|
110,193 |
|
|
|
107,252 |
|
|
|
54,393 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision |
|
$ |
140,267 |
|
|
$ |
127,117 |
|
|
$ |
81,570 |
|
|
|
|
|
|
|
|
|
|
|
Average income tax provision per BOE |
|
$ |
8.71 |
|
|
$ |
9.47 |
|
|
$ |
7.50 |
|
Effective tax rate |
|
|
35.7 |
% |
|
|
38.6 |
% |
|
|
32.9 |
% |
Total net deferred tax asset (liability) |
|
$ |
(334,662 |
) |
|
$ |
(229,925 |
) |
|
$ |
(129,474 |
) |
|
|
|
|
|
|
|
|
|
|
Our income tax provision was based on an estimated statutory rate of approximately 38% in
2007, and 39% in 2006 and 2005, adjusted for the impact of certain items such as compensation
arising from incentive stock options that cannot be deducted for tax purposes in the same manner as
book expense. The reduction in the estimated statutory rate to 38% in 2007 was a result of our
sale of our Louisiana natural gas assets during the fourth quarter of 2007. For 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 and 2007, we did not
earn any additional EOR credits because of the high oil prices during 2005 and 2006, which
completely phased out our ability to earn any additional credits.
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, 2007, we had an
estimated $37 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 2024. 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 in the future unless oil prices decrease
significantly from current levels. Once our existing EOR credits are utilized, our cash taxes will
also increase.
46
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations on a Per BOE Basis
The following table summarizes the cash flow, DD&A and results of operations on a per BOE
basis for the comparative periods. Each of the individual components is discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Per BOE data |
|
2007 |
|
2006 |
|
2005 |
|
Oil and natural gas revenues |
|
$ |
59.17 |
|
|
$ |
53.37 |
|
|
$ |
50.49 |
|
Gain (loss) on settlements of derivative contracts |
|
|
1.27 |
|
|
|
(0.39 |
) |
|
|
(1.54 |
) |
Lease operating expenses |
|
|
(14.34 |
) |
|
|
(12.46 |
) |
|
|
(9.98 |
) |
Production taxes and marketing expenses |
|
|
(3.05 |
) |
|
|
(2.71 |
) |
|
|
(2.54 |
) |
|
Production netback |
|
|
43.05 |
|
|
|
37.81 |
|
|
|
36.43 |
|
Non-tertiary CO2 operating margin |
|
|
0.58 |
|
|
|
0.46 |
|
|
|
0.54 |
|
General and administrative expenses |
|
|
(3.04 |
) |
|
|
(3.20 |
) |
|
|
(2.62 |
) |
Net cash interest expense |
|
|
(1.43 |
) |
|
|
(1.26 |
) |
|
|
(1.28 |
) |
Current income taxes and other |
|
|
(1.37 |
) |
|
|
(0.41 |
) |
|
|
(1.50 |
) |
Changes in assets and liabilities relating to operations |
|
|
(2.38 |
) |
|
|
1.00 |
|
|
|
1.62 |
|
|
Cash flow from operations |
|
|
35.41 |
|
|
|
34.40 |
|
|
|
33.19 |
|
DD&A |
|
|
(12.17 |
) |
|
|
(11.11 |
) |
|
|
(9.09 |
) |
Deferred income taxes |
|
|
(6.84 |
) |
|
|
(7.99 |
) |
|
|
(5.00 |
) |
Non-cash commodity derivative adjustments |
|
|
(2.43 |
) |
|
|
1.87 |
|
|
|
(1.12 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
1.75 |
|
|
|
(2.09 |
) |
|
|
(2.67 |
) |
|
Net income |
|
$ |
15.72 |
|
|
$ |
15.08 |
|
|
$ |
15.31 |
|
|
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
$150 million of bank debt outstanding as of December 31, 2007, and $111 million outstanding as of
February 28, 2008. None of our existing debt has any triggers or covenants regarding our debt
ratings with rating agencies. The fair value of the subordinated debt is based on quoted market
prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
Carrying |
|
Fair |
Amounts in thousands |
|
2011 |
|
2013 |
|
2015 |
|
Value |
|
Value |
|
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted average interest rate of 6.2%
at December 31, 2007) |
|
$ |
150,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
150,000 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2013 (fixed rate of 7.5%) |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
223,980 |
|
|
|
227,250 |
|
7.5% subordinated debt due 2015 (fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
300,685 |
|
|
|
303,000 |
|
|
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 enter into natural gas derivative contracts in late 2006
and September 2007 as we believed that there is more risk with regard to natural gas prices and the
fact that we planned to spend significantly more than
our projected cash flow from operations during the ensuing year (see Capital Resources and
Liquidity). In late 2006, we swapped 80% to 90% of our forecasted 2007 natural gas production
at
a weighted average price of $7.96 per Mcf, and in September 2007 we swapped 70% to 80% of our
remaining forecasted 2008 natural gas production
47
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
(after the sale of our Louisiana natural gas
properties see 2007 Overview Sale of Louisiana Natural Gas Properties) at a weighted average
price of $7.91 per Mcf.
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, 2007, 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 between 5% and 6% of our estimated 2008 oil
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 2008 at a price of $57.34 per Bbl.
All of the mark-to-market valuations used for our oil and natural gas 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 2007, see Note 10 to the Consolidated Financial
Statements.
Since January 1, 2005, for accounting purposes, we have elected to account for our oil and
natural gas derivative contracts 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, 2007, our derivative contracts were recorded at their fair value, which was a
net liability of approximately $23.3 million, a decrease of $39.0 million from the $15.7 million
fair value asset recorded as of December 31, 2006. This change is primarily related to the
recognition of our natural gas hedges which expired during 2007, but were a significant asset at
December 31, 2006 (see above), and higher oil prices which reduced the value of the remaining oil
swaps. During 2007, we recognized total expenses related to our hedge contracts of $18.6 million,
consisting of $20.5 million of net cash receipts on settlements of expired contracts and $39.1
million of expense relating to market-to-market non-cash adjustments.
Based on NYMEX crude oil futures prices at December 31, 2007, we would expect to make future
cash payments of $26.3 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 $19.5 million, and if futures prices were to increase by 10%
we would expect to pay $33.1 million. Based on NYMEX natural gas futures prices at December 31,
2007, we would expect to receive future cash payments of $2.4 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 $19.5 million, and if future
prices were to increase by 10% we would expect to pay $14.7 million.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with generally accepted accounting
principles requires that we select certain accounting policies and make certain estimates and
judgments regarding the application of those policies. Our significant accounting policies are
included in Note 1 to the Consolidated Financial Statements. These policies, along with the
underlying assumptions and judgments by our management in their application, have a significant
impact on our consolidated financial statements. Following is a discussion of our most critical
accounting estimates, judgments and uncertainties that are inherent in the preparation of our
financial statements.
Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Reserves
Businesses involved in the production of oil and natural gas are required to follow accounting
rules that are
unique to the oil and gas industry. We apply the full-cost method of accounting for our oil
and natural gas properties. Another acceptable method of accounting for oil and gas production
activities is the successful efforts method of accounting. In general, the primary differences
between the two methods are related to the capitalization
48
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 2.5% of the previous years estimates and have been both
positive and negative.
Changes in commodity prices also affect our reserve quantities. During 2005, 2006 and 2007,
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 2007 DD&A rate from $12.05 per Bbl
to approximately $11.55 per Bbl, and a 5% decrease in our proved reserve quantities would have
increased our DD&A rate to approximately $12.60 per Bbl. Also, reserve quantities and their
ultimate values are the primary factors in determining the borrowing base under our bank credit
facility and are determined solely by our banks.
There can also be significant questions as to whether reserves are sufficiently supported by
technical evidence to be considered proven. In some cases our proven reserves are less than what
we believe to exist because additional evidence, including production testing, is required in order
to classify the reserves as proven. 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 subsequent three years (or at least the commencement of the
project is scheduled in the case of longer-term multi-year projects such as waterfloods and
tertiary recovery projects). Therefore, with regard to potential reserves, 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 further discussion.) All of these factors and the decisions made regarding
these issues can have a significant effect on our proven reserves
49
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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.
Tertiary Injection Cost
Our tertiary operations are conducted in reservoirs
that have already produced significant amounts of oil over many years; however, in accordance with
the rules for recording proved reserves, we cannot recognize proved reserves associated with
enhanced recovery techniques, such as CO2 injection, until there is a production
response to the injected CO2 or, unless the field is analogous to an existing flood. Our
costs associated with the CO2 we produce (or acquire) and inject are principally our
costs of production, transportation and acquisition, or to pay royalties.
Prior to January 1, 2008, we expensed currently all costs associated with injecting
CO2
that we use in our tertiary recovery operations, even though some of these costs
were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we will
begin capitalizing, as a development cost, injection costs in fields that are in their development
stage, which means we have not yet seen incremental oil production due to the CO2
injections (i.e. a production response). These capitalized development costs will be included in
our unevaluated property costs within our full cost pool if there are not already proved tertiary
reserves in that field. After we see a production response to the CO2 injections (i.e.
the production stage), injection costs will be expensed as incurred and any previously deferred
unevaluated development costs will become subject to depletion upon
recognition of proved tertiary reserves.
Based upon the current status of some of our tertiary floods, this change in accounting will cause
us to capitalize certain costs that we historically expensed. Had the new method of accounting for
tertiary injectant costs been used in periods prior to January 1, 2008, the effect on our financial
statements would have been immaterial for all periods presented.
Asset Retirement Obligations
We have significant obligations related to the plugging and abandonment of our oil, natural
gas and CO2 wells, the removal of equipment and facilities from leased acreage, and land
restoration. SFAS No. 143 requires that we estimate the future cost of this obligation, discount
it to its present value, and record a corresponding asset and liability in our Consolidated Balance
Sheets. The values ultimately derived are based on many significant estimates, including the
ultimate expected cost of the obligation, the expected future date of the required cash payment,
and interest and inflation rates. Revisions to these estimates may be required based on changes to
cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that
result in upward or downward revisions in the estimated obligation will result in an adjustment to
the related capitalized asset and corresponding liability on a prospective basis and an adjustment
in our DD&A expense in future periods. See Note 4 to our Consolidated Financial Statements for
further discussion regarding our asset retirement obligations.
Income Taxes
We make certain estimates and judgments in determining our income tax expense for financial
reporting purposes. These estimates and judgments occur in the calculation of certain tax assets
and liabilities that arise from differences in the timing and recognition of revenue and expense
for tax and financial reporting purposes. Our federal and state income tax returns are generally
not prepared or filed before the consolidated financial statements are prepared; therefore, we
estimate the tax basis of our assets and liabilities at the end of each period as well as the
effects of tax rate changes, tax credits and, prior to year-end 2005, net operating loss
carryforwards. Adjustments related to these estimates are recorded in our tax provision in the
period in which we file our income tax returns. Further, we must assess the likelihood that we
will be able to recover or utilize our deferred tax assets (primarily our enhanced oil recovery
credits). If recovery is not likely, we must record a valuation allowance against such deferred
tax assets for the amount we would not expect to recover, which would result in an increase to our
income tax expense. As of December 31, 2007, 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 $3.9
million, $3.3 million and $2.5 million for the years ended December 31, 2007, 2006 and 2005,
respectively. See Note 7 to the Consolidated Financial Statements for further information
concerning our income taxes.
50
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil and Natural Gas Derivative Contracts
We enter into oil and natural gas 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.
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 2007, 2006 and 2005, we recognized expense (income) of $39.1 million,
($25.1) million and $4.5 million, respectively, related to changes in the fair market value of our
derivative contracts.
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 No. 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 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, 2007, there was $9.8 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 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 United
States generally accepted accounting principles, and expands disclosures about fair value
measurements. SFAS No. 157 does not require any new fair value measurements, but provides guidance
on how to measure fair
51
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
value by providing a fair value hierarchy used to classify the source of the
information. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007.
However, on February 12, 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date
of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring basis (at least
annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning
after November 15, 2008, and interim periods within those fiscal years for items within the scope
of this FSP. Effective for 2008, we will adopt SFAS No. 157 except as it applies to those
nonfinancial assets and nonfinancial liabilities as noted in FSP SFAS No. 157-2. We have not yet
determined the impact the partial adoption of SFAS No. 157 will have on the Companys financial
condition or results of operations.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities. SFAS No. 159 permits entities to choose to measure many financial
instruments and certain other items at fair value, with the objective of improving financial
reporting by giving entities the opportunity to mitigate volatility in reported earnings caused by
measuring related assets and liabilities differently without having to apply complex hedge
accounting provisions. The provisions of SFAS No. 159 are effective for us beginning January 1,
2008. We have not yet determined what impact, if any, this pronouncement will have on our
financial condition or results of operations.
In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combinations.
SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures
in its financial statements the identifiable assets acquired, the liabilities assumed, any
noncontrolling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes
disclosure requirements to enable the evaluation of the nature and financial effects of the
business combination. This statement is effective for us beginning January 1, 2009. We have not yet
determined what impact, if any, this pronouncement will have on our
financial condition or results
of operations.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements an amendment of ARB No. 51. SFAS No. 160 establishes accounting and
reporting standards for ownership interests in subsidiaries held by parties other than the parent,
the amount of consolidated net income attributable to the parent and to the noncontrolling
interest, changes in a parents ownership interest, and the valuation of retained noncontrolling
equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure
requirements that clearly identify and distinguish between the interests of the parent and the
interests of the noncontrolling owners. This statement is effective for us beginning January 1,
2009. We have not yet determined what impact, if any, this pronouncement will have on our financial
condition or 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, 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, and unexpected delays, as well as the risks and uncertainties inherent in
oil and gas drilling and production activities
52
Denbury Resources Inc.
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 |
Managements Report on Internal Control over Financial Reporting |
|
|
54 |
|
Report of Independent Registered Public Accounting Firm |
|
|
55 |
|
Consolidated Balance Sheets |
|
|
56 |
|
Consolidated Statements of Operations |
|
|
57 |
|
Consolidated Statements of Cash Flows |
|
|
58 |
|
Consolidated Statements of Changes in Stockholders Equity |
|
|
59 |
|
Consolidated Statements of Comprehensive Income |
|
|
60 |
|
Notes to Consolidated Financial Statements |
|
|
61 |
|
Supplemental Oil and Natural Gas Disclosures (Unaudited) |
|
|
89 |
|
Quarterly Financial Information (Unaudited) |
|
|
92 |
|
|
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, 2007. 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, 2007, based on those criteria. The
effectiveness of the Companys internal control over financial reporting as of December 31, 2007,
has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm,
as stated in their report which appears herein.
54
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Denbury Resources Inc.:
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, 2007 and 2006, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2007 in conformity with
accounting principles generally accepted in the United States of America. Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2007, based on criteria established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The
Companys management is responsible for these financial statements, for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Managements Report on Internal
Control over Financial Reporting. Our responsibility is to express opinions on these financial
statements and on the Companys internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was maintained in all
material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
As discussed in Note 1 to the consolidated financial statements, the Company changed the
manner in which it accounts for stock-based compensation costs in 2006.
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.
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, 2008
55
Denbury Resources Inc.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
(In Thousands, Except Shares) |
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Assets |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
60,107 |
|
|
$ |
53,873 |
|
Accrued production receivable |
|
|
136,284 |
|
|
|
72,398 |
|
Trade and other receivables, net of
allowance of $369 and $315 |
|
|
28,977 |
|
|
|
24,260 |
|
Derivative assets |
|
|
2,283 |
|
|
|
26,883 |
|
Deferred tax assets |
|
|
12,708 |
|
|
|
5,855 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
240,359 |
|
|
|
183,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment |
|
|
|
|
|
|
|
|
Oil and natural gas properties (using
full cost accounting)
|
|
|
|
|
|
|
|
|
Proved |
|
|
2,682,932 |
|
|
|
2,226,942 |
|
Unevaluated |
|
|
366,518 |
|
|
|
293,657 |
|
CO2
properties and equipment |
|
|
436,591 |
|
|
|
267,483 |
|
Other |
|
|
50,116 |
|
|
|
43,133 |
|
Less accumulated depletion and
depreciation |
|
|
(1,143,282 |
) |
|
|
(951,447 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
2,392,875 |
|
|
|
1,879,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deposits on properties under option or
contract |
|
|
49,097 |
|
|
|
49,002 |
|
Other assets |
|
|
88,746 |
|
|
|
27,798 |
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
2,771,077 |
|
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
147,580 |
|
|
$ |
139,111 |
|
Oil and gas production payable |
|
|
84,150 |
|
|
|
52,244 |
|
Derivative liabilities |
|
|
28,096 |
|
|
|
4,302 |
|
Deferred revenue Genesis |
|
|
4,070 |
|
|
|
4,070 |
|
Short-term capital lease obligations |
|
|
737 |
|
|
|
671 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
264,633 |
|
|
|
200,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term Liabilities |
|
|
|
|
|
|
|
|
Capital lease obligations |
|
|
5,665 |
|
|
|
6,387 |
|
Long-term debt, net of discount or
premium |
|
|
674,665 |
|
|
|
507,786 |
|
Asset retirement obligations |
|
|
38,954 |
|
|
|
39,331 |
|
Derivative liabilities |
|
|
|
|
|
|
6,834 |
|
Deferred revenue Genesis |
|
|
24,424 |
|
|
|
28,843 |
|
Deferred tax liability |
|
|
347,370 |
|
|
|
235,780 |
|
Other |
|
|
10,988 |
|
|
|
8,419 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
1,102,066 |
|
|
|
833,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 600,000,000 shares
authorized;
245,386,951 and 120,506,815 shares issued at
December 31,
2007 and 2006, respectively |
|
|
245 |
|
|
|
121 |
|
Paid-in capital in excess of par |
|
|
662,698 |
|
|
|
616,046 |
|
Retained earnings |
|
|
751,179 |
|
|
|
498,032 |
|
Accumulated other comprehensive loss |
|
|
(1,591 |
) |
|
|
|
|
Treasury stock, at cost, 637,795 and 370,327 shares at
December 31, 2007
and 2006, respectively |
|
|
(8,153 |
) |
|
|
(8,140 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,404,378 |
|
|
|
1,106,059 |
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders
Equity |
|
$ |
2,771,077 |
|
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
56
Denbury Resources Inc.
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands, Except Per Share Data) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and related product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated parties |
|
$ |
952,687 |
|
|
$ |
715,061 |
|
|
$ |
544,408 |
|
Related party Genesis |
|
|
101 |
|
|
|
1,496 |
|
|
|
4,647 |
|
CO2 sales and transportation fees |
|
|
13,630 |
|
|
|
9,376 |
|
|
|
8,119 |
|
Interest income and other |
|
|
5,532 |
|
|
|
6,379 |
|
|
|
3,532 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
971,950 |
|
|
|
732,312 |
|
|
|
560,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
230,932 |
|
|
|
167,271 |
|
|
|
108,550 |
|
Production taxes and marketing expenses |
|
|
43,130 |
|
|
|
31,993 |
|
|
|
23,553 |
|
Transportation expense Genesis |
|
|
5,961 |
|
|
|
4,358 |
|
|
|
4,029 |
|
CO2 operating expenses |
|
|
4,214 |
|
|
|
3,190 |
|
|
|
2,251 |
|
General and administrative |
|
|
48,972 |
|
|
|
43,014 |
|
|
|
28,540 |
|
Interest, net of amounts capitalized of
$20,385, $11,333 and $1,649
in 2007, 2006 and 2005, respectively |
|
|
30,830 |
|
|
|
23,575 |
|
|
|
17,978 |
|
Depletion, depreciation and amortization |
|
|
195,900 |
|
|
|
149,165 |
|
|
|
98,802 |
|
Commodity derivative expense (income) |
|
|
18,597 |
|
|
|
(19,828 |
) |
|
|
28,962 |
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
578,536 |
|
|
|
402,738 |
|
|
|
312,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
393,414 |
|
|
|
329,574 |
|
|
|
248,041 |
|
Income tax provision |
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
30,074 |
|
|
|
19,865 |
|
|
|
27,177 |
|
Deferred income taxes |
|
|
110,193 |
|
|
|
107,252 |
|
|
|
54,393 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
253,147 |
|
|
$ |
202,457 |
|
|
$ |
166,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share basic |
|
$ |
1.05 |
|
|
$ |
0.87 |
|
|
$ |
0.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
$ |
1.00 |
|
|
$ |
0.82 |
|
|
$ |
0.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
240,065 |
|
|
|
233,101 |
|
|
|
223,485 |
|
Diluted |
|
|
252,101 |
|
|
|
247,547 |
|
|
|
239,267 |
|
See Notes to Consolidated Financial Statements.
57
Denbury Resources Inc.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Cash Flow from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
253,147 |
|
|
$ |
202,457 |
|
|
$ |
166,471 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
195,900 |
|
|
|
149,165 |
|
|
|
98,802 |
|
Deferred income taxes |
|
|
110,193 |
|
|
|
107,252 |
|
|
|
54,393 |
|
Deferred revenue Genesis |
|
|
(4,419 |
) |
|
|
(4,180 |
) |
|
|
(3,080 |
) |
Stock based compensation |
|
|
10,595 |
|
|
|
17,246 |
|
|
|
4,121 |
|
Non-cash fair value derivative adjustments |
|
|
38,952 |
|
|
|
(25,129 |
) |
|
|
12,201 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
|
|
|
|
9,218 |
|
Amortization of debt issue costs and other |
|
|
4,149 |
|
|
|
1,603 |
|
|
|
1,257 |
|
Changes in assets and liabilities relating to operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued production receivable |
|
|
(63,886 |
) |
|
|
(5,474 |
) |
|
|
(21,388 |
) |
Trade and other receivables |
|
|
(10,409 |
) |
|
|
1,712 |
|
|
|
(14,924 |
) |
Other assets |
|
|
(819 |
) |
|
|
(672 |
) |
|
|
129 |
|
Accounts payable and accrued liabilities |
|
|
1,576 |
|
|
|
7,038 |
|
|
|
38,202 |
|
Oil and gas production payable |
|
|
31,906 |
|
|
|
10,422 |
|
|
|
16,966 |
|
Other liabilities |
|
|
3,329 |
|
|
|
370 |
|
|
|
(1,408 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities |
|
|
570,214 |
|
|
|
461,810 |
|
|
|
360,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Used for Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas expenditures |
|
|
(613,659 |
) |
|
|
(507,327 |
) |
|
|
(308,366 |
) |
Acquisitions of oil and gas properties |
|
|
(49,077 |
) |
|
|
(319,000 |
) |
|
|
(70,870 |
) |
Change in accrual for capital expenditures |
|
|
(421 |
) |
|
|
13,195 |
|
|
|
18,196 |
|
Investment in Genesis |
|
|
(47,738 |
) |
|
|
|
|
|
|
(4,257 |
) |
Acquisition of CO2 assets and CO2 capital expenditures |
|
|
(171,182 |
) |
|
|
(63,586 |
) |
|
|
(78,726 |
) |
Net purchases of other assets |
|
|
(13,672 |
) |
|
|
(10,531 |
) |
|
|
(6,441 |
) |
Deposits on properties under option or contract |
|
|
(7,595 |
) |
|
|
(11,159 |
) |
|
|
(21,917 |
) |
Increase in restricted cash |
|
|
(1,836 |
) |
|
|
(981 |
) |
|
|
(249 |
) |
Sales of short-term investments |
|
|
|
|
|
|
|
|
|
|
57,133 |
|
Net proceeds from CO2 production payment Genesis |
|
|
|
|
|
|
|
|
|
|
14,363 |
|
Net proceeds from other sales of properties and equipment |
|
|
142,667 |
|
|
|
42,762 |
|
|
|
17,447 |
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used for Investing Activities |
|
|
(762,513 |
) |
|
|
(856,627 |
) |
|
|
(383,687 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(265,000 |
) |
|
|
(249,000 |
) |
|
|
(64,800 |
) |
Bank borrowings |
|
|
281,000 |
|
|
|
383,000 |
|
|
|
64,800 |
|
Payments on capital lease obligations |
|
|
(671 |
) |
|
|
(580 |
) |
|
|
(521 |
) |
Income tax benefit from equity awards |
|
|
19,181 |
|
|
|
16,575 |
|
|
|
|
|
Issuance of subordinated debt |
|
|
150,750 |
|
|
|
|
|
|
|
150,000 |
|
Issuance of common stock |
|
|
18,222 |
|
|
|
139,834 |
|
|
|
12,392 |
|
Purchase of treasury stock |
|
|
(2,960 |
) |
|
|
(5,544 |
) |
|
|
(5,119 |
) |
Costs of debt financing |
|
|
(1,989 |
) |
|
|
(684 |
) |
|
|
(1,975 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Financing Activities |
|
|
198,533 |
|
|
|
283,601 |
|
|
|
154,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
6,234 |
|
|
|
(111,216 |
) |
|
|
132,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
53,873 |
|
|
|
165,089 |
|
|
|
33,039 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
60,107 |
|
|
$ |
53,873 |
|
|
$ |
165,089 |
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
58
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, 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 plans |
|
|
949,051 |
|
|
|
1 |
|
|
|
9,650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,651 |
|
Issued pursuant to directors
compensation plan |
|
|
3,502 |
|
|
|
|
|
|
|
119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119 |
|
Two-for-one stock split |
|
|
57,468,101 |
|
|
|
57 |
|
|
|
(57 |
) |
|
|
|
|
|
|
|
|
|
|
185,847 |
|
|
|
|
|
|
|
|
|
Restricted stock grants |
|
|
10,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 plan |
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74,130 |
|
|
|
(2,960 |
) |
|
|
(2,960 |
) |
Issued pursuant to employee stock
purchase plan |
|
|
|
|
|
|
|
|
|
|
2,099 |
|
|
|
|
|
|
|
|
|
|
|
(149,360 |
) |
|
|
2,947 |
|
|
|
5,046 |
|
Issued pursuant to employee stock
option plan |
|
|
2,071,940 |
|
|
|
2 |
|
|
|
13,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,176 |
|
Issued pursuant to directors
compensation plan |
|
|
3,981 |
|
|
|
|
|
|
|
136 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
136 |
|
Two-for-one stock split |
|
|
122,626,451 |
|
|
|
122 |
|
|
|
(122 |
) |
|
|
|
|
|
|
|
|
|
|
342,698 |
|
|
|
|
|
|
|
|
|
Restricted stock grants |
|
|
198,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants forfeited |
|
|
(20,590 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
12,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,184 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
|
|
|
|
19,181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,181 |
|
Derivative contracts, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,591 |
) |
|
|
|
|
|
|
|
|
|
|
(1,591 |
) |
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
245,386,951 |
|
|
$ |
245 |
|
|
$ |
662,698 |
|
|
$ |
751,179 |
|
|
$ |
(1,591 |
) |
|
|
637,795 |
|
|
$ |
(8,153 |
) |
|
$ |
1,404,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
59
Denbury Resources Inc.
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Net Income |
|
$ |
253,147 |
|
|
$ |
202,457 |
|
|
$ |
166,471 |
|
Other comprehensive income (loss), net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative contracts designated as a hedge,
net of tax of $1,017 |
|
|
(1,591 |
) |
|
|
|
|
|
|
|
|
Reclassification adjustments related to settlements of derivative
contracts, net of tax of $2,920 |
|
|
|
|
|
|
|
|
|
|
4,764 |
|
Unrealized gain on securities available for sale, net of tax of $15 |
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income |
|
$ |
251,556 |
|
|
$ |
202,457 |
|
|
$ |
171,259 |
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
60
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. A Denbury subsidiary is the general partner and owns an aggregate
9.25% interest in Genesis Energy, L.P. (Genesis), a publicly traded master limited partnership.
We account for our 9.25% 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 Splits
Stockholders of Denbury approved two 2-for-1 stock splits (described below) during the
three-year period ended December 31, 2007. 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 splits, except for the share amounts included on our Consolidated Balance
Sheets and Consolidated Statements of Changes in Stockholders Equity, which reflect the actual
shares outstanding at each period end.
On November 19, 2007, 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 250,000,000 shares to 600,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common
stock for each share of common stock held at that time.
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.
Oil and Natural Gas Operations
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.
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
61
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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
$11.60 in 2007, $10.54 in 2006 and $8.69 in 2005.
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 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.
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.
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.
Proved Reserves. See Note 15 for information on our proved oil and natural gas
reserves and the basis on which they are recorded.
Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs
that have already produced significant amounts of oil over many years; however, in accordance with
the rules for recording proved reserves, we cannot recognize proved reserves associated with
enhanced recovery techniques, such as CO2 injection, until there is a production
response to the injected CO2 or, unless the field is analogous to an existing flood. Our
costs associated with the CO2 we produce (or acquire) and inject are principally our
costs of production, transportation and acquisition, or to pay royalties.
Prior to January 1, 2008, we expensed currently all costs associated with injecting
CO2
that we use in our tertiary recovery operations, even though some of these costs
were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we will
begin capitalizing, as a development cost, injection costs in fields that are in their development
stage, which means we have not yet seen incremental oil production due to the CO2
injections (i.e. a production response). These capitalized development costs will be included in
our unevaluated property costs within our full cost pool if there are not already proved tertiary
reserves in that field. After we see a production response to the CO2 injections (i.e.
the production stage), injection costs will be expensed as incurred and any previously deferred
unevaluated development costs will become subject to depletion upon
recognition of proved tertiary reserves.
Based upon the current status of some of our tertiary floods, this change in accounting will cause
us to capitalize certain costs that we historically expensed. Had the new method of accounting for
tertiary injectant costs been used in periods prior to January 1, 2008, the effect on our financial
statements would have been immaterial for all periods presented.
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.
62
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, 2007 and 2006, 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 utilize oil and natural gas derivative contracts to mitigate our exposure to commodity
price risk associated with our future oil and natural gas production. These derivative contracts
have historically consisted of options, in the form of price floors or collars, and fixed price
swaps. We have also used interest rate lock contracts to mitigate our exposure to interest rate
fluctuations related to sale-leaseback financing of certain equipment used at our oilfield
facilities. Our derivative financial instruments are recorded on the balance sheet as either an
asset or a liability measured at fair value. Our recognition of the change in fair value depends
on the designation of the derivative instrument. The changes in fair value of derivatives that are
not designated as hedges under SFAS No. 133, as well as the ineffective portion of hedge
derivatives, are recognized currently in earnings. Unrealized gains or losses on effective cash
flow hedge derivatives, as well as any deferred gain or loss realized upon early termination of
effective hedge derivatives, are recognized as a component of accumulated other comprehensive
income. When the hedged transaction occurs, the realized gain or loss, as well as any deferred
gain or loss, on the hedge derivative is transferred from accumulated other comprehensive income to
earnings.
In order to qualify for hedge accounting, the relationship between the hedging instruments and
the hedged items must be highly effective in achieving the offset of changes in fair values or cash
flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis.
We measure hedge effectiveness on a quarterly basis. Hedge accounting is discontinued
prospectively when a hedging instrument becomes ineffective. We assess hedge effectiveness based
on total changes in the fair value of derivatives used in cash flow hedges rather than changes of
intrinsic value only. As a result, changes in the entire fair value of derivative contracts are
deferred in accumulated other comprehensive income, to the extent they are effective, until the
hedged transaction is completed.
Effective January 1, 2005, we elected to discontinue hedge accounting for our oil and natural
gas derivative contracts and accordingly de-designated our oil and gas 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. See Note 10 for further information on our derivative contracts.
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
63
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 or, effective January 1, 2008, are capitalized as oil and gas properties in our
Consolidated Balance Sheets, depending on the status of floods that receive the CO2 (see
Tertiary Injection Costs on page 62 for further discussion). 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, 2007 and 2006, we had approximately $9.5 million and $7.6 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,
2007 and 2006, 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.
All shares have been adjusted for our 2-for-1 stock splits. For each of the three years in
the period ended December 31, 2007, there were no adjustments to net income for purposes of
calculating basic and diluted net income per common share. In April 2006, we issued 6,985,190
shares (3,492,595 on a pre-split basis) 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Weighted average common shares basic |
|
|
240,065 |
|
|
|
233,101 |
|
|
|
223,485 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
10,485 |
|
|
|
12,376 |
|
|
|
13,862 |
|
Restricted stock |
|
|
1,551 |
|
|
|
2,070 |
|
|
|
1,920 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
252,101 |
|
|
|
247,547 |
|
|
|
239,267 |
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount in 2007, 2006 and 2005 excludes 2.7 million,
2.8 million and 4.0 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 130,000 shares in 2007, 256,000 shares in 2006 and 368,000 shares in 2005
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.
Effective January 1, 2007 we adopted the provision of
FASB Interpretation 48 (FIN 48), Accounting for Uncertainties in Income Taxes - an
interpretation of FASB Statement No. 109, Accounting for Income Taxes. This interpretation
addresses how tax benefits claimed or expected to be
65
Denbury Resources Inc.
Notes to Consolidated Financial Statements
claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company
may recognize the tax benefit from an uncertain tax position only if it is more likely than not
that the tax position will be sustained on examination by the taxing authorities, based on the
technical merits of the position. The tax benefits recognized in the financial statements from
such a position should be measured based on the largest benefit that has a greater than fifty
percent likelihood of being realized upon ultimate settlement. There was no material impact on our
financial statements as the result of our adoption of FIN 48 in 2007. See Note 7, Income Taxes,
for further information regarding our income taxes and our adoption of FIN 48.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amount of certain assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during each reporting period. Management believes its
estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to
differ materially from such estimates. Significant estimates underlying these financial statements include (i) the fair
value of financial derivative instruments, (ii) the estimated quantities of proved oil and natural
gas reserves used to compute depletion of oil and natural gas properties, the related present value
of estimated future net cash flows therefrom and ceiling test, (iii) accruals related to oil and
gas production and revenues, capital expenditures 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 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 United
States generally accepted accounting principles, and expands disclosures about fair value
measurements. SFAS No. 157 does not require any new fair value measurements, but provides guidance
on how to measure fair value by providing a fair value hierarchy used to classify the source of the
information. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007.
However, on February 12, 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date
of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring basis (at least
annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning
after November 15, 2008, and interim periods within those fiscal years for items within the scope
of this FSP. Effective for 2008, we will adopt SFAS No. 157 except as it applies to those
nonfinancial assets and nonfinancial liabilities as noted in FSP SFAS No. 157-2. We have not yet
determined the impact of the partial adoption of SFAS No. 157 will have on the Companys financial
condition or results of operations.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities. SFAS No. 159 permits entities to choose to measure many financial
instruments and certain other items at fair value, with the objective of improving financial
reporting by giving entities the opportunity to mitigate volatility in reported earnings caused by
measuring related assets and liabilities differently without having to apply complex hedge
accounting provisions. The provisions of SFAS No. 159 are effective for us beginning January 1,
2008. We have not yet determined what impact, if any, this pronouncement will have on our
financial condition or results of operations.
66
Denbury Resources Inc.
Notes to Consolidated Financial Statements
In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combinations.
SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures
in its financial statements the identifiable assets acquired, the liabilities assumed, any
noncontrolling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes
disclosure requirements to enable the evaluation of the nature and financial effects of the
business combination. This statement is effective for us beginning January 1, 2009. We have not yet
determined what impact, if any, this pronouncement will have on our
financial condition or results
of operations.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements an amendment of ARB No. 51. SFAS No. 160 establishes accounting and
reporting standards for ownership interests in subsidiaries held by parties other than the parent,
the amount of consolidated net income attributable to the parent and to the noncontrolling
interest, changes in a parents ownership interest, and the valuation of retained noncontrolling
equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure
requirements that clearly identify and distinguish between the interests of the parent and the
interests of the noncontrolling owners. This statement is effective for us beginning January 1,
2009. We have not yet determined what impact, if any, this pronouncement will have on our financial
condition or results of operations.
Note 2. Acquisitions and Divestitures
2007 Acquisition
On March 30, 2007, Denbury completed the acquisition of the Seabreeze Complex, which is
composed of two significant fields and four smaller fields in the general area of Houston, Texas.
At the time of acquisition these fields were producing approximately 400 BOE/d and had estimated
current conventional proved reserves of approximately 525 MBOE. Two of these fields are future
potential CO2 tertiary flood candidates. Tertiary flooding at these fields is not
expected to begin until 2010 or 2011, following completion of the proposed CO2 pipeline
from Louisiana to Hastings Field, near Houston, Texas.
The adjusted purchase price is approximately $39.4 million, after adjusting for interim net
cash flow between the effective date and closing date of the acquisition, and minor purchase price
adjustments. The purchase price 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 and
probable reserves acquired. Based on this analysis, $5.5 million was assigned to proved properties
and $33.9 million was 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.
2007 Divestiture
In October 2007, we entered into an agreement to sell our Louisiana natural gas assets to a
privately held company for approximately $180 million (before closing adjustments) plus any amounts
received from a net profits interest. In late December 2007, we closed on approximately 70% of
that sale with net proceeds of approximately $108.6 million (including estimated final purchase
price adjustments). The agreement has an effective date of August 1, 2007, and consequently
operating net revenue after August 1, net of capital expenditures, along with any other minor
closing items were adjustments to the purchase price. We closed on the remaining portion of the
sale in February 2008 (see Note 14, Subsequent Event). The potential net profits interest
relates to a well in the South Chauvin field and is only earned if operating income from that well
exceeds certain levels, which we believe could potentially increase the ultimate sales price by up
to 10%. The operating results of these sold properties are included in our financial statements
through the December 19, 2007 closing date. We did not record any gain or loss on the sale in
accordance with the full cost method of accounting.
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. The adjusted purchase price was approximately $250 million
(including the $25 million deposited as earnest money as of December 31, 2005), of which $124
million was assigned to unevaluated properties.
67
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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. Approximately $49 million of the purchase price was assigned to unevaluated
properties.
2006 Purchase Option Contract
During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc. that
gives us an option on September 1, 2008, or September 1, 2009, with an effective date of January 1
of the following year, 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 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, a
payment of $7.5 million in 2007, and are required to make an additional payment of $5 million in
2008. We have recorded these payments and the discounted present value of the required additional
payment, which total approximately $49 million, in Deposits on properties under option or
contract in our December 31, 2007, Consolidated Balance Sheet. Upon exercise of the option to
purchase 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).
Note 3. Related Party Transactions Genesis
Interest In and Transactions With Genesis
Denburys subsidiary, Genesis Energy, Inc. is the general partner and owns an aggregate 9.25%
interest in Genesis Energy, L.P. (Genesis), a publicly traded master limited partnership.
Genesis business is focused on the mid stream segment of the oil and gas industry in the Gulf
Coast area of the United States, and its activities include gathering, marketing and transportation
of crude oil and natural gas, refinery services, wholesale marketing of CO2,
and supply and logistic services.
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 investment in
Genesis is included in Other assets in our Consolidated Balance Sheets. Denbury received cash
distributions from Genesis of $1.7 million in 2007, $0.9 million in 2006, and $0.5 million in 2005.
We also received $0.1 million 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 our other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
On July 25, 2007, Genesis acquired several energy related businesses from the Davison family
of Ruston, Louisiana, for total consideration of approximately $623 million (net of cash acquired
at closing and subject to final purchase price adjustments). These businesses include a trucking
operation for petroleum products and other bulk commodities, terminal storage of refined petroleum
products, a refinery service operation which processes sour gas streams at several refining
operations, and a wholesale petroleum products marketing business. Approximately one-half of the
acquisition was funded by debt from Genesis bank credit facility and approximately one-half
through the issuance of Genesis common units to the seller. In conjunction with that acquisition,
our subsidiary, Genesis Energy, Inc., exercised its right to maintain its pro rata (7.4%) ownership
of common units, acquiring 1,074,882
additional common units for approximately $22.4 million, in addition to its capital
contribution of an additional $6.2 million, as general partner, to maintain its 2% general
partners capital interest.
68
Denbury Resources Inc.
Notes to Consolidated Financial Statements
In December 2007, Genesis issued additional common units in a public offering. Our
subsidiary, Genesis Energy, Inc., maintained its 2% general partners interest and acquired 734,732
common units in this offering for $20 million, which maintained its same ownership interest of
approximately 9.25%.
Our investment in Genesis of $60 million exceeded our percentage of net equity in the limited
partnership at the time of acquisition by approximately $15.7 million, which represents goodwill
and is not subject to amortization. The fair value of our investment in Genesis was in excess of
$84.9 million at December 31, 2007, based on quoted market values of Genesis publicly traded
limited partnership units.
Oil Sales and Transportation Services
We utilize Genesis trucking services and common carrier pipeline to transport certain of our
crude oil production to sales points where it is sold to third party purchasers. We expensed $6.0
million in 2007, $4.4 million in 2006, and $4.0 million in 2005 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
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, 2007 and
2006, we had $5.2 million and $5.9 million, respectively, of capital lease obligations with Genesis recorded as liabilities in our Consolidated
Balance Sheets, of which $0.7 million and $0.6 million, respectively, was current.
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, 2007 and 2006, $28.5 million
and $32.9 million, respectively, was recorded as deferred revenue of which $4.1 million was
included in current liabilities at both December 31, 2007 and 2006. We recognized deferred revenue
of $4.4 million, $4.2 million and $3.1 million for the years ended December 31, 2007, 2006 and
2005, 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 $0.18 per Mcf of CO2. For
these services, we recognized revenues of $5.2 million, $4.6 million and $3.5 million for the years
ended December 31, 2007, 2006 and 2005, respectively.
At December 31, 2007 and 2006, we had a net receivable from Genesis of $0.1 million, in both
periods 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.
69
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following table summarizes the changes in our asset retirement obligations for the years
ended December 31, 2007 and 2006.
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
Beginning asset retirement obligation |
|
$ |
41,107 |
|
|
$ |
27,088 |
|
Liabilities incurred and assumed during period |
|
|
6,530 |
|
|
|
10,159 |
|
Revisions in estimated cash flows |
|
|
1,165 |
|
|
|
2,791 |
|
Liabilities settled during period |
|
|
(1,302 |
) |
|
|
(1,320 |
) |
Accretion expense |
|
|
2,976 |
|
|
|
2,389 |
|
Sales |
|
|
(9,218 |
) |
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
41,258 |
|
|
$ |
41,107 |
|
|
|
|
|
|
|
|
At December 31, 2007 and 2006, $2.3 million and $1.8 million, respectively, of our asset
retirement obligation were classified in Accounts payable and accrued liabilities under current
liabilities in our Consolidated Balance Sheets. Liabilities sold in 2007 were associated with the
sale of our Louisiana natural gas properties in December 2007. The reversal of this asset
retirement obligation, which was assumed by the purchaser, was recorded as an adjustment to the
full cost pool with no gain or loss recognized in accordance with the full cost method of
accounting. Liabilities incurred and assumed during 2007 and 2006 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 $9.5 million at December 31, 2007, and
$7.6 million at December 31, 2006, and are included in Other assets in our Consolidated Balance
Sheets.
Note 5. Property and Equipment
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
2,682,932 |
|
|
$ |
2,226,942 |
|
Unevaluated properties |
|
|
366,518 |
|
|
|
293,657 |
|
|
|
|
|
|
|
|
Total |
|
|
3,049,450 |
|
|
|
2,520,599 |
|
Accumulated depletion and depreciation |
|
|
(1,081,909 |
) |
|
|
(907,911 |
) |
|
|
|
|
|
|
|
Net oil and natural gas properties |
|
|
1,967,541 |
|
|
|
1,612,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 properties and equipment |
|
|
269,335 |
|
|
|
205,235 |
|
Accumulated depletion and depreciation |
|
|
(34,676 |
) |
|
|
(23,492 |
) |
|
|
|
|
|
|
|
Net CO2 properties |
|
|
234,659 |
|
|
|
181,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 pipelines |
|
|
167,256 |
|
|
|
62,248 |
|
Accumulated depletion and depreciation |
|
|
(3,340 |
) |
|
|
(1,505 |
) |
|
|
|
|
|
|
|
Net CO2 pipelines |
|
|
163,916 |
|
|
|
60,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital leases |
|
|
7,985 |
|
|
|
7,985 |
|
Accumulated depletion and depreciation |
|
|
(2,482 |
) |
|
|
(1,631 |
) |
|
|
|
|
|
|
|
Net capital leases |
|
|
5,503 |
|
|
|
6,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
42,131 |
|
|
|
35,148 |
|
Accumulated depletion and depreciation |
|
|
(20,875 |
) |
|
|
(16,908 |
) |
|
|
|
|
|
|
|
Net other |
|
|
21,256 |
|
|
|
18,240 |
|
|
|
|
|
|
|
|
Net property and equipment |
|
$ |
2,392,875 |
|
|
$ |
1,879,768 |
|
|
|
|
|
|
|
|
70
Denbury Resources Inc.
Notes to Consolidated Financial Statements
At December 31, 2007 and 2006, we had $106.2 million and $7.9 million of costs, respectively,
included in CO2 Pipelines above related to construction in progress. These costs were
not being depreciated at December 31, 2007 or December 31, 2006. Depreciation will commence when
the pipelines are placed into service. The Company capitalizes interest on its CO2
pipelines during the construction period. Interest capitalized on these CO2 pipelines
was $2.1 million in 2007 and $0.3 million in 2006.
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. We
allocate the purchase price of oil and natural gas properties we acquire between proved and
unevaluated properties based on a risk adjusted analysis of the total estimated value of the
proved, probable and possible reserves acquired. The costs classified as unevaluated are
transferred to the full cost amortization base as the properties are developed, tested and
evaluated. A summary of the unevaluated properties excluded from oil and natural gas properties
being amortized at December 31, 2007 and 2006, and the year in which they were incurred follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, 2007 |
|
|
|
Costs Incurred During: |
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Total |
|
Property acquisition costs |
|
$ |
40,889 |
|
|
$ |
184,407 |
|
|
$ |
4,567 |
|
|
$ |
229,863 |
|
Exploration and development |
|
|
95,246 |
|
|
|
13,638 |
|
|
|
23 |
|
|
|
108,907 |
|
Capitalized interest |
|
|
17,501 |
|
|
|
10,247 |
|
|
|
|
|
|
|
27,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
153,636 |
|
|
$ |
208,292 |
|
|
$ |
4,590 |
|
|
$ |
366,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, 2006 |
|
|
|
Costs Incurred During: |
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
Prior |
|
|
Total |
|
Property acquisition costs |
|
$ |
193,554 |
|
|
$ |
11,906 |
|
|
$ |
1,655 |
|
|
$ |
207,115 |
|
Exploration and development |
|
|
70,624 |
|
|
|
1,657 |
|
|
|
3,202 |
|
|
|
75,483 |
|
Capitalized interest |
|
|
11,059 |
|
|
|
|
|
|
|
|
|
|
|
11,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
275,237 |
|
|
$ |
13,563 |
|
|
$ |
4,857 |
|
|
$ |
293,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs for 2007 are primarily for CO2 tertiary oil field
candidates acquired in the Seabreeze Complex acquisition, and 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. Exploration and development costs for 2007 are primarily associated with our
CO2 tertiary oil fields that are under development and did not have proved reserves at
December 31, 2007. 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.
71
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 6. Notes Payable and Long-Term Indebtedness
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
7.5% Senior Subordinated Notes due 2015 |
|
$ |
300,000 |
|
|
$ |
150,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
685 |
|
|
|
|
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(1,020 |
) |
|
|
(1,214 |
) |
Senior bank loan |
|
|
150,000 |
|
|
|
134,000 |
|
Capital lease obligations Genesis |
|
|
5,238 |
|
|
|
5,869 |
|
Capital lease obligations |
|
|
1,164 |
|
|
|
1,189 |
|
|
|
|
|
|
|
|
Total |
|
|
681,067 |
|
|
|
514,844 |
|
Less current obligations |
|
|
737 |
|
|
|
671 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
680,330 |
|
|
$ |
514,173 |
|
|
|
|
|
|
|
|
7.5% Senior Subordinated Notes due 2015
On April 3, 2007, we issued $150 million of Senior Subordinated Notes due 2015 as an
additional issuance under our existing indenture governing our December 2005 sale of $150 million
of 7.5% Senior Subordinated Notes due 2015 (2015 Notes). The notes, which carry a coupon rate of
7.5%, were sold at 100.5% of par, which equates to an effective yield to maturity of approximately
7.4%. Net proceeds from the sale were approximately $149.2 million. The net proceeds were used to
repay a portion of the outstanding borrowings under our bank credit facility.
The $150 million of 2015 Notes issued on December 21, 2005, 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).
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.
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
72
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement, the instrument
governing our senior bank loan. The amendment (i) increased the commitment amount that the banks
are committed to fund from $250 million to $350 million, (ii) reconfirmed the borrowing base of
$500 million, (iii) authorized the $150 million subordinated debt offering, and (iv) authorized us
to enter into a sale-leaseback type transaction for our CO2 pipelines, not to exceed
$300 million, with Genesis Energy, L.P. 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 ($350 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
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. We were in compliance with all
of our bank covenants as of December 31, 2007. 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, 2007, we had $150.0 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 6.2% at December 31, 2007. The next scheduled redetermination
of the borrowing base will be as of April 1, 2008, based on December 31, 2007 assets and proved
reserves.
Indebtedness Repayment Schedule
At December 31, 2007, our indebtedness, excluding the discount and premium on our senior
subordinated debt, is repayable over the next five years and thereafter as follows:
|
|
|
|
|
(In Thousands) |
|
|
|
|
2008 |
|
$ |
737 |
|
2009 |
|
|
1,031 |
|
2010 |
|
|
890 |
|
2011 |
|
|
150,978 |
|
2012 |
|
|
1,027 |
|
Thereafter |
|
|
526,739 |
|
|
|
|
|
Total indebtedness |
|
$ |
681,402 |
|
|
|
|
|
73
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 7. Income Taxes
Our income tax provision is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Current income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
21,948 |
|
|
$ |
16,033 |
|
|
$ |
26,659 |
|
State |
|
|
8,126 |
|
|
|
3,832 |
|
|
|
518 |
|
|
|
|
|
|
|
|
|
|
|
Total current income tax expense |
|
|
30,074 |
|
|
|
19,865 |
|
|
|
27,177 |
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
113,868 |
|
|
|
97,902 |
|
|
|
44,191 |
|
State |
|
|
(3,675 |
) |
|
|
9,350 |
|
|
|
10,202 |
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax expense |
|
|
110,193 |
|
|
|
107,252 |
|
|
|
54,393 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
140,267 |
|
|
$ |
127,117 |
|
|
$ |
81,570 |
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2007, we have no net operating loss carryforwards. As of December 31, 2007,
we have an estimated $37 million of enhanced oil recovery credits to carry forward related to our
tertiary operations. These credits will begin to expire in 2024.
Deferred income taxes relate to temporary differences based on tax laws and statutory rates in
effect at the December 31, 2007 and 2006, balance sheet dates. We believe that we will be able to
realize all of our deferred tax assets at December 31, 2007, and therefore have provided no
valuation allowance against our deferred tax assets.
At December 31, 2007 and 2006, our deferred tax assets and liabilities were as follows:
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Loss carryforwards state |
|
$ |
|
|
|
$ |
792 |
|
Tax credit carryover |
|
|
15,631 |
|
|
|
14,103 |
|
Enhanced oil recovery credit carryforwards |
|
|
37,257 |
|
|
|
41,856 |
|
Other |
|
|
19,950 |
|
|
|
7,791 |
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
72,838 |
|
|
|
64,542 |
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property and equipment |
|
|
(406,632 |
) |
|
|
(283,983 |
) |
Derivative hedging contracts |
|
|
(868 |
) |
|
|
(10,484 |
) |
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
(407,500 |
) |
|
|
(294,467 |
) |
|
|
|
|
|
|
|
Total net deferred tax liability |
|
$ |
(334,662 |
) |
|
$ |
(229,925 |
) |
|
|
|
|
|
|
|
74
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Our income tax provision varies from the amount that would result from applying the federal
statutory income tax rate to income before income taxes as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Income tax provision calculated using the
federal statutory income tax rate |
|
$ |
137,695 |
|
|
$ |
115,351 |
|
|
$ |
86,814 |
|
State income taxes |
|
|
11,536 |
|
|
|
13,183 |
|
|
|
9,922 |
|
Estimated statutory rate change |
|
|
(7,351 |
) |
|
|
|
|
|
|
|
|
Enhanced oil recovery credits |
|
|
|
|
|
|
|
|
|
|
(17,142 |
) |
Other |
|
|
(1,613 |
) |
|
|
(1,417 |
) |
|
|
1,976 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
140,267 |
|
|
$ |
127,117 |
|
|
$ |
81,570 |
|
|
|
|
|
|
|
|
|
|
|
Uncertain Tax Positions
We adopted the provisions of FIN 48 as of January 1, 2007. As a result of the implementation,
we determined that approximately $4.0 million of tax benefits previously recognized were considered
uncertain tax positions, as the timing of these deductions may not be sustained upon examination by
taxing authorities. As such, upon adoption of FIN 48, we recorded income taxes payable of $4.3
million (including $0.3 million in estimated interest) which was offset by a corresponding
reduction of the deferred tax liability of $4.1 million for the tax position that we believe will
ultimately be sustained. At January 1, 2007, the total amount of unrecognized tax benefits was
$4.5 million, exclusive of interest.
There was no cumulative adjustment made to the opening balance of retained earnings at January
1, 2007. Our uncertain tax positions relate primarily to timing differences, and we do not believe
any of such uncertain tax positions will materially impact our effective tax rate in future
periods. The amount of unrecognized tax benefits are expected to change over the next 12 months;
however, such change is not expected to have a significant impact on our results of operations or
financial position.
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in
many state jurisdictions. We are currently under examination by the Internal Revenue Service and
different state authorities. The Internal Revenue Service concluded its examination of our 2004
tax year during the third quarter of 2007 and began an examination of our 2005 tax year during the
fourth quarter of 2007. The state of Mississippi concluded its audit of tax years 1998 through
2000 during the third quarter of 2007 and is currently examining years 2001 through 2004. Neither
of the concluded examinations by the Internal Revenue Service and the state of Mississippi resulted
in any material assessments. As a result of the examinations concluded during the third quarter,
we decreased our total amount of unrecognized tax benefits from $4.5 million to $3.5 million.
These adjustments all related to temporary timing differences and did not have any impact on our
effective tax rate.
The following table summarizes the changes in our liability for unrecognized tax benefits for
the year ended December 31, 2007:
|
|
|
|
|
(In Thousands) |
|
|
|
|
Unrecognized tax benefit at January 1, 2007 |
|
$ |
4,462 |
|
Settlements |
|
|
(1,005 |
) |
|
|
|
|
Unrecognized tax benefit at December 31, 2007 |
|
$ |
3,457 |
|
|
|
|
|
We have not paid any significant interest or penalties associated with our income taxes, but
classify both interest expense and penalties as part of our income tax expense.
75
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 8. Stockholders Equity
Authorized
We are authorized to issue 600 million shares of common stock, par value $.001 per share, and
25 million shares of preferred stock, par value $.001 per share. The preferred shares may be
issued in one or more series with rights and conditions determined by the Board of Directors.
Stock Splits
Stockholders of Denbury approved two 2-for-1 stock splits (described below) during the
three-year period ended December 31, 2007. 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 splits, except for the share amounts included on our Consolidated Balance
Sheets and Consolidated Statements of Changes in Stockholders Equity, which reflect the actual
shares outstanding at each period end.
On November 19, 2007, 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 250,000,000 shares to 600,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common
stock for each share of common stock held at that time.
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.
Stock Issuance
On April 25, 2006, we sold 6,985,190 shares (3,492,595 on a pre-split basis) of common stock
in a public offering for $125 million (net to Denbury). 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 Repurchases
In 2006 and 2007, all of our share repurchases were from employees of Denbury that delivered
shares to the Company to satisfy their minimum tax withholding requirements as provided for under
Denburys stock compensation plans 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 7,400,000 shares of
common stock. As of December 31, 2007, there were 779,093 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 $2.2 million, $1.7 million and $1.2 million for the years ended December 31, 2007, 2006 and
2005, 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%. Effective January 1, 2008, Denbury increased its match
to 100% of an employees contribution, up to 6% of
76
Denbury Resources Inc.
Notes to Consolidated Financial Statements
compensation. Denburys match is vested immediately. During 2007, 2006 and 2005, Denburys
matching contributions were approximately $2.2 million, $1.6 million and $1.2 million,
respectively, to the 401(k) Plan.
Note 9. Stock Compensation Plans
Stock Incentive Plans
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. In May 2007, shareholders approved an increase to the number of shares that may be used
under our 2004 Plan, from 10.0 million to 14.0 million shares. 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 14.0 million shares of common stock are
authorized for issuance pursuant to the 2004 Plan, of which awards covering no more than 6.7
million shares may be issued in the form of restricted stock or performance vesting awards. At
December 31, 2007, a total of 5,168,519 shares were available for future issuance of awards, of
which only 1,580,684 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 termination of
employment, and 90 days or one year after permanent disability, depending on the plan, 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.
In 2004, Denbury began the use of restricted stock awards for its officers and independent
directors, 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 a portion thereof until certain requirements are met. With respect to the
restricted stock granted to officers of Denbury in 2004, 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 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.
In the second quarter of 2006, our Senior Vice President of Operations departed Denbury. 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, compensation cost of approximately $5.3
million was included in General and administrative expenses in the Consolidated Statement of
Operations for the year ended December 31, 2006. 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 $10.6
million and $17.2 million (including the $5.3 million resulting from modification of equity awards
discussed above) for the years ended December 31, 2007 and 2006, respectively. Part of this
expense, $1.5 million in each year, was included in Lease operating expenses for stock
compensation expense associated with our field employees, and the remaining amount recognized
in General and administrative expenses in the Consolidated Statements of
77
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Operations. The total income tax benefit recognized in the Consolidated Statements of
Operations for share-based compensation arrangements was $4.1 million and $4.6 million for the
years ended December 31, 2007 and 2006, respectively. Share-based compensation capitalized as part
of Oil and Natural Gas Properties was $1.6 million and $1.7 million for the years ended December
31, 2007 and 2006, respectively.
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 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.
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
Amounts in thousands, except per share amounts |
|
2005 |
|
|
|
|
Net income, as reported |
|
$ |
166,471 |
|
Add: stock-based compensation included in reported net
income, net of related tax effects |
|
|
2,765 |
|
Less: stock-based compensation expense applying fair value
based method, net of related tax effects |
|
|
8,425 |
|
|
|
|
|
Pro-forma net income |
|
$ |
160,811 |
|
|
|
|
|
|
|
|
|
|
Net income per common share |
|
|
|
|
As reported: |
|
|
|
|
Basic |
|
$ |
0.74 |
|
Diluted |
|
|
0.70 |
|
Pro forma: |
|
|
|
|
Basic |
|
$ |
0.72 |
|
Diluted |
|
|
0.68 |
|
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 years ended December 31, 2007 and 2006, was to
decrease net income by approximately $3.5 million and $6.4 million, respectively, 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,
2007 and 2006, was a decrease of $0.01 and $0.03, respectively, per both basic and diluted share.
Additionally, cash flow from operations was lower and cash flow from financing activities was
higher by approximately $19.2 million and $16.6 million for the years ended December 31, 2007 and
2006, respectively, 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 with 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
78
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
Weighted average fair value
of options granted |
|
$ |
6.90 |
|
|
$ |
6.32 |
|
|
$ |
3.47 |
|
Risk free interest rate |
|
|
4.54 |
% |
|
|
4.52 |
% |
|
|
3.80 |
% |
Expected life |
|
|
4.6 to 6.4 years |
|
|
|
4.9 to 6.9 years |
|
|
|
5 years |
|
Expected volatility |
|
|
38.3 |
% |
|
|
41.1 |
% |
|
|
42.6 |
% |
Dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of our stock option and SARs activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
Outstanding at beginning of year |
|
|
14,964,920 |
|
|
$ |
4.96 |
|
|
|
18,812,144 |
|
|
$ |
4.04 |
|
|
|
17,760,628 |
|
|
$ |
2.63 |
|
Granted |
|
|
873,649 |
|
|
|
16.34 |
|
|
|
1,034,310 |
|
|
|
13.58 |
|
|
|
4,966,508 |
|
|
|
8.15 |
|
Exercised |
|
|
(4,054,844 |
) |
|
|
3.44 |
|
|
|
(4,032,652 |
) |
|
|
2.77 |
|
|
|
(3,594,292 |
) |
|
|
2.69 |
|
Forfeited |
|
|
(320,440 |
) |
|
|
7.90 |
|
|
|
(848,882 |
) |
|
|
5.53 |
|
|
|
(320,700 |
) |
|
|
4.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
11,463,285 |
|
|
|
6.28 |
|
|
|
14,964,920 |
|
|
|
4.96 |
|
|
|
18,812,144 |
|
|
|
4.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year |
|
|
3,969,466 |
|
|
$ |
3.26 |
|
|
|
4,739,104 |
|
|
$ |
2.66 |
|
|
|
5,019,270 |
|
|
$ |
2.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of stock options and SARs exercised during the years ended December
31, 2007, 2006 and 2005, was approximately $60.3 million, $49.3 million and $24.8 million,
respectively. The total grant-date fair value of stock options and SARs vested during the years
ended December 31, 2007, 2006 and 2005, was approximately $6.8 million, $6.0 million and $3.4
million, respectively. The aggregate intrinsic value of stock options and SARs outstanding at
December 31, 2007, was approximately $269.1 million, and these options and SARs have a
weighted-average remaining contractual life of 6.1 years. The aggregate intrinsic value of options
exercisable at December 31, 2007, was approximately $105.1 million, and these stock options and
SARs have a weighted-average remaining contractual life of 4.2 years.
A summary of the status of our non-vested stock options and SARs as of December 31, 2007, and
the changes during the year ended December 31, 2007, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Grant-Date |
Non-Vested Stock Options and SARs |
|
Shares |
|
Fair Value |
Non-vested at January 1, 2007 |
|
|
10,225,816 |
|
|
$ |
2.71 |
|
Granted |
|
|
873,649 |
|
|
|
6.90 |
|
Vested |
|
|
(3,285,206 |
) |
|
|
2.06 |
|
Forfeited |
|
|
(320,440 |
) |
|
|
3.39 |
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2007 |
|
|
7,493,819 |
|
|
|
3.45 |
|
|
|
|
|
|
|
|
|
|
79
Denbury Resources Inc.
Notes to Consolidated Financial Statements
As of December 31, 2007, there was $9.8 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 years ended December 31,
2007, 2006 and 2005, was $13.1 million, $11.1 million and $9.7 million, respectively. The tax
benefit realized from the exercises of stock options and SARs totaled $18.7 million for 2007, $14.7
million for 2006, and $8.6 million for 2005.
Restricted Stock
As of December 31, 2007, we had issued 5,267,082 shares of restricted stock pursuant to the
2004 Plan and have recorded deferred compensation expense of $32.6 million, the fair market value
of the shares on the grant dates, net of estimated forfeitures of $1.2 million. This expense is
amortized over the applicable five-year, four-year, or retirement date vesting periods. As of
December 31, 2007, there was $14.2 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 2.5 years.
A summary of the status of our non-vested restricted stock grants and the changes during the
year ended December 31, 2007, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
Grant Date |
Non-Vested Restricted Stock Grants |
|
Shares |
|
Fair Value |
Non-vested at beginning of year |
|
|
2,887,922 |
|
|
$ |
5.90 |
|
Granted |
|
|
367,108 |
|
|
|
17.67 |
|
Vested |
|
|
(531,402 |
) |
|
|
6.02 |
|
Forfeited |
|
|
(21,180 |
) |
|
|
7.70 |
|
|
|
|
|
|
|
|
|
|
Non-vested at end of year |
|
|
2,702,448 |
|
|
|
7.46 |
|
|
|
|
|
|
|
|
|
|
The total vesting date fair value of restricted stock vested during the years ended December
31, 2007, 2006 and 2005 was $10.7 million, $17.4 million and $7.1 million, respectively.
Performance Equity Awards
On January 2, 2007, the Board of Directors awarded performance equity awards to the officers
of Denbury. These performance-based shares will vest on March 31, 2010, when the Companys various
financial and operational results for 2009 will have been finalized. The number of
performance-based shares that will be earned (and eligible to vest) during the performance period
will depend on the Companys level of success in achieving four specifically identified performance
targets. Generally, one-half of the shares earnable under the performance-based shares will be
earned for performance at the designated target levels (100% target vesting levels) or upon any
earlier change of control, and twice the number of shares will be earned if the higher maximum
target levels are met. If performance is below designated minimum levels for all performance
targets, no performance-based shares will be earned. Any portion of the performance shares that
are not earned by the end of the three year measurement period will be forfeited. In certain
change of control events, one-half (i.e. the target level amount) of the performance-based shares
would vest.
The number of performance-based shares (at the 100% targeted vesting level) granted
to the Companys executive officers is 107,918 shares. The actual number of shares to be delivered
pursuant to the performance-based shares could range from zero to 200% (215,836 shares) of the
stated 100% targeted amount. These performance-based share awards have a grant date fair value of
$13.90 per share. The Company recognizes compensation expense when it becomes probable that the
performance criteria specified in the plan will be achieved. We currently estimate that the 100%
targeted vesting level amount is probable. During the year ended December 31, 2007, we recorded
$0.4 million of expense in General and administrative expenses in our Consolidated Statement of
Operations for these performance-based awards.
80
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 10. Derivative Instruments and Hedging Activities
Oil and Gas Derivative Contracts
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 enter into natural gas contracts in late
2006 and September 2007 as we believed that there is more risk with regard to natural gas prices
and the fact that we planned to spend significantly more than our expected cash flow in the ensuing
year. In late 2006, we swapped 80% to 90% of our forecasted 2007 natural gas production at a
weighted average price of $7.96 per Mcf, and in September 2007, we swapped 70% to 80% of our 2008
natural gas production (after the sale of our Louisiana natural gas properties) at a weighted
average price of $7.91 per Mcf.
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, 2007, 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.
The following is a summary of Commodity derivative (expense) income, included in our
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Receipt (payment) on settlements of derivative contracts oil |
|
$ |
(9,833 |
) |
|
$ |
(5,302 |
) |
|
$ |
|
|
Receipt (payment) on settlements of derivative contracts gas |
|
|
30,313 |
|
|
|
|
|
|
|
(16,761 |
) |
Reclassification of accumulated other comprehensive income
balance |
|
|
|
|
|
|
|
|
|
|
(7,684 |
) |
Fair value adjustments to derivative contracts income (expense) |
|
|
(39,077 |
) |
|
|
25,130 |
|
|
|
(4,517 |
) |
|
|
|
|
|
|
|
|
|
|
Commodity derivative (expense) income |
|
$ |
(18,597 |
) |
|
$ |
19,828 |
|
|
$ |
(28,962 |
) |
|
|
|
|
|
|
|
|
|
|
81
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Oil and Natural Gas Derivative Contracts at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Contracts: |
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract Prices Per Bbl |
|
Asset (Liability) at |
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2008 Dec. 2008
|
|
|
2,000 |
|
|
$ |
57.34 |
|
|
$ |
(25,614 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Contracts: |
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract Prices Per MMBtu |
|
Asset (Liability) at |
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2008 Dec. 2008
|
|
|
20,000 |
|
|
|
$7.89 |
|
|
|
$594 |
|
Jan. 2008 Dec. 2008
|
|
|
20,000 |
|
|
|
7.91 |
|
|
|
737 |
|
Jan. 2008 Dec. 2008
|
|
|
20,000 |
|
|
|
7.94 |
|
|
|
952 |
|
At December 31, 2007, our derivative contracts were recorded at their fair value, which was a
net liability of $23.3 million.
Interest Rate Lock Derivative Contracts
In January 2007, we entered into interest rate lock contracts to remove our exposure to
possible interest rate fluctuations related to our commitment to the sale-leaseback financing of
certain equipment for CO2 recycling facilities at our tertiary oil fields. We are
applying hedge accounting to these contracts as provided under SFAS No. 133. For these instruments
designated as interest rate hedges, changes in fair value, to the extent the hedge is effective,
are recognized in other comprehensive income (loss) until the hedged item is recognized in
earnings. Amounts representing hedge ineffectiveness are recorded in earnings. Hedge
effectiveness is assessed quarterly based on the total change in the contracts fair value.
At December 31, 2007, the interest rate lock contracts had a fair value liability of
approximately $2.5 million that was recorded in our December 31, 2007, Consolidated Balance Sheet.
This $2.5 million liability includes approximately $1 million related to the contracts that
settled on December 31, 2007 (payment made to the counterparty in January 2008 in this amount),
which were designated as a hedge of our equipment leases which also closed on December 31, 2007.
We recorded $1.6 million (net of taxes of $1.0 million) in accumulated other comprehensive income
in our December 31, 2007, Consolidated Balance Sheet and the ineffectiveness totaling $0.1
million was recognized as income in our Consolidated Statement of Operations for the year ended
December 31, 2007.
Note 11. Commitments and Contingencies
We have operating leases for the rental of equipment, office space and vehicles that totaled
$143.8 million, $101.4 million and $37.2 million as of December 31, 2007, 2006 and 2005,
respectively. During the last five 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 $27.1 million during 2007, $41.1 million during 2006, and $17.3 million during
2005 with associated required monthly payments of $257,000 for the 2007 leases, $431,000 for the
2006 leases, and $223,000 for the 2005 leases. Leases entered into prior to 2006 have
seven-year terms, and the leases entered into in 2006 and 2007 have 10-year terms. Rental expense
for operating leases totaled $23.4 million in 2007, $14.1 million in 2006, and $8.2 million in
2005.
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.
82
Denbury Resources Inc.
Notes to Consolidated Financial Statements
At December 31, 2007, long-term commitments for these items require the following future
minimum rental payments:
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
Operating |
|
(In Thousands) |
|
Leases |
|
|
Leases |
|
2008 |
|
$ |
1,291 |
|
|
$ |
17,580 |
|
2009 |
|
|
1,529 |
|
|
|
17,128 |
|
2010 |
|
|
1,291 |
|
|
|
16,745 |
|
2011 |
|
|
1,291 |
|
|
|
16,185 |
|
2012 |
|
|
1,242 |
|
|
|
14,957 |
|
Thereafter |
|
|
2,094 |
|
|
|
61,173 |
|
|
|
|
|
|
|
|
Total minimum lease payments |
|
|
8,738 |
|
|
$ |
143,768 |
|
|
|
|
|
|
|
|
|
Less: Amount representing interest |
|
|
(2,336 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Present value of minimum lease payments |
|
$ |
6,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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 562 Bcf of
CO2 to these customers over the next 20 years, with a maximum volume required in any
given year of approximately 142 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, 2007 (approximately 5.6 Tcf before deducting
approximately 182.3 Bcf for the VPPs with Genesis), our current production capabilities and our
projected levels of CO2 usage for our own tertiary flooding program, we believe that we
can meet these contractual delivery obligations.
We currently have long-term commitments to purchase manufactured CO2 from three
proposed gasification plants, if these plants are built, two proposed by the developers of Faustina
Hydrogen Products LLC and another by Rentech Inc. If all three plants are built, these synthetic
sources are currently anticipated to provide us with an aggregate of 750 MMcf/d to 850 MMcf/d of
CO2 by 2013. The base price of CO2 per Mcf from these synthetic sources is
currently expected to be 1.5 to 2.0 times higher than our most recent all-in cost of CO2
from our natural sources (Jackson Dome) using current oil prices and assuming comparable
compression levels. These predicted synthetic CO2 prices are expected to be competitive
with the cost of our natural CO2 after adjusting for our share of potential carbon
emissions credits using estimated current prices of CO2 carbon credit futures. If all
three plants are built, the aggregate purchase obligation for this CO2 would be around
$190 million per year, assuming a $90 per barrel oil price and comparable compression levels,
before any potential savings from our share of carbon emissions credits. All of the contracts have
price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on
any of these plants, and their construction is contingent on the satisfactory resolution of various
issues, including financing; although based on their public representations, the initial Faustina
plant is currently scheduled to begin construction during 2008, with completion scheduled in late
2010 or 2011. We have invested a total of $8.6 million during 2006 and 2007 in preferred stock of
the Faustina plant. All of our investment may later be redeemed, with a return, or converted to
equity after construction financing for the project has been obtained, currently expected to occur
some time during 2008. We have recorded our investment in this debt security at cost and
classified it as held-to-maturity, since we have the intent and ability to hold it until it is
redeemed. The investment is included in Other assets in our Consolidated Balance Sheets.
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.
83
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 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, 2007, we had three significant
purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon
Ashland Petroleum LLC (43%), Hunt Crude Oil Supply Co. (19%) and Crosstex Energy Field Services
Inc. (16%). 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%).
Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Accounts payable |
|
$ |
59,076 |
|
|
$ |
57,637 |
|
Accrued exploration and development costs |
|
|
36,409 |
|
|
|
36,830 |
|
Accrued lease operating expense |
|
|
10,114 |
|
|
|
8,178 |
|
Hastings purchase option current |
|
|
4,709 |
|
|
|
6,794 |
|
Accrued compensation |
|
|
10,872 |
|
|
|
6,361 |
|
Accrued interest |
|
|
5,716 |
|
|
|
5,233 |
|
Taxes payable |
|
|
8,103 |
|
|
|
4,447 |
|
Asset retirement obligations current |
|
|
2,304 |
|
|
|
1,776 |
|
Other |
|
|
10,277 |
|
|
|
11,855 |
|
|
|
|
|
|
|
|
Total |
|
$ |
147,580 |
|
|
$ |
139,111 |
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Interest paid, net of amounts capitalized |
|
$ |
27,892 |
|
|
$ |
21,514 |
|
|
$ |
16,622 |
|
Interest capitalized |
|
|
20,385 |
|
|
|
11,333 |
|
|
|
1,649 |
|
Income taxes paid |
|
|
10,277 |
|
|
|
4,210 |
|
|
|
21,000 |
|
During 2007 and 2006, we capitalized $18.3 million and $11.0 million of interest,
respectively, on our significant unevaluated properties, primarily related to our CO2
tertiary floods without proved reserves. Additionally, we capitalized $2.1 million in 2007, $0.3
million in 2006, and $1.6 million in 2005 of interest relating to the construction of our
CO2 pipelines. We recorded a non-cash increase to property and debt in the amount of
$1.2 million in 2006, and $2.4 million in 2005, related to capital leases. In 2007, we issued
367,108 shares of restricted stock with a market value of $6.5 million on the date of grant. In
2006, we issued 259,974 shares of restricted stock with a market value of $3.8 million on the date
of grant. In 2005, we issued 40,000 shares of
84
Denbury Resources Inc.
Notes to Consolidated Financial Statements
restricted stock with a market value of $0.3 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 following two years. In 2006, we accrued the discounted present value of these required
additional payments and recorded this amount plus the upfront payment in Deposits on properties
under option or contract on our December 31, 2006, Consolidated Balance Sheet. The upfront
payment of $37.5 million in 2006 and the $7.5 million payment we made in 2007 are recorded on our
Consolidated Statements of Cash Flow under Investing Activities.
Fair Value of Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
|
|
|
|
December 31, |
|
|
|
|
|
|
2007 |
|
2006 |
|
|
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
|
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
7.5% Senior Subordinated Notes due 2013 |
|
$ |
223,980 |
|
|
$ |
227,250 |
|
|
$ |
223,786 |
|
|
$ |
227,250 |
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,685 |
|
|
|
303,000 |
|
|
|
150,000 |
|
|
|
152,250 |
|
Senior Bank Loan |
|
|
150,000 |
|
|
|
150,000 |
|
|
|
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.
85
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 13. Condensed Consolidating Financial Information
Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of
Denbury Resources Inc.s subsidiaries other than minor subsidiaries, except that with respect to
our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury
Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is
the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. 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 subsidiary guarantors:
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
430,518 |
|
|
$ |
237,273 |
|
|
$ |
7,263 |
|
|
$ |
(434,695 |
) |
|
$ |
240,359 |
|
Property and equipment |
|
|
|
|
|
|
2,392,865 |
|
|
|
10 |
|
|
|
|
|
|
|
2,392,875 |
|
Investment in subsidiaries (equity method) |
|
|
1,018,397 |
|
|
|
|
|
|
|
905,796 |
|
|
|
(1,924,193 |
) |
|
|
|
|
Other assets |
|
|
312,556 |
|
|
|
78,230 |
|
|
|
113,633 |
|
|
|
(366,576 |
) |
|
|
137,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,761,471 |
|
|
$ |
2,708,368 |
|
|
$ |
1,026,702 |
|
|
$ |
(2,725,464 |
) |
|
$ |
2,771,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
691,062 |
|
|
$ |
8,266 |
|
|
$ |
(434,695 |
) |
|
$ |
264,633 |
|
Long-term liabilities |
|
|
300,686 |
|
|
|
1,111,510 |
|
|
|
39 |
|
|
|
(310,169 |
) |
|
|
1,102,066 |
|
Stockholders equity |
|
|
1,460,785 |
|
|
|
905,796 |
|
|
|
1,018,397 |
|
|
|
(1,980,600 |
) |
|
|
1,404,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and stockholders equity |
|
$ |
1,761,471 |
|
|
$ |
2,708,368 |
|
|
$ |
1,026,702 |
|
|
$ |
(2,725,464 |
) |
|
$ |
2,771,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 |
|
|
|
|
|
|
|
698,380 |
|
|
|
(1,407,991 |
) |
|
|
|
|
Other assets |
|
|
154,076 |
|
|
|
64,391 |
|
|
|
10,794 |
|
|
|
(152,461 |
) |
|
|
76,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
Resources Inc. |
|
|
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
19,594 |
|
|
$ |
953,398 |
|
|
$ |
18,552 |
|
|
$ |
(19,594 |
) |
|
$ |
971,950 |
|
Expenses |
|
|
20,046 |
|
|
|
554,540 |
|
|
|
23,544 |
|
|
|
(19,594 |
) |
|
|
578,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(452 |
) |
|
|
398,858 |
|
|
|
(4,992 |
) |
|
|
|
|
|
|
393,414 |
|
Equity in net earnings of subsidiaries |
|
|
253,970 |
|
|
|
|
|
|
|
257,554 |
|
|
|
(511,524 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
253,518 |
|
|
|
398,858 |
|
|
|
252,562 |
|
|
|
(511,524 |
) |
|
|
393,414 |
|
Income tax provision (benefit) |
|
|
371 |
|
|
|
141,305 |
|
|
|
(1,409 |
) |
|
|
|
|
|
|
140,267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
253,147 |
|
|
$ |
257,553 |
|
|
$ |
253,971 |
|
|
$ |
(511,524 |
) |
|
$ |
253,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 |
|
|
$ |
796 |
|
|
$ |
(11,219 |
) |
|
$ |
732,312 |
|
Expenses |
|
|
11,581 |
|
|
|
400,657 |
|
|
|
1,719 |
|
|
|
(11,219 |
) |
|
|
402,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(362 |
) |
|
|
330,859 |
|
|
|
(923 |
) |
|
|
|
|
|
|
329,574 |
|
Equity in net earnings of subsidiaries |
|
|
202,749 |
|
|
|
|
|
|
|
203,669 |
|
|
|
(406,418 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
$ |
314 |
|
|
$ |
|
|
|
$ |
560,706 |
|
Expenses |
|
|
485 |
|
|
|
310,974 |
|
|
|
1,206 |
|
|
|
|
|
|
|
312,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(172 |
) |
|
|
249,105 |
|
|
|
(892 |
) |
|
|
|
|
|
|
248,041 |
|
Equity in net earnings of subsidiaries |
|
|
166,576 |
|
|
|
|
|
|
|
167,064 |
|
|
|
(333,640 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, 2007 |
|
|
|
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 |
|
$ |
33 |
|
|
$ |
570,098 |
|
|
$ |
83 |
|
|
$ |
|
|
|
$ |
570,214 |
|
Cash flow from investing activities |
|
|
(183,204 |
) |
|
|
(762,513 |
) |
|
|
|
|
|
|
183,204 |
|
|
|
(762,513 |
) |
Cash flow from financing activities |
|
|
183,204 |
|
|
|
198,533 |
|
|
|
|
|
|
|
(183,204 |
) |
|
|
198,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
33 |
|
|
|
6,118 |
|
|
|
83 |
|
|
|
|
|
|
|
6,234 |
|
Cash, beginning of period |
|
|
1 |
|
|
|
52,225 |
|
|
|
1,647 |
|
|
|
|
|
|
|
53,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
34 |
|
|
$ |
58,343 |
|
|
$ |
1,730 |
|
|
$ |
|
|
|
$ |
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 14. Subsequent Event
On February 20, 2008, we closed on the remaining portion of our Louisiana natural gas asset
sale. We received net proceeds of approximately $48.9 million related to this portion of the asset
sale (see Note 2, Acquisition and Divestitures 2007 Divestiture).
88
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 15. Supplemental Oil and Natural Gas Disclosures (unaudited)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural gas property
acquisition, exploration and development activities. Property acquisition costs are those costs
incurred to purchase, lease, or otherwise acquire property, including both undeveloped leasehold
and the purchase of reserves in place.
Exploration costs include costs of identifying areas that may warrant examination and
examining specific areas that are considered to have prospects containing oil and natural gas
reserves, including costs of drilling exploratory wells, geological and geophysical costs and
carrying costs on undeveloped properties. Development costs are incurred to obtain access to
proved reserves, including the cost of drilling development wells, and to provide facilities for
extracting, treating, gathering and storing the oil and natural gas, and the cost of improved
recovery systems.
The Company capitalizes interest on unevaluated oil and gas properties that have on-going
development activities. Included in the cost incurred below are capitalized interest of $18.3
million in 2007 and $11.0 million in 2006. Costs incurred also include new asset retirement
obligations established, as well as changes to asset retirement obligations resulting from
revisions in cost estimates or abandonment dates. Asset retirement obligations included in the
table below were $7.5 million in 2007, $12.8 million in 2006 and $4.6 million in 2005 (see Note 4,
Asset Retirement Obligations).
Costs incurred in oil and natural gas activities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Property acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
15,531 |
|
|
$ |
147,655 |
|
|
$ |
64,791 |
|
Unevaluated |
|
|
60,079 |
|
|
|
205,506 |
|
|
|
32,874 |
|
Exploration |
|
|
42,726 |
|
|
|
43,564 |
|
|
|
45,652 |
|
Development |
|
|
553,315 |
|
|
|
443,866 |
|
|
|
240,478 |
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred (1) |
|
$ |
671,651 |
|
|
$ |
840,591 |
|
|
$ |
383,795 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Capitalized general and administrative costs that directly relate to exploration and
development activities were $10.3 million, $7.6 million and $5.1 million for the years ended
December 31, 2007, 2006 and 2005, 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, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Oil, natural gas and related product sales |
|
$ |
952,788 |
|
|
$ |
716,557 |
|
|
$ |
549,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs |
|
|
230,932 |
|
|
|
167,271 |
|
|
|
108,550 |
|
Production taxes and marketing expenses |
|
|
49,091 |
|
|
|
36,351 |
|
|
|
27,582 |
|
Depletion, depreciation and amortization |
|
|
177,333 |
|
|
|
135,269 |
|
|
|
90,631 |
|
CO2 depletion, depreciation and amortization (1) |
|
|
9,403 |
|
|
|
6,281 |
|
|
|
3,894 |
|
Commodity derivative expense (income) |
|
|
18,597 |
|
|
|
(19,828 |
) |
|
|
28,962 |
|
|
|
|
|
|
|
|
|
|
|
Net operating income |
|
|
467,432 |
|
|
|
391,213 |
|
|
|
289,436 |
|
Income tax provision |
|
|
177,624 |
|
|
|
151,008 |
|
|
|
95,224 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and natural gas producing activities |
|
$ |
289,808 |
|
|
$ |
240,205 |
|
|
$ |
194,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization per BOE |
|
$ |
11.60 |
|
|
$ |
10.54 |
|
|
$ |
8.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents an allocation of the depletion, depreciation and amortization of our CO2
properties associated with our tertiary oil producing activities. |
89
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates for all years presented were prepared by
DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. The reserves
were prepared in accordance
with guidelines established by the Securities and Exchange Commission and, accordingly, were
based on existing economic and operating conditions. Oil and natural gas prices in effect as of
the reserve report date were used without any escalation. (See Standardized Measure of Discounted
Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below
for a discussion of the effect of the different prices on reserve quantities and values.)
Operating costs, production and ad valorem taxes and future development costs were based on current
costs with no escalation.
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, |
|
|
2007 |
|
2006 |
|
2005 |
|
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
(MMcf) |
Balance at beginning of year |
|
|
126,185 |
|
|
|
288,826 |
|
|
|
106,173 |
|
|
|
278,367 |
|
|
|
101,287 |
|
|
|
168,484 |
|
Revisions of previous estimates |
|
|
(1,601 |
) |
|
|
1,478 |
|
|
|
4,351 |
|
|
|
(22,279 |
) |
|
|
(3,613 |
) |
|
|
(12,047 |
) |
Revisions due to price changes |
|
|
1,538 |
|
|
|
(355 |
) |
|
|
(2 |
) |
|
|
(3,116 |
) |
|
|
872 |
|
|
|
1,268 |
|
Extensions and discoveries |
|
|
6,887 |
|
|
|
131,451 |
|
|
|
4,587 |
|
|
|
65,582 |
|
|
|
1,214 |
|
|
|
117,512 |
|
Improved recovery (1) |
|
|
12,376 |
|
|
|
|
|
|
|
5,044 |
|
|
|
|
|
|
|
13,276 |
|
|
|
|
|
Production |
|
|
(10,193 |
) |
|
|
(35,456 |
) |
|
|
(8,372 |
) |
|
|
(30,322 |
) |
|
|
(7,305 |
) |
|
|
(21,424 |
) |
Acquisition of minerals in place |
|
|
405 |
|
|
|
1,935 |
|
|
|
14,424 |
|
|
|
643 |
|
|
|
442 |
|
|
|
24,574 |
|
Sales of minerals in place |
|
|
(619 |
) |
|
|
(29,271 |
) |
|
|
(20 |
) |
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
|
134,978 |
|
|
|
358,608 |
|
|
|
126,185 |
|
|
|
288,826 |
|
|
|
106,173 |
|
|
|
278,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year |
|
|
83,703 |
|
|
|
176,648 |
|
|
|
59,640 |
|
|
|
151,681 |
|
|
|
55,998 |
|
|
|
94,573 |
|
Balance at end of year |
|
|
97,005 |
|
|
|
226,271 |
|
|
|
83,703 |
|
|
|
176,648 |
|
|
|
59,640 |
|
|
|
151,681 |
|
|
|
|
(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 cause 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
90
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, |
|
|
2007 |
|
2006 |
|
2005 |
Oil (NYMEX) |
|
$ |
95.98 |
|
|
$ |
61.05 |
|
|
$ |
61.04 |
|
Natural Gas (Henry Hub) |
|
|
6.80 |
|
|
|
5.63 |
|
|
|
10.08 |
|
Future cash inflows were reduced by estimated future production, development and abandonment
costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed
by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the
associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards
were also considered in the future income tax calculation. Future net cash inflows after income
taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
|
|
|
|
|
|
|
|
|
|
|
|
|
(In Thousands) |
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Future cash inflows |
|
$ |
14,082,865 |
|
|
$ |
8,185,682 |
|
|
$ |
8,197,957 |
|
Future production costs |
|
|
(3,687,197 |
) |
|
|
(2,697,206 |
) |
|
|
(2,069,015 |
) |
Future development costs |
|
|
(605,638 |
) |
|
|
(565,488 |
) |
|
|
(525,877 |
) |
Future income taxes |
|
|
(3,283,702 |
) |
|
|
(1,519,179 |
) |
|
|
(1,944,430 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
6,506,328 |
|
|
|
3,403,809 |
|
|
|
3,658,635 |
|
10% annual discount for estimated timing of cash flows |
|
|
(2,966,711 |
) |
|
|
(1,566,468 |
) |
|
|
(1,574,186 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
3,539,617 |
|
|
$ |
1,837,341 |
|
|
$ |
2,084,449 |
|
|
|
|
|
|
|
|
|
|
|
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, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Beginning of year |
|
$ |
1,837,341 |
|
|
$ |
2,084,449 |
|
|
$ |
1,129,196 |
|
Sales of oil and natural gas produced, net of production costs |
|
|
(672,765 |
) |
|
|
(512,935 |
) |
|
|
(412,923 |
) |
Net changes in sales prices |
|
|
2,346,008 |
|
|
|
(552,772 |
) |
|
|
1,261,231 |
|
Extensions and discoveries, less applicable future development
and production costs |
|
|
344,615 |
|
|
|
124,787 |
|
|
|
461,936 |
|
Improved recovery (1) |
|
|
513,840 |
|
|
|
117,342 |
|
|
|
204,116 |
|
Previously estimated development costs incurred |
|
|
192,696 |
|
|
|
124,207 |
|
|
|
110,424 |
|
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production |
|
|
(214,994 |
) |
|
|
(324,608 |
) |
|
|
(261,730 |
) |
Accretion of discount |
|
|
269,520 |
|
|
|
321,548 |
|
|
|
164,329 |
|
Acquisition of minerals in place |
|
|
32,212 |
|
|
|
182,374 |
|
|
|
44,807 |
|
Sales of minerals in place |
|
|
(121,209 |
) |
|
|
(222 |
) |
|
|
|
|
Net change in income taxes |
|
|
(987,647 |
) |
|
|
273,171 |
|
|
|
(616,937 |
) |
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
3,539,617 |
|
|
$ |
1,837,341 |
|
|
$ |
2,084,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Improved recovery additions result from the application of secondary recovery methods such as
water flooding or tertiary recovery methods such as CO2 flooding. |
91
Denbury Resources Inc.
Notes to Consolidated Financial Statements
CO2 Reserves
Based on engineering reports prepared by DeGolyer and MacNaughton, our CO2
reserves, on a 100% working interest basis, were estimated at approximately 5.6 Tcf at
December 31, 2007 (includes 182.3 Bcf of reserves dedicated to three volumetric production payments
with Genesis), 5.5 Tcf at December 31, 2006 (includes 210.5 Bcf of reserves dedicated to three
volumetric production payments with Genesis), and 4.6 Tcf at December 31, 2005 (includes 237.1 Bcf
of reserves dedicated to three 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.
Note 16. Unaudited Quarterly Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Thousands, Except Per Share Amounts |
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
174,155 |
|
|
$ |
222,510 |
|
|
$ |
253,509 |
|
|
$ |
321,776 |
|
Expenses |
|
|
146,907 |
|
|
|
120,033 |
|
|
|
142,296 |
|
|
|
169,300 |
|
Net income |
|
|
16,616 |
|
|
|
62,567 |
|
|
|
67,988 |
|
|
|
105,976 |
|
Net income per share (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
0.07 |
|
|
|
0.26 |
|
|
|
0.28 |
|
|
|
0.44 |
|
Diluted |
|
|
0.07 |
|
|
|
0.25 |
|
|
|
0.27 |
|
|
|
0.42 |
|
Cash flow from operations |
|
|
93,345 |
|
|
|
102,252 |
|
|
|
169,214 |
|
|
|
205,403 |
|
Cash flow used for investing activities (2) |
|
|
(215,615 |
) |
|
|
(205,404 |
) |
|
|
(231,045 |
) |
|
|
(110,449 |
) |
Cash flow provided by (used for) financing activities (3) |
|
|
103,404 |
|
|
|
100,722 |
|
|
|
68,668 |
|
|
|
(74,261 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
179,146 |
|
|
$ |
193,566 |
|
|
$ |
192,201 |
|
|
$ |
167,399 |
|
Expenses |
|
|
107,398 |
|
|
|
119,978 |
|
|
|
97,237 |
|
|
|
78,125 |
|
Net income |
|
|
43,778 |
|
|
|
44,262 |
|
|
|
59,294 |
|
|
|
55,123 |
|
Net income per share (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
0.19 |
|
|
|
0.19 |
|
|
|
0.25 |
|
|
|
0.23 |
|
Diluted |
|
|
0.18 |
|
|
|
0.18 |
|
|
|
0.24 |
|
|
|
0.22 |
|
Cash flow from operations |
|
|
102,512 |
|
|
|
106,417 |
|
|
|
135,365 |
|
|
|
117,516 |
|
Cash flow used for investing activities (4) |
|
|
(347,684 |
) |
|
|
(205,495 |
) |
|
|
(143,349 |
) |
|
|
(160,099 |
) |
Cash flow provided by financing activities (5) |
|
|
110,067 |
|
|
|
99,906 |
|
|
|
6,096 |
|
|
|
67,532 |
|
|
|
|
(1) |
|
Per share amounts for all periods reflect the impact of a 2-for-1 split on December 5, 2007. |
|
(2) |
|
In December 2007, we received cash proceeds of $115.4 million for the sale of our Louisiana
natural gas assets. (See Note 2, Acquisitions and Divestitures.) |
|
(3) |
|
In the second quarter of 2007, we issued $150 million of 7.5% Senior Subordinated Notes due
2015 (See Note 6, Notes Payable and Long-Term Indebtedness.) Also during 2007, we had
net borrowings of $96 million in the first quarter and $60 million in the third quarter,
and net repayments of $60 million in the second quarter and $80 million in the fourth
quarter, all under our senior bank loan. |
|
(4) |
|
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.) |
|
(5) |
|
In April 2006, 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. |
92
Denbury Resources Inc.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our President
and Chief Executive Officer and our Chief Financial Officer, we evaluated the effectiveness of our
disclosure controls and procedures as of the end of the period covered by this report. Based upon
that evaluation, our President and Chief Executive Officer and our Chief Financial Officer
concluded that our disclosure controls and procedures were effective to provide reasonable
assurance that we record, process, summarize and report the information we must disclose in reports
that we file or submit under the Securities Exchange Act of 1934, as amended, within the time
periods specified in the SECs rules and forms.
Evaluation of Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of our management, including our President
and Chief Executive Officer and our Chief Financial Officer, we have determined that, during the
fourth quarter of fiscal 2007, there were no changes in our internal control over financial
reporting that have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rules 13a-15(f) and 15(d)-15(f) of the Securities Exchange Act of
1934, as amended. Under the supervision and with the participation of our management, including our
President and Chief Executive Officer and our Chief Financial Officer, we assessed the
effectiveness of our internal control over financial reporting as of the end of the period covered
by this report based on the framework in Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our
President and Chief Executive Officer and our Chief Financial Officer concluded that our internal
control over financial reporting was effective to provide reasonable assurance regarding the
reliability of our financial reporting and the preparation of our financial statements for external
purposes in accordance with U.S. generally accepted accounting principles.
The effectiveness of the Companys internal control over financial reporting as of December
31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which appears herein.
Important Considerations
The effectiveness of our disclosure controls and procedures and our internal control over
financial reporting is subject to various inherent limitations, including cost limitations,
judgments used in decision making, assumptions about the likelihood of future events, the soundness
of our systems, the possibility of human error, and the risk of fraud. Moreover, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions and the risk that the degree of compliance with
policies or procedures may deteriorate over time. Because of these limitations, there can be no
assurance that any system of disclosure controls and procedures or internal control over financial
reporting will be successful in preventing all errors or fraud or in making all material
information known in a timely manner to the appropriate levels of management.
Item 9B. Other Information
None.
93
Denbury Resources Inc.
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, 2008, (Annual
Meeting) and is incorporated herein by reference.
Code of Ethics
We have adopted a Code of Ethics for Senior Financial Officers and the 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.
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 |
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)*
|
|
|
|
Certificate of Amendment of Restated Certificate of Incorporation of Denbury Resources Inc.
filed
with the Delaware Secretary of State on November 21, 2007. |
|
|
|
|
|
3(d)
|
|
|
|
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). |
94
Denbury Resources Inc.
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Exhibit |
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). |
|
|
|
|
|
4(d)
|
|
|
|
First Supplemental Indenture for 7.5% Senior Subordinated Notes due 2015, dated April 3, 2007,
between Denbury Resources Inc., as issuer, and The Bank of New York Trust Company, N.A., as
Trustee (incorporated by reference as Exhibit 4.1 of our Form 8-K filed April 3, 2007). |
|
|
|
|
|
10(a)
|
|
|
|
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(b)
|
|
|
|
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, as
Parent Guarantor, Bank One, N.A. as Administrative Agent, and certain other financial
institutions dated as of December 22, 2006 (incorporated by reference as Exhibit 10(c) of our
Form 10-K for the year ended December 31, 2007). |
|
|
|
|
|
10(c)
|
|
|
|
First Amendment to 6th Amended and Restated Credit Agreement among Denbury Onshore,
LLC, as Borrower, Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank, N.A., as
Administrative Agent and certain other financial institutions effective March 31, 2007
(incorporated by reference as Exhibit 10 in our Form 10-Q for the quarter ended March 31,
2007). |
|
|
|
|
|
10(d)
|
|
|
|
Amendment for Increased Commitment from $250 million to $350 million to Sixth Amended and
Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, and JPMorgan Chase Bank,
N.A., as Administrative Agent, and certain other financial institutions dated as of March 31,
2007 (incorporated by reference as Exhibit 10 in our Form 10-Q for the quarter ended March 31,
2007). |
|
|
|
|
|
10(e)
|
|
**
|
|
Denbury Resources Inc. Amended and Restated Stock Option Plan as of December 5, 2007
(incorporated by reference as Exhibit 99.2 of our Form 8-K, filed December 11, 2007). |
|
|
|
|
|
10(f)
|
|
**
|
|
Denbury Resources Inc. Stock Purchase Plan, as amended and restated December 5, 2007
(incorporated by reference as Exhibit 99.4 of our Form 8-K, filed December 11, 2007). |
|
|
|
|
|
10(g)
|
|
**
|
|
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(h)
|
|
**
|
|
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(i)
|
|
**
|
|
Denbury Resources Severance Protection Plan, as amended and restated effective December 5,
2007 (incorporated by reference as Exhibit 99.3 of our Form 8-K, filed December 11, 2007). |
|
|
|
|
|
10(j)
|
|
**
|
|
Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated
effective December 5, 2007 (incorporated by reference as Exhibit 99.1 of our Form 8-K, filed
December 11, 2007). |
|
|
|
|
|
10(k)
|
|
**
|
|
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(l)
|
|
**
|
|
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(m)
|
|
**
|
|
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(n)
|
|
**
|
|
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). |
95
Denbury Resources Inc.
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Exhibit |
10(o)
|
|
**
|
|
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 Form 10-K for the
year ended December 31, 2004). |
|
|
|
|
|
10(p)
|
|
**
|
|
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(q)
|
|
**
|
|
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(r)
|
|
**
|
|
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(s)
|
|
**
|
|
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). |
|
|
|
|
|
10(t)
|
|
**
|
|
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(u)
|
|
**
|
|
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(v)
|
|
**
|
|
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(w)
|
|
**
|
|
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. (incorporated by reference as
Exhibit 10(y) of our Form 10-K for the year ended December 31, 2007). |
|
|
|
|
|
10(x)
|
|
**
|
|
2007 form of performance share awards to 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, 2007). |
|
|
|
|
|
10(y)
|
|
**
|
|
2007 form of restricted stock award to directors that cliff vests after three years pursuant
to 2004 Omnibus Stock and Incentive Plan (incorporated by reference as Exhibit 10(cc) of our
Form 10-K for the year ended December 31, 2007). |
|
|
|
|
|
10(z)*
|
|
**
|
|
2007 form of restricted stock award to new directors that vest 20% per annum. |
|
|
|
|
|
10(aa)
|
|
**
|
|
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(bb)
|
|
**
|
|
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). |
|
|
|
|
|
21*
|
|
|
|
List of subsidiaries of Denbury Resources Inc. |
|
|
|
|
|
23(a)*
|
|
|
|
Consent of PricewaterhouseCoopers LLP. |
|
|
|
|
|
23(b)*
|
|
|
|
Consent of DeGolyer and MacNaughton. |
|
|
|
|
|
31(a)*
|
|
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
31(b)*
|
|
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
32*
|
|
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |
96
Denbury Resources Inc.
|
|
|
|
|
Exhibit |
|
|
|
|
No. |
|
|
|
Exhibit |
99*
|
|
|
|
The summary of DeGolyer and MacNaughtons Report as of December 31, 2007, on oil and gas
reserves (SEC Case) dated February 11, 2008. |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Compensation arrangements. |
97
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
Denbury Resources Inc. has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
|
|
|
|
|
DENBURY RESOURCES INC. |
|
|
|
February 28, 2008
|
|
/s/ Phil Rykhoek |
|
|
|
|
|
Phil Rykhoek |
|
|
Sr. Vice President and Chief Financial Officer |
|
|
|
February 28, 2008
|
|
/s/ Mark C. Allen |
|
|
|
|
|
Mark C. Allen |
|
|
Vice President and Chief Accounting Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of Denbury Resources Inc. and in the capacities and
on the dates indicated.
|
|
|
February 28, 2008
|
|
/s/ Gareth Roberts |
|
|
|
|
|
Gareth Roberts |
|
|
Director, President and Chief Executive Officer |
|
|
(Principal Executive Officer) |
|
|
|
February 28, 2008
|
|
/s/ Phil Rykhoek |
|
|
|
|
|
Phil Rykhoek |
|
|
Sr. Vice President and Chief Financial Officer |
|
|
(Principal Financial Officer) |
|
|
|
February 28, 2008
|
|
/s/ Mark C. Allen |
|
|
|
|
|
Mark C. Allen |
|
|
Vice President and Chief Accounting Officer |
|
|
(Principal Accounting Officer) |
|
|
|
February 28, 2008
|
|
/s/ Ron Greene |
|
|
|
|
|
Ron Greene |
|
|
Director |
|
|
|
February 28, 2008
|
|
/s/ David I. Heather |
|
|
|
|
|
David I. Heather |
|
|
Director |
|
|
|
February 28, 2008
|
|
/s/ Randy Stein |
|
|
|
|
|
Randy Stein |
|
|
Director |
98
|
|
|
February 28, 2008
|
|
/s/ Wieland Wettstein |
|
|
|
|
|
Wieland Wettstein |
|
|
Director |
|
|
|
February 28, 2008
|
|
/s/ Greg McMichael |
|
|
|
|
|
Greg McMichael |
|
|
Director |
|
|
|
February 28, 2008
|
|
/s/ Michael Beatty |
|
|
|
|
|
Michael Beatty |
|
|
Director |
|
|
|
February 28, 2008
|
|
/s/ Michael Decker |
|
|
|
|
|
Michael Decker |
|
|
Director |