e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2008 FORM 10-K
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(Mark One) |
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Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 |
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For the fiscal year ended December 31, 2008 |
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OR |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from _________ to________
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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Delaware
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20-0467835 |
(State or other jurisdiction
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(I.R.S. Employer |
of incorporation or organization)
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Identification No.) |
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5100 Tennyson Parkway, |
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Suite 1200, Plano, TX
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75024 |
(Address of principal executive offices)
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(Zip Code) |
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Registrants telephone number, including area code:
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(972) 673-2000 |
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class:
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Name of Each Exchange on Which Registered: |
Common Stock $.001 Par Value
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New York Stock Exchange |
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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 No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a small reporting company. See definition of large accelerated filer,
accelerated filer, and small reporting company in Rule 12b-2 of the Exchange Act.
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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 |
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 $6,251,312,368.
The number of shares outstanding of the registrants Common Stock as of January 31, 2009, was
248,411,326.
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 13, 2009.
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1. |
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Part III, Items 10, 11, 12, 13, 14 |
Denbury Resources Inc.
2008 Annual Report on Form 10-K
Table of Contents
2
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. |
Bbls/d
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Barrels of oil produced per day. |
Bcf
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One billion cubic feet of natural gas or CO2. |
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. |
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. |
BOE/d
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BOEs produced per day. |
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. |
CO2
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Carbon dioxide. |
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. |
MBbls
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One thousand barrels of crude oil or other liquid hydrocarbons. |
MBOE
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One thousand BOEs. |
Mbtu
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One thousand Btus. |
Mcf
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One thousand cubic feet of natural gas or CO2. |
Mcf/d
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One thousand cubic feet of natural gas or CO2 produced per day. |
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. |
Mcfe/d
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Mcfes produced per day. |
MMBbls
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One million barrels of crude oil or other liquid hydrocarbons. |
MMBOE
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One million BOEs. |
MMBtu
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One million Btus. |
MMcf
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One million cubic feet of natural gas or CO2. |
MMcf/d
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One million cubic feet of natural gas or CO2 per day. |
MMcfe
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One thousand Mcfe. |
MMcfe/d
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MMcfes produced per day. |
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 21. |
Proved Developed
Reserves*
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Reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods. |
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. |
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. |
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. For the complete definition see: http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&
sid=20c66c74f60c4bb8392bcf9ad6fccea3&rgn=div5&view=text&
node=17:2.0.1.1.8&idno=17#17:2.0.1.1.8.0.21.43. |
3
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, 2008, we had
797 employees, 493 of whom were employed in field operations or at the field offices. Our employee
count does not include the approximately 610 employees of Genesis Energy, LLC as of December 31,
2008, 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 where we have a competitive advantage as a
result of our CO2 reserves and expanding infrastructure, or where we
believe we can ultimately obtain it; |
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acquire properties where we believe additional value can be created through
tertiary recovery operations and a combination of other exploitation, development,
exploration and marketing techniques; |
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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
controlling cost; and |
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maintain a highly competitive team of experienced and incentivized personnel. |
4
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
Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999,
we have gradually increased our emphasis on these types of operations. During this time, we have
learned a considerable amount about tertiary operations and working with carbon dioxide. Our
tertiary operations have grown to the point that approximately 50% of our December 31, 2008 proved
reserves are proved tertiary oil reserves, almost 50% of our forecasted 2009 production is expected
to come from tertiary oil operations (on a BOE basis), and almost all of our 2009 capital
expenditures are related to our current or future tertiary 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
(we estimate our economic per barrel dollar cost on these projects at current oil prices is in the
range of the mid-twenties, 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. In addition, we are pursuing
anthropogenic (man-made) sources of CO2 to use in our tertiary operations, which we
believe will not only help us recover additional oil, but will provide an economical way to
sequester CO2. We have acquired several old oil fields in our areas of operations with
potential for tertiary recovery and plan to acquire additional fields, and we are continuing to
expand our CO2 pipeline infrastructure to transport CO2.
During 2008, we added 63.4 MMBbls of tertiary-related proved oil reserves, primarily initial
proven tertiary oil reserves at Heidelberg Field (Phase II), Tinsley Field (Phase III) and Lockhart
Crossing Field (Phase I) (see discussion of the individual fields below), increasing our proved
tertiary oil reserves from 69.5 MMBbls at December 31, 2007 to 125.8 MMBbls as of December 31,
2008. In order to recognize proved tertiary oil reserves, we must either have an oil production
response to the CO2 injections or the field must be analogous to an existing tertiary
flood. The magnitude of proved reserves that we can book in any given year will depend on our
progress with new floods and the timing of the associated production response.
We believe that 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 5% 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 proved 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, followed
by our acquisition of Jackson Dome CO2 reserves and NEJD 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
enhanced oil play.
5
Tertiary Recovery Phases. We categorize our tertiary operations by labeling operating areas
or groups of fields as phases. Phase I includes several fields along our 183-mile NEJD CO2 Pipeline
that runs through southwest Mississippi and into Louisiana. The most significant fields in this
area are Little Creek, Mallalieu, McComb, and Brookhaven Fields, all fields which have been
producing oil for some time, and one of our newest enhanced oil fields, Lockhart Crossing Field.
We saw our first tertiary oil production from Lockhart Crossing Field, located in South Louisiana,
during 2008. Lockhart Crossing, although a relatively small field, is the first of three fields we
plan to CO2 flood in Louisiana and is 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, and Martinville Fields which have been producing oil
for over two years, and Heidelberg Field where we started injecting CO2 in December
2008. 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. Tinsley Field had its first oil production response in the second quarter of 2008. Phase IV
includes Cranfield, where we began CO2 injection operations during July 2008 and had our
first oil production response in the first quarter of 2009, and Lake St. John Field, a project
currently scheduled to commence in 2011, both fields located near the Mississippi/Louisiana border
west of the Phase I fields. Phase V is Delhi Field, a Louisiana field
acquired in 2006, located
southwest of Tinsley Field. CO2 injection in Phase V will begin in 2009 upon completion
of the Delta CO2 Pipeline, an 80-mile pipeline from Tinsley to Delhi. Citronelle Field
in Southwest Alabama, another field acquired in 2006, is our Phase VI. Citronelle will require an
extension to the Free State CO2 Pipeline in order to commence this project, the timing
of which is uncertain at this time. Our last two currently existing phases will require completion
of our 320-mile Green Pipeline, which will run from Southern Louisiana to Hastings Field, south of
Houston, Texas, scheduled for completion in 2010. Hastings Field, a field on which we acquired a
purchase option in late 2006 and purchased in February 2009, 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 wells and drilled 20 additional CO2 producing wells, significantly
increasing our estimated proved CO2 reserves to approximately 5.6 Tcf as of December 31,
2008, 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.
Today, we own every producing CO2 well in the region. Although our current proved
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 continued our exploration efforts by
completing a 136 square mile 3-dimensional seismic program during 2008. The 3-D seismic program
was located west of the DRI Ice Field over existing known CO2 fields and adjacent lead
areas. The seismic data will be evaluated during 2009 with anticipated exploratory drilling in
future years. During 2008 we drilled and completed five CO2 production wells. These
wells added 360 MMcf/d of CO2 production capacity which increased the Jackson Dome total
CO2 production capacity to between 900 MMcf/d and 1.0 Bcf/d. During the fourth quarter
2008, production averaged 767 MMcf/d of CO2, a 44% increase over levels in the fourth
quarter 2007. In addition to expanding our production capacity, during 2008 we completed the
installation and startup of a second train at the Barksdale dehydration facility at Jackson Dome.
This expansion added 300 MMcf/d of CO2 dehydration capacity, which increased the Jackson
Dome total CO2 dehydration capacity to approximately 1.1 Bcf/d. We also installed a
pump station in Brandon, Mississippi, to boost NEJD pipeline pressure and increase CO2
deliverability capacity in that pipeline to approximately 515 MMcf/d. In order to ensure
future production rates, processing capabilities and deliverability to the main transportation
pipelines, during 2009 we are constructing a 150 MMcf/d Trace Dehydration Facility, installing
additional pump capacity at the Brandon Pump Station and constructing a 13-mile pipeline from the
Barksdale dehydration facility to the Brandon Pump Station. This
pipeline will provide additional
capacity to the NEJD line by bypassing a majority of the industrial users.
6
During 2008, we sold an average of 89 MMcf/d of CO2 to commercial users, and we
used an average of 548 MMcf/d for our tertiary activities. We are continuing to increase our CO2 production,
averaging 767 MMcf/d during the fourth quarter of 2008. We estimate that our planned tertiary
operations will not require any significant additional deliverability through 2010.
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. If built, these plants could 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 2013. These plants have all been delayed due to current economic conditions
and it is uncertain when, if ever, these plants will be built. We have entered into long-term
commitments to purchase manufactured CO2 from four proposed plants, which, if all four
plants are built, could potentially provide us with an aggregate of 1.0 Bcf/d of
CO2, commencing in 2013. In addition to the proposed gasification plants, we
have ongoing discussions underway regarding existing plants of various types that emit CO2
and we may be able to purchase their volumes. In order to capture such volumes, we (or the
plant owner) would need to install additional equipment, which include at a minimum, compression
facilities. Most of these existing plants emit relatively small volumes of CO2,
generally less than the proposed gasification plants, but such volumes may still be
attractive if the source is located near our proposed Green CO2 pipeline. The cost 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 in the next few years Congress could enact legislation to address climate change by
capping or taxing U.S. CO2 emissions, which could ultimately increase the supply and
lower our cost of man-made CO2 for our operations by creating economic penalties for the
emission of CO2. Further, we see these sources as a possible expansion of our natural
Jackson Dome source, assuming they are economic, and we believe that our potential ability to tie
these sources together with pipelines will give us a significant competitive advantage over our
competitors in our geographic area in acquiring additional oil fields and future potential man-made
sources of CO2. We believe that we are a likely purchaser of CO2
produced 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 source to balance
our CO2 supplies and demand.
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 four existing Phase II tertiary fields in East
Mississippi (Eucutta, Soso, Martinville and Heidelberg) and will also be used for our proposed
projects at South Cypress Creek and other fields in Phase II.
During 2008, 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 (31 miles), which significantly increased the transportation capacity of CO2 to
that field. We also reconditioned and converted the natural gas pipeline we acquired from Southern
Natural Gas Company in 2007 to CO2 service, which we are currently using to transport
CO2 to our first Phase IV field, Cranfield Field. During 2008, we started construction
to further extend our Delta Pipeline with a 24 78-mile extension from Tinsley Field to Delhi
Field. Completion of this segment is expected during the second quarter of 2009.
In late 2006, we purchased an option to acquire Hastings Field, a potential tertiary flood
located near Houston, Texas, which we subsequently acquired in February 2009. In order to flood
Hastings Field, we are building a CO2 pipeline from the southern end of our existing
NEJD CO2 Pipeline that terminates near Donaldsonville, Louisiana, to Hastings Field,
estimated to be approximately 320 miles. Based on our latest estimates, this pipeline is expected
to cost between $700 million and $750 million. During 2007, we committed to the manufacture of the
24 pipe and thereby locked-in the pipe purchase price, and acquired approximately 100-plus miles
of the necessary 320 miles of right-of-way. Our efforts during 2008 were focused on engineering
design, pipe manufacturing and right-of-way acquisitions. Construction of the pipeline began
during November 2008 and will continue through 2010. This multi-year project is underway and in
2009 we expect elevated activity and elevated spending (especially during the first half of the
year) as crews work to complete the pipeline and its connecting line to Oyster Bayou Field, east of
Galveston Bay, by late 2009 or early 2010 and on to the Hastings Field by year-end 2010. 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.
7
Overall 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, but we
expect them to be reduced to an economic break-even dollar cost on these projects in the
mid-twenties per barrel if oil prices remain at their current reduced level, 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 proved reserves) for our
tertiary oil fields through December 31, 2008, are approximately $11.30 per BOE. Currently, we
forecast that our finding and development costs for most of our tertiary projects will average less
than $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, and other factors, as the finding and development costs to date do not include
significant unproved potential reserves in most of the fields. Our operating costs for tertiary
operations are highly dependent on commodity prices and could range from $15 to $25 per BOE over
the life of each field, 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 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.
Tentatively, we plan to spend approximately $52 million in 2009 in the Jackson Dome area with
the intent to add additional CO2 deliverability for future operations. Approximately
$138 million in capital expenditures is budgeted in 2009 at the oil field level in Phases I through
V, plus an additional $485 million for our Delta and Green CO2 Pipelines, making our
combined CO2 related expenditures just over 90% of our projected $750 million 2009
capital budget.
Our Tertiary Oil Fields with Proved Tertiary Reserves
On December 31, 2008, we had total tertiary-related proved oil reserves of approximately 125.8
MMBbls, consisting of 3.2 MMBbls at Little Creek Field (and surrounding smaller fields), 11.8
MMBbls at Mallalieu Field, 13.7 MMBbls at McComb and Smithdale Fields, 17.3 MMBbls at Brookhaven
Field, 9.1 MMBbls at Eucutta Field, 9.0 MMBbls at Soso Field, 0.8 MMBbls at Martinville Field, 34.4
MMBbls at Tinsley, 4.0 MMBbls at Lockhart, and 22.4 MMBbls at Heidelberg. 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 21,874 Bbls/d during
the fourth quarter of 2008. We expect this production to continue to increase for several years as
we expand our tertiary operations to additional fields.
Phase I Fields
Mallalieu Field. Mallalieu Field consists of two units, West Mallalieu Unit and the smaller
East Mallalieu Unit. Combined they are our most prolific tertiary flood in terms of production,
producing 5,056 Bbls/d during the fourth quarter 2008. In contrast to many of our existing fields,
Mallalieu Field was not waterflooded prior to CO2 injection. Therefore, we estimate
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 2007, we increased our proved reserves in
this area, raising our estimated recovery factor from 17% to 20% for this field, based on
production performance to date. A total of $11.3 million was invested in this field during 2008 to
drill, re-enter or recomplete wells in efforts to improve production. During the fourth quarter of
2008, we began an expansion of the central processing facility in this field, which is expected to
be completed in July, 2009. The expansion of the facility will allow CO2 recycle rates
to increase from the current 160 MMcf/d to 230 MMcf/d.
From inception through December 31, 2008, we had net positive cash flow (revenue less
operating expenses and capital expenditures, including the acquisition cost) from Mallalieu Field of $421.0 million.
8
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 generally
increased since that time, averaging 1,563 Bbls/d in the fourth quarter of 2008. During 2008, we
expanded the number of injection wells and increased injection pressures, resulting in significant
increases in our CO2 injections at McComb Field. The field continues to present
challenges to the technical team, but we are improving our understanding of the reservoir. The
technical team is working to further improve production rates by monitoring injection patterns,
reworking producing wells, and using injection surveys for conformance issues within the reservoir.
In early 2008, we had a mechanical failure in one of our best wells at Smithdale, causing a
temporary decline in production. The well was redrilled and oil production was restored, averaging
529 Bbls/d in the fourth quarter of 2008. The reservoir at Smithdale is a channel and thus our
drilling was based on the completion of our 2007 3-D seismic survey covering the McComb and
Smithdale Fields. By utilizing the 3-D seismic data, our geoscientists are able to put our wells
in optimal positions within the channels at Smithdale to maximize the aerial coverage and sweep of
the CO2 injected.
From inception through December 31, 2008, we had not yet recovered our costs in these fields,
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition costs) from these fields of $101.2 million.
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 generally increase throughout 2006 and
2007 as additional injection patterns have been developed. Brookhaven Field has three discrete
reservoirs that are being simultaneously CO2 flooded. Our oil production here during
the fourth quarter of 2008 averaged 3,178 Bbls/d.
During 2008, oil production increased from 3,000 to 4,500 barrels of oil per day as a result
of expanded development of the CO2 flood. Also, detailed production and reservoir
evaluations identified certain areas of high permeability within the Tuscaloosa Reservoir that act
as thief zones and take a disproportionate volume of CO2 from the injection wells.
Polymer treatments designed to reduce CO2 injection into these thief zones were pumped
successfully on two wells. The polymer treatments are designed to alter the injection profiles and
improve the reservoir sweep efficiencies in the first and second development areas of Brookhaven
Field. The injection and offsetting production results of these treatments are encouraging enough
that additional treatments are planned in 2009.
From inception through December 31, 2008, we had net positive cash flow (revenue less
operating expenses and capital expenditures, including the acquisition cost) from Brookhaven of
$4.6 million.
Little Creek Area. The Little Creek area fields, Denburys most mature enhanced oil recovery
project, were acquired in 1999. During the fourth quarter of 2008, production averaged 1,706
Bbls/d from the Little Creek area, which includes Lazy Creek. Production at Little Creek Field
began declining during 2006 and is expected to gradually decline in the future, even though 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.
A project was initiated in 2008 between Denbury, Mississippi State University, and the U.S.
Department of Energy. The group is studying the process of alternating CO2 injection
with nutrient-enriched water in a CO2 injection well to stimulate the growth and
development of microbes in the reservoir. The one-year project will monitor injection pressures
and offset oil samples for evidence of improved sweep efficiencies within the reservoir as a result
of the growth of the microbes. If successful, the technique could be expanded to other portions of
the field.
From inception through December 31, 2008, 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 $183.5 million.
Lockhart
Crossing Field. Lockhart Crossing, located in Livingston Parish, Louisiana, is our first
CO2 project outside of Mississippi. Lockhart Crossing produces from the Wilcox formation at an average depth of 10,200 and has similar reservoir
characteristics to the Tuscaloosa formation in which we had great success
with tertiary flooding at Little Creek and Mallalieu Fields.
We initiated CO2 injections during December 2007 after completing
the six mile supply line connecting Lockhart Crossing to the NEJD Pipeline. We saw our first tertiary production there in July 2008. By the end of 2008, we had completed two of the five development phases in the field and we are using 3-D
seismic data to assist us with the remaining development.
From inception through December 31, 2008, 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 costs) from this field of $59.5 million.
9
Phase II Fields
Eucutta Field. The oil production 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. The initial tertiary oil
production occurred in the fourth quarter of 2006. During 2008, oil production continued to
increase as the Eutaw Reservoir was more fully developed, averaging 3,538 Bbls/d during the fourth
quarter of 2008. Our plans for 2009 include the development of the remaining injection patterns,
along with an expansion and upgrade of the CO2 facility. This work will be completed in
early 2009, with an anticipated increase in oil production thereafter.
At December 31, 2008, we had 9.1 MMBbls of proved reserves in the Eucutta Field attributable
to the CO2 flood 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, 2008, we had net positive
cash flow (revenue less operating expenses and capital expenditures, including the acquisition
cost) from Eucutta of $3.9 million.
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 early 2007 from the Bailey.
In 2007 we continued the development of additional patterns in both the Rodessa and Bailey
intervals, and by the fourth quarter of 2007, we had our initial response from the Rodessa combined
with continued response from the Bailey. In addition, a pilot CO2 flood was initiated
in the Cotton Valley Sand. We made significant additions to the CO2 recycle facility
during 2008, increasing the CO2 purchase capacity. During the fourth quarter of 2008,
production at Soso had increased to 2,704 Bbls/d.
From inception through December 31, 2008, 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 $67.6 million.
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 completed the development of the Mooringsport
formation during 2006. During 2008, an additional producing well was drilled to expand the
development of the Rodessa sand. A Lower Hosston huff and puff project was also initiated. The
Lower Hosston project consists of injecting a predetermined volume of CO2 into the
reservoir, allowing the CO2 time to disperse and contact oil, then flowing the well back
and producing the oil that contacted the CO2. Numerous cycles of injection and
production are planned. We are currently in the first injection cycle on this project. During the
fourth quarter of 2008 production at Martinville averaged 1,213 Bbls/d, almost all of which is from
the Mooringsport.
Although we booked minimal proved reserves in 2006 from the one responding well in the
Mooringsport, in 2007 and 2008 we booked additional reserves, approximately 1.5 MMBbls and 0.8
MMBbls, respectively, 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.
10
From inception through December 31, 2008, 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 $6.2 million.
The Martinville Field Wash Fred 8500 reservoir development continues to evolve. The Wash
Fred formation 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
low 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
with 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.
Heidelberg Field. Our 2008 capital program included $43.4 million for construction of the
CO2 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 will be conducted in the West Heidelberg (WHEOUP) Unit. 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 similar to the results
at Eucutta Field. During the first half of 2008, the Heidelberg central processing and
CO2 recycle facility surface site was secured, cleared, and prepared for construction
and facility construction began during the third quarter of the year. The first phase well work
was completed in the fourth quarter with the conversion of seventeen producers and eight
CO2
injectors. As of year end, we were injecting approximately 40 MMcf/d of CO2 into the
Eutaw formation in the southern end of West Heidelberg Field. During 2009, we will add eight new
injection patterns and expand the central processing facility. Oil production response to the
CO2 injection is expected during the second half of 2009. Four phases are planned for
West Heidelberg Field before moving EOR operations into East Heidelberg.
Due to Heidelberg being an analogy to Eucutta, we were able to book proved tertiary oil
reserves at Heidelberg Field at December 31, 2008. Although similar in many respects, the Eutaw
reservoir at Heidelberg contains two to three times the potential oil reserves as the Eutaw
formation at Eucutta Field.
Phase III Field
Tinsley Field. Tinsley Field was acquired in January 2006 and is the largest oil field in the
state of Mississippi. As is the case with the majority of fields in Mississippi, Tinsley produces
from multiple reservoirs. Our primary target in Tinsley for CO2 enhanced oil recovery
operations is the Woodruff formation. A prior operator 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 crude 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 reconditioned the pipeline for CO2
service and initiated limited CO2 injection in Tinsley Field in January 2007. During
2008 the 24 Delta Pipeline was completed and placed in service between Jackson Dome and the
Tinsley CO2 recycle facility, allowing us to transport and inject significantly larger
volumes of CO2. We had our first tertiary oil production commencing in April 2008. By
July 2008, all of the tertiary wells in the first two phases were responding to CO2
injection and producing oil. During the fourth quarter of 2008, the average oil production was
1,832 Bbls/d. We also had non-CO2 oil production during this same period of 736 Bbls/d.
From inception through December 31, 2008, 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 Tinsley of $213.8 million.
11
Our Tertiary Oil Fields Without Proved Tertiary Reserves
Cranfield. Cranfield development accelerated during 2008 as we increased the well count to 11
CO2 injectors and 11 producers. Reconditioning of the CO2 pipeline and the
initial phase of the production facility were completed in the third quarter of 2008, which allowed us to commence CO2 injection
into the Lower Tuscaloosa reservoir. The CO2 injection increased reservoir pressure to
a level that caused most of the wells to begin flowing water by late 2008. We had our first minor
amounts of tertiary oil production in January 2009. At Cranfield, we have participated with the
Bureau of Economic Geology (BEG) from the University of Texas as they study CO2
injection and sequestration to better define and understand the movement of CO2 through
the reservoir. The results of this study could lead to a greater recovery of the oil in the
reservoir.
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 income. In 2008, eight wells were re-completed to be utilized in the Delhi
flood patterns. We also finalized the development plans to complete two CO2 flood
patterns in the Paluxy formation and one pattern in the Tuscaloosa formation. The surveying and
permitting process for wells, flowlines and facilities are expected to be completed during the
first quarter of 2009. The Delta Pipeline (Tinsley to Delhi) is expected to be delivering
CO2 to Delhi Field by the end of the second quarter of 2009. The CO2
processing facility engineering will be completed during 2009 and construction of the CO2
facility will begin, with first enhanced oil production anticipated in 2010. As of December
31, 2008, 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 gave us an option to purchase their interest in Hastings Field, a strategically
significant potential tertiary flood candidate located near Houston, Texas. We exercised the
purchase option prior to September 2008, and closed the $201 million acquisition during February
2009. As consideration for the option agreement, we made total payments of $50 million.
The purchase price of $201 million included approximately $4.9 million for certain surface
land, oilfield equipment and other related assets. Under the terms of
the agreement, Venoco, Inc., the seller, retained a 2% override and reversionary interest of approximately 25% following payout,
as defined in the option agreement. The Hastings Complex is currently producing approximately 2,400
BOE/d, net to the acquired interest, with conventional proved
reserves of approximately 5.8 MMBOE
using year-end 2008 prices. The Hastings proved reserves were not included in the Companys
year-end proved reserves. We plan to commence flooding the field with CO2 beginning in
2011, after completion of our Green
CO2 Pipeline currently under construction, and
construction of field CO2 recycling facilities.
As part of the agreement, we are required to spend an aggregate of approximately $179 million
over a five year period to develop the field for tertiary operations (commencing in 2010), with an
obligation to commence CO2 injections in the field by late 2012.
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 started
construction of the Green Pipeline during November 2008 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
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 on or close to the planned
route of the 24 Green Pipeline. We acquired the majority interest in Oyster Bayou Field and a
relatively small interest in Fig Ridge Field. We plan to start the unitization hearings required
at Oyster Bayou Field during 2009. 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.
During 2008 we initiated those discussions.
Our acquisitions in Gillock Field include an acquisition of almost all of the South Gillock
Unit, 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 Green Pipeline.
12
Overall Tertiary Economics to Date. Through December 31, 2008, we have invested a total of
$1.4 billion on tertiary oil fields (including the allocated acquisition costs), and received $1.3
billion in net operating income (revenue less operating expenses), or net unrecovered cash flow of
$105.3 million, the deficit primarily due to the significant funds expended on acquisitions during
2006. Of our total spending, approximately $229.6 million was invested to date on fields that had
little or no proved reserves at December 31, 2008 (i.e., significant incremental proved reserves
are anticipated in future years). 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 $816.7 million as of December 31, 2008, including $525.7 million
associated with CO2 pipelines. At year-end 2008, the proved oil reserves in our
tertiary recovery oil fields had a PV-10 Value of approximately $1.0 billion, using December 31,
2008, NYMEX pricing of $44.60 per barrel. In addition, there are significant probable and
potential reserves at several other fields for which tertiary operations are under way or planned.
Texas Barnett Shale
We currently own approximately 20,441 gross acres and 19,457 net acres in the Barnett Shale
area in North Central Texas. We acquired our initial acreage in this area in 2001 and did only
limited development until 2005. Through December 31, 2008, we have invested a total of $552.3
million on the Barnett Shale area (including acquisition costs) and have received $403.0 million in
net operating income (revenue less operating expenses), or net negative cash flow of $149.3
million. At December 31, 2008, we had approximately 458 Bcfe of proved reserves in the Barnett
Shale area with a PV-10 Value of approximately $430.0 million, using December 31, 2008, Henry Hub
indicative cash pricing of $5.71 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 2008, we drilled and completed
38 horizontal wells which kept our production from this area about the same throughout the year,
averaging approximately 73 MMcfe/d during the fourth quarter of 2008.
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 were 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
development well locations that could be drilled. Our year-end reserves included 77 proved
undeveloped locations, plus we have an additional 64 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 are inconclusive at this time. We have drilled two 250 spaced wells.
These wells have produced volumes at or above that which an average conventionally spaced well
would have produced at this time in their production life. If our testing of the Barnett Shale on
tighter well spacing continues to be successful, it would significantly increase our number of
future locations. We expect production in the Barnett Shale to decline during 2009, as we are
planning on drilling only six wells during the year due to reduction of our overall capital
expenditure program because of the significant decline in commodity prices during the last half of
2008. Our planned 2009 capital expenditures in the Barnett Shale area are estimated to be
approximately $25 million.
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 2008 averaged approximately 12,150 BOE/d from this area (25% of our Company
total), and we had proved reserves of 40.1 MMBOE as of December 31, 2008 (16% 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 four currently have tertiary operations (Soso, Martinville,
Eucutta and Heidleberg Fields). Production from our conventional and secondary recovery operations
in our East Mississippi fields has been relatively consistent over the last three years, averaging
12,743 BOE/d in 2006, 12,479 BOE/d in 2007 and 11,897 BOE/d during 2008.
Heidelberg Field. The largest field in the region and one of our largest fields corporately is
Heidelberg Field, which for the fourth quarter of 2008 produced an average of 7,482 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
13
segments due to subsequent faulting. Most of the past and current production comes from the
Eutaw, Selma Chalk and Christmas sands at depths from 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,
other than our tertiary operations, 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
Heidelberg to a peak quarterly average of 19.4 MMcf/d in the fourth quarter of 2008. 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 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 during
2008, we drilled 10 horizontal Selma Chalk wells, three of which were located in West Heidelberg.
Similar to the Barnett Shale, we have severely curtailed capital expenditures on this field in 2009
as a result of lower commodity prices.
14
Field Summaries
Denbury operates in five primary areas: Eastern Mississippi, Western Mississippi, Texas,
Alabama and Louisiana. Our 17 largest fields (listed below) constitute approximately 97% of our
total proved reserves on a BOE basis, and 96% of our total proved reserves on a PV-10 Value basis.
Within these 17 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; Jackson, Mississippi; and Aledo, Texas.
|
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|
Proved Reserves as of December 31, 2008(1) |
|
|
2008 Average Daily Production |
|
|
|
|
|
|
Oil |
|
|
Natural Gas |
|
|
|
|
|
|
BOE |
|
|
PV-10 Value(2) |
|
|
Oil |
|
|
Natural Gas |
|
|
|
|
|
|
(MBbls) |
|
|
(MMcf) |
|
|
MBOEs |
|
|
% of total |
|
|
(000's) |
|
|
(Bbls/d) |
|
|
(Mcf/d) |
|
|
Avg NRI |
|
|
|
|
|
|
Tertiary Oil Fields |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
34,440 |
|
|
|
|
|
|
|
34,440 |
|
|
|
13.8 |
% |
|
$ |
224,812 |
|
|
|
1,010 |
|
|
|
|
|
|
|
75.6 |
% |
Heidelberg |
|
|
22,394 |
|
|
|
|
|
|
|
22,394 |
|
|
|
8.9 |
% |
|
|
22,948 |
|
|
|
|
|
|
|
|
|
|
|
77.3 |
% |
Brookhaven |
|
|
17,330 |
|
|
|
|
|
|
|
17,330 |
|
|
|
6.9 |
% |
|
|
213,816 |
|
|
|
2,826 |
|
|
|
|
|
|
|
79.2 |
% |
McComb Area |
|
|
13,688 |
|
|
|
|
|
|
|
13,688 |
|
|
|
5.5 |
% |
|
|
101,106 |
|
|
|
1,901 |
|
|
|
|
|
|
|
78.9 |
% |
Mallalieu |
|
|
11,790 |
|
|
|
|
|
|
|
11,790 |
|
|
|
4.7 |
% |
|
|
161,077 |
|
|
|
5,686 |
|
|
|
|
|
|
|
76.6 |
% |
Eucutta |
|
|
9,147 |
|
|
|
|
|
|
|
9,147 |
|
|
|
3.7 |
% |
|
|
135,975 |
|
|
|
3,109 |
|
|
|
|
|
|
|
83.5 |
% |
Soso |
|
|
9,024 |
|
|
|
|
|
|
|
9,024 |
|
|
|
3.6 |
% |
|
|
91,089 |
|
|
|
2,111 |
|
|
|
|
|
|
|
77.2 |
% |
Lockhart Crossing |
|
|
3,970 |
|
|
|
|
|
|
|
3,970 |
|
|
|
1.6 |
% |
|
|
35,502 |
|
|
|
186 |
|
|
|
|
|
|
|
58.0 |
% |
Little Creek & Lazy Creek |
|
|
3,213 |
|
|
|
|
|
|
|
3,213 |
|
|
|
1.3 |
% |
|
|
40,758 |
|
|
|
1,683 |
|
|
|
|
|
|
|
83.2 |
% |
Martinville |
|
|
839 |
|
|
|
|
|
|
|
839 |
|
|
|
0.3 |
% |
|
|
7,700 |
|
|
|
865 |
|
|
|
|
|
|
|
78.1 |
% |
|
|
|
|
|
Total Tertiary Oil Fields |
|
|
125,835 |
|
|
|
|
|
|
|
125,835 |
|
|
|
50.3 |
% |
|
|
1,034,783 |
|
|
|
19,377 |
|
|
|
|
|
|
|
78.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heidelberg |
|
|
17,066 |
|
|
|
63,637 |
|
|
|
27,672 |
|
|
|
11.0 |
% |
|
|
276,199 |
|
|
|
4,505 |
|
|
|
17,663 |
|
|
|
77.3 |
% |
Sharon |
|
|
16 |
|
|
|
24,458 |
|
|
|
4,092 |
|
|
|
1.6 |
% |
|
|
54,930 |
|
|
|
13 |
|
|
|
8,222 |
|
|
|
83.6 |
% |
Eucutta |
|
|
1,140 |
|
|
|
|
|
|
|
1,140 |
|
|
|
0.5 |
% |
|
|
14,346 |
|
|
|
309 |
|
|
|
3 |
|
|
|
67.3 |
% |
Summerland |
|
|
1,044 |
|
|
|
|
|
|
|
1,044 |
|
|
|
0.4 |
% |
|
|
7,524 |
|
|
|
373 |
|
|
|
|
|
|
|
74.4 |
% |
S. Cypress Creek |
|
|
937 |
|
|
|
17 |
|
|
|
940 |
|
|
|
0.4 |
% |
|
|
9,523 |
|
|
|
190 |
|
|
|
20 |
|
|
|
83.0 |
% |
Other Mississippi |
|
|
4,777 |
|
|
|
2,807 |
|
|
|
5,245 |
|
|
|
2.1 |
% |
|
|
53,816 |
|
|
|
2,012 |
|
|
|
1,065 |
|
|
|
21.4 |
% |
|
|
|
|
|
Total Mississippi |
|
|
24,980 |
|
|
|
90,919 |
|
|
|
40,133 |
|
|
|
16.0 |
% |
|
|
416,338 |
|
|
|
7,402 |
|
|
|
26,973 |
|
|
|
48.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Newark (Barnett Shale) |
|
|
20,865 |
|
|
|
332,502 |
|
|
|
76,282 |
|
|
|
30.5 |
% |
|
|
429,961 |
|
|
|
2,887 |
|
|
|
58,874 |
|
|
|
79.9 |
% |
Other Texas |
|
|
343 |
|
|
|
553 |
|
|
|
435 |
|
|
|
0.1 |
% |
|
|
3,059 |
|
|
|
266 |
|
|
|
1,488 |
|
|
|
64.6 |
% |
|
|
|
|
|
Total Texas |
|
|
21,208 |
|
|
|
333,055 |
|
|
|
76,717 |
|
|
|
30.6 |
% |
|
|
433,020 |
|
|
|
3,153 |
|
|
|
60,362 |
|
|
|
78.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana
and Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Various
Fields |
|
|
417 |
|
|
|
3,912 |
|
|
|
1,069 |
|
|
|
0.4 |
% |
|
|
17,786 |
|
|
|
310 |
|
|
|
1,312 |
|
|
|
56.7 |
% |
Louisiana Sold (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15 |
|
|
|
518 |
|
|
|
49.0 |
% |
|
|
|
|
|
Total Louisiana and Other |
|
|
417 |
|
|
|
3,912 |
|
|
|
1,069 |
|
|
|
0.4 |
% |
|
|
17,786 |
|
|
|
325 |
|
|
|
1,830 |
|
|
|
55.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Citronelle |
|
|
6,686 |
|
|
|
|
|
|
|
6,686 |
|
|
|
2.7 |
% |
|
|
24,906 |
|
|
|
1,176 |
|
|
|
|
|
|
|
63.3 |
% |
Other Alabama |
|
|
|
|
|
|
69 |
|
|
|
12 |
|
|
|
|
|
|
|
22 |
|
|
|
3 |
|
|
|
277 |
|
|
|
1.8 |
% |
|
|
|
|
|
Total Alabama |
|
|
6,686 |
|
|
|
69 |
|
|
|
6,698 |
|
|
|
2.7 |
% |
|
|
24,928 |
|
|
|
1,179 |
|
|
|
277 |
|
|
|
29.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company Total |
|
|
179,126 |
|
|
|
427,955 |
|
|
|
250,452 |
|
|
|
100.0 |
% |
|
$ |
1,926,855 |
|
|
|
31,436 |
|
|
|
89,442 |
|
|
|
64.9 |
% |
|
|
|
|
|
|
|
|
(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, 2008. The prices at that date were a NYMEX oil price of $44.60 per Bbl adjusted to prices received by
field and a Henry Hub natural gas cash price of $5.71 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 $1,415,498 at
December 31, 2008. A comparison of PV-10 to the Standardized Measure is included in the table on page 21 as well as further information
regarding our use of this non-GAAP measure. |
|
(3) |
|
Production in the Louisiana sold category is associated with the portion of the Louisiana divestiture that closed in February 2008. |
15
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, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Mississippi |
|
|
153,080 |
|
|
|
108,720 |
|
|
|
248,227 |
|
|
|
32,036 |
|
|
|
401,307 |
|
|
|
140,756 |
|
Louisiana |
|
|
35,863 |
|
|
|
34,162 |
|
|
|
4,559 |
|
|
|
3,882 |
|
|
|
40,422 |
|
|
|
38,044 |
|
Texas |
|
|
37,691 |
|
|
|
34,324 |
|
|
|
7,229 |
|
|
|
3,814 |
|
|
|
44,920 |
|
|
|
38,138 |
|
Alabama |
|
|
19,429 |
|
|
|
15,218 |
|
|
|
68,697 |
|
|
|
11,755 |
|
|
|
88,126 |
|
|
|
26,973 |
|
Other |
|
|
6,852 |
|
|
|
855 |
|
|
|
38,711 |
|
|
|
9,686 |
|
|
|
45,563 |
|
|
|
10,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
252,915 |
|
|
|
193,279 |
|
|
|
367,423 |
|
|
|
61,173 |
|
|
|
620,338 |
|
|
|
254,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denburys net undeveloped acreage that is subject to expiration over the next three years, if
not renewed, is approximately 25% in 2009, 22% in 2010 and 45% in 2011.
Productive Wells
The following table sets forth our gross and net productive oil and natural gas wells at
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Natural |
|
|
|
Producing Oil Wells |
|
|
Gas Wells |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
585 |
|
|
|
558.3 |
|
|
|
220 |
|
|
|
200.0 |
|
|
|
805 |
|
|
|
758.3 |
|
Louisiana |
|
|
25 |
|
|
|
18.8 |
|
|
|
9 |
|
|
|
9.0 |
|
|
|
34 |
|
|
|
27.8 |
|
Texas |
|
|
27 |
|
|
|
23.1 |
|
|
|
199 |
|
|
|
192.6 |
|
|
|
226 |
|
|
|
215.7 |
|
Alabama |
|
|
151 |
|
|
|
120.3 |
|
|
|
7 |
|
|
|
3.1 |
|
|
|
158 |
|
|
|
123.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
788 |
|
|
|
720.5 |
|
|
|
435 |
|
|
|
404.7 |
|
|
|
1,223 |
|
|
|
1,125.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
39 |
|
|
|
3.8 |
|
|
|
20 |
|
|
|
4.6 |
|
|
|
59 |
|
|
|
8.4 |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Texas |
|
|
1 |
|
|
|
|
|
|
|
4 |
|
|
|
0.5 |
|
|
|
5 |
|
|
|
0.5 |
|
Alabama |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
0.6 |
|
|
|
3 |
|
|
|
0.6 |
|
Other |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
44 |
|
|
|
3.8 |
|
|
|
28 |
|
|
|
5.7 |
|
|
|
72 |
|
|
|
9.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
624 |
|
|
|
562.1 |
|
|
|
240 |
|
|
|
204.6 |
|
|
|
864 |
|
|
|
766.7 |
|
Louisiana |
|
|
25 |
|
|
|
18.8 |
|
|
|
10 |
|
|
|
9.0 |
|
|
|
35 |
|
|
|
27.8 |
|
Texas |
|
|
28 |
|
|
|
23.1 |
|
|
|
203 |
|
|
|
193.1 |
|
|
|
231 |
|
|
|
216.2 |
|
Alabama |
|
|
151 |
|
|
|
120.3 |
|
|
|
10 |
|
|
|
3.7 |
|
|
|
161 |
|
|
|
124.0 |
|
Other |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
832 |
|
|
|
724.3 |
|
|
|
463 |
|
|
|
410.4 |
|
|
|
1,295 |
|
|
|
1,134.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
Drilling Activity
The following table sets forth the results of our drilling activities over the last three
years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
6.2 |
|
|
|
10 |
|
|
|
8.5 |
|
Non-productive(3) |
|
|
1 |
|
|
|
1.0 |
|
|
|
4 |
|
|
|
3.4 |
|
|
|
8 |
|
|
|
6.8 |
|
Development Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
102 |
|
|
|
98.3 |
|
|
|
101 |
|
|
|
96.8 |
|
|
|
90 |
|
|
|
82.7 |
|
Non-productive(3)(4) |
|
|
1 |
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
104 |
|
|
|
100.0 |
|
|
|
114 |
|
|
|
106.4 |
|
|
|
108 |
|
|
|
98.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
An exploratory well is a well drilled either in search of a new, as yet undiscovered, oil
or natural 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 2008, 2007 and 2006, an additional 33, 23, and 14 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 Results 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, 2008, we had three significant
purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon
Petroleum Company LLC (49%), Hunt Crude Oil Supply Co. (20%) and Crosstex Energy Field Services
Inc. (14%).
17
For the year ended December 31, 2007, three purchasers each accounted for 10% or more
of our oil and natural gas revenues: Marathon Petroleum Company LLC (43%), Hunt Crude Oil Supply
Co. (19%) and Crosstex Energy Field Services Inc. (16%). For the year ended December 31, 2006, we
had two significant purchasers that each accounted for 10% or more of our oil and natural gas
revenues: Marathon Petroleum Company LLC (28%) and Hunt Crude Oil Supply Co. (18%).
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 tertiary
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, 2008, the discount for our oil
production from Heidelberg Field averaged $15.65 per Bbl and for our Eastern Mississippi properties
as a whole the discount averaged $13.64 per Bbl relative to NYMEX oil prices. For our Phase I
tertiary fields in Southwest Mississippi, we averaged a premium of $3.75 per Bbl over NYMEX oil
prices during 2008. For our Phase II tertiary fields, we averaged a discount of $6.61 per Bbl
below NYMEX oil prices during 2008. Our Texas Barnett Shale properties averaged $43.74 per Bbl
below NYMEX prices during 2008, largely because the reported oil sales are mostly natural gas
liquids, which typically sell at much lower prices 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 in
Mississippi. For the year ended December 31, 2008,
we averaged $0.35 above NYMEX prices for our Mississippi natural gas production. However, in the
Barnett Shale area in Texas, due primarily to its location, the price
we received averaged $0.74
below NYMEX prices.
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
18
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 and Climate Change Legislation
In October 2008, as part of the Emergency Economic Stabilization Act, Congress included a new
tax credit for carbon capture and sequestration, including that achieved through enhanced oil
recovery, as further modified by the American Recovery and Reinvestment Act of 2009, passed in
February 2009. In future periods Congress may decide to revisit legislation introduced in prior
sessions to repeal existing incentives or impose new taxes on the
19
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 greenhouse gases. If enacted, such legislation could impose a tax or other
economic penalty on the production of oil and gas that, when consumed, ultimately release
CO2. Any additional taxes or economic penalties imposed on the production of oil and
gas would increase the costs incurred by the Company in its exploration and production activities
and more than likely reduce the supply of domestic production of oil and gas which could in turn
increase the price received on our oil and gas production. At the same time, legislation to reduce
the emissions of carbon dioxide or other gases could also create economic incentives for
technologies and practices that reduce or avoid such emissions, including activities that sequester
CO2 in geologic formations such as oil and gas reservoirs. Denburys CO2-EOR
operations, including our CO2 pipeline network are well positioned in this regard.
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 or could result in the imposition of economic
penalties on the production of fossil fuels that, when used, ultimately release CO2;
(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.
20
Estimated Net Quantities of Proved Oil and Natural 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, 2008, 2007 and 2006.
The reserve estimates were prepared using constant prices and costs in accordance with the
guidelines of Statement of Financial Accounting Standards (SFAS) No. 69. The prices used in
preparation of the reserve estimates were based on the market prices in effect as of December 31 of
each year, with the appropriate adjustments (transportation, gravity, basic sediment and water
(BS&W), purchasers bonuses, Btu, etc.) applied to each field. The reserve estimates do not
include any value for probable or possible reserves that may exist, nor do they include any value
for undeveloped acreage. The reserve estimates represent our net revenue interests in our
properties. During 2008, we provided oil and gas reserve estimates for 2007 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, 2007.
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 90% 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 94% of our proved
undeveloped natural gas reserves. Due to the curtailment of our capital spending for 2009, our
current plans include drilling only six new wells in the Barnett Shale during 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
ESTIMATED PROVED RESERVES: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
179,126 |
|
|
|
134,978 |
|
|
|
126,185 |
|
Natural gas (MMcf) |
|
|
427,955 |
|
|
|
358,608 |
|
|
|
288,826 |
|
Oil equivalent (MBOE) |
|
|
250,452 |
|
|
|
194,746 |
|
|
|
174,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PERCENTAGE OF TOTAL MBOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved producing |
|
|
47 |
% |
|
|
56 |
% |
|
|
48 |
% |
Proved non-producing |
|
|
11 |
% |
|
|
13 |
% |
|
|
17 |
% |
Proved undeveloped |
|
|
42 |
% |
|
|
31 |
% |
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
REPRESENTATIVE OIL AND NATURAL GAS PRICES:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil NYMEX |
|
$ |
44.60 |
|
|
$ |
95.98 |
|
|
$ |
61.05 |
|
Natural gas Henry Hub |
|
|
5.71 |
|
|
|
6.80 |
|
|
|
5.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PRESENT VALUES (thousands):(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Discounted estimated future net cash flow before
income taxes (PV-10 Value) (3) |
|
$ |
1,926,855 |
|
|
$ |
5,385,123 |
|
|
$ |
2,695,199 |
|
Standardized measure of discounted estimated future net
cash flow after income taxes |
|
|
1,415,498 |
|
|
|
3,539,617 |
|
|
|
1,837,341 |
|
|
|
|
(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 (in thousands), was $511,357 at December 31, 2008, $1,845,506 at
December 31, 2007, and $857,858 at December 31, 2006. 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. |
21
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 90% of our 2009 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, have been particularly
volatile over the last six months, and likely will continue to be volatile in the future,
especially given current world geopolitical conditions. As a result of the low oil and natural gas
prices at December 31, 2008, we recorded a $226.0 million full cost ceiling test write-down.
Subsequent to December 31, 2008, oil and natural gas prices have continued their volatility and are
currently at levels lower than at year-end 2008. If oil and natural gas prices remain at these
lower levels through March 31, 2009, or subsequent periods, we may be required to record additional
full cost ceiling test write-downs in the first quarter of 2009, or in subsequent periods. The
amount of any future write-down is difficult to predict and will depend upon the oil and natural
gas prices at the end of each period, the incremental proved reserves that might be added during
each period and additional capital spent.
Our cash flow from operations is highly dependent on the prices that we receive for oil and
natural gas. This price volatility also affects the amount of our cash flow available for capital
expenditures and our ability to borrow money or raise additional capital. The amount we can borrow
or have outstanding under our bank credit facility is subject to semi-annual redeterminations. Oil
prices are likely to affect us more than natural gas prices because approximately 72% of our
December 31, 2008 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; |
22
|
|
|
the price and availability of alternative fuel sources; |
|
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|
|
weather conditions, including hurricanes and tropical storms in and around the Gulf
of Mexico; |
|
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|
|
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. Also, oil and natural gas prices do not
necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue,
but could reduce the amount of oil and natural gas that we can produce economically and, as a
result, could have a material adverse effect upon our financial condition, results of operations,
oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the
oil and natural gas industry experiences significant price declines, we may, among other things, be
unable to meet our financial obligations or make planned expenditures.
Since the end of 1998, oil prices have gone from near historic low prices to historic highs.
At the end of 1998, NYMEX oil prices were at historic lows of approximately $12.00 per Bbl, but
have generally increased since that time until mid-2008, albeit with fluctuations. For 2008, NYMEX
oil prices increases throughout the first six months, averaging approximately $111.03 per Bbl for
the first six months of 2008. During the last half of 2008, oil prices declined substantially,
ending the year at a NYMEX price of $44.60 per Bbl. Since we have acquired oil commodity
derivative contracts with a NYMEX floor price of $75 per barrel covering approximately 80% of our
2009 forecasted oil production, we are relatively insensitive to lower oil prices during 2009. We
currently do not have any oil or natural gas commodity derivative contracts in place for subsequent
years, and therefore oil prices could decline to a level that makes our tertiary projects uneconomic. If that were to happen,
we may decide to suspend future expansion projects and if prices were to drop below the cash break-
even point for an extended period of time, we may decide to shut-in existing production, either of
which would have a material adverse effect on our operations. Since our operating costs have not
decreased as quickly as commodity prices, it is difficult to determine a precise break-even point
for our tertiary projects. Based on prior history, we estimate that our economic break-even point
for these types of projects would approximate per barrel dollar costs in the range of the
mid-twenties, and our operating cash break-even point would be
between $15 and $20 of cost per
barrel if commodity prices remain at current levels for sustained periods.
The prices we receive for our crude oil do not always correlate with NYMEX prices. Our
NYMEX differentials over the last few years have ranged from a low of approximately $1.50 per Bbl
to a high of almost $10.00 per Bbl. These variances have been due to various factors and are
difficult to forecast or anticipate but have a direct impact on the net oil price we receive.
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 $6.97 per MMBtu during 2006, $7.09 per MMBtu during
2007, and $8.89 per MMBtu
during 2008, and ended 2008 at $5.62 per MMBtu.
The current financial crisis may have effects on our liquidity, business and financial condition
that we cannot predict.
Liquidity is essential to our business. Our liquidity could be substantially negatively
affected by an inability to raise funding in the long-term or short-term debt capital markets or
equity capital markets or an inability to access bank financing. The continued credit crisis and
related turmoil in the global financial system is likely to continue to materially affect our
liquidity, business and our financial condition. Our ability to access the capital markets has
been restricted as a result of this crisis and may be restricted in the future when we would like,
or need, to raise capital. The economic situation could also adversely affect the collectability
of our trade receivables or performance by our suppliers and cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their obligations or
seek bankruptcy protection. Additionally, the current economic situation could lead to reduced
demand for oil and gas, or lower prices for oil and gas, or both, which could have a negative
impact on our revenues.
23
Our level of indebtedness may adversely affect operations and limit our growth.
As of February 27, 2009, we had outstanding $525 million (principal amount) of 7.5%
subordinated notes, $420 million (principal amount) of 9.75% Senior Subordinated Notes, and $60
million of bank debt. At that time, we had approximately $690 million available on our bank credit
line. We currently have a bank borrowing base of $1.0 billion, with a commitment amount of $750
million. The borrowing base represents the amount that can be borrowed from a credit standpoint,
while the commitment amount is the amount the banks have committed to fund pursuant to the terms of
the credit agreement. The next semi-annual redetermination of the borrowing base for our bank
credit facility will be on April 1, 2009. 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 as our projected 2009 capital expenditures, excluding acquisitions, are
between $200 million and $300 million higher than our projected 2009 cash flow from operations. Further,
our cash flow from operations is highly dependent on the prices that we receive for oil and natural
gas, which in the latter part of 2008, declined significantly. If oil and natural gas prices remain
depressed 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; |
|
|
|
|
as a result of the discretionary nature of the setting of our bank borrowing base
and its being highly dependent on current commodity prices, if commodity prices were to
further decrease, our banks could reduce our borrowing base so that we could not borrow
additional funds or to a level below our outstanding debt that would require us to
repay any deficit (between the borrowing base and the outstanding bank debt) over a six
month period; |
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|
|
our business may not generate sufficient cash flow from operations to enable us to
continue to meet our obligations under our indebtedness; |
|
|
|
|
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 be greater
as a result of our level of indebtedness, potentially restricting us from making
acquisitions, introducing new technologies or exploiting business opportunities; |
|
|
|
|
our ability to borrow additional funds, dispose of assets, pay dividends and make
certain investments may be limited by the covenants contained in the agreements
governing our outstanding indebtedness limit; and |
|
|
|
|
our debt covenants may also affect our flexibility in planning for, and reacting to,
changes in the economy and in our industry. Our failure to comply with such covenants
could result in an event 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.
24
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.
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 3,926 BOE/d net to the acquired interests
during the fourth quarter of 2008, and have proved reserves of approximately 42.8 MMBOEs as of
December 31, 2008. During 2008, we recognized approximately 34.8 MMBOE of proven tertiary reserves
at Tinsley Field, but have yet to recognize any tertiary oil reserves at Citronelle or South
Cypress Creek Fields. In February 2009, we closed on the acquisition of Hastings field located
near Houston, Texas. Hastings is also a potential tertiary oil field and it will be supplied
CO2 by the Green Pipeline, which is currently under construction. The purchase price,
including option payments, was approximately $250 million. 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 these specific
acquisitions, 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
25
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; |
|
|
|
|
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.
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
26
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.
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, 2008, three purchasers each accounted for more than 10% of our
oil and natural gas revenues and in the aggregate, for 83% 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 flows 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.
As of December 31, 2008, approximately 42% 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.
27
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.
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
None.
28
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. As of February 23, 2009, based on information from the Companys transfer agent, American Stock Transfer and Trust
Company, the number of holders of record of Denburys common stock was 1,066. On
February 25, 2009, the last reported
sale price of Denburys common stock, as reported on the NYSE, was $12.88 per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
|
High |
|
|
Low |
|
|
High |
|
|
Low |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
33.640 |
|
|
$ |
21.760 |
|
|
$ |
15.310 |
|
|
$ |
12.980 |
|
Second Quarter |
|
|
40.320 |
|
|
|
27.280 |
|
|
|
19.380 |
|
|
|
14.835 |
|
Third Quarter |
|
|
37.240 |
|
|
|
16.110 |
|
|
|
23.380 |
|
|
|
18.275 |
|
Fourth Quarter |
|
|
18.860 |
|
|
|
5.590 |
|
|
|
30.560 |
|
|
|
22.405 |
|
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 2008.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Total Number of |
|
(d) Maximum Number |
|
|
(a) Total |
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
Number of |
|
(b) Average |
|
as Part of Publicly |
|
Yet Be Purchased |
|
|
Shares |
|
Price Paid |
|
Announced Plans or |
|
Under the Plan Or |
Period |
|
Purchased |
|
per Share |
|
Programs |
|
Programs |
October 1 through 31, 2008 |
|
|
3,475 |
|
|
$ |
15.44 |
|
|
|
|
|
|
|
|
|
November 1
through 30, 2008 |
|
|
398 |
|
|
$ |
10.33 |
|
|
|
|
|
|
|
|
|
December 1
through 31, 2008 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,873 |
|
|
$ |
14.91 |
|
|
|
|
|
|
|
|
|
There shares were purchased from employees of Denbury who delivered shares to the company to satisfy their minimum tax
withholding requirements related to the vesting of restricted shares.
29
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, 2008, 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, 2003, and that dividends were reinvested.
CUMULATIVE
TOTAL RETURN ON $100 INVESTMENT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2003 |
|
|
2004 |
|
|
2005 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
Denbury |
|
|
100.00 |
|
|
|
197.34 |
|
|
|
327.53 |
|
|
|
399.57 |
|
|
|
855.50 |
|
|
|
314.02 |
|
S&P 500 |
|
|
100.00 |
|
|
|
110.88 |
|
|
|
116.33 |
|
|
|
134.70 |
|
|
|
142.10 |
|
|
|
89.53 |
|
Dow Jones U.S. Exploration and Production |
|
|
100.00 |
|
|
|
141.87 |
|
|
|
234.54 |
|
|
|
247.14 |
|
|
|
355.06 |
|
|
|
212.61 |
|
30
Item 6. Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, unless otherwise noted) |
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006(1) |
|
|
2005 |
|
|
2004(2) |
|
Consolidated Statements of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,365,702 |
|
|
$ |
973,060 |
|
|
$ |
731,536 |
|
|
$ |
560,392 |
|
|
$ |
382,972 |
|
Net income (3) |
|
|
388,396 |
|
|
|
253,147 |
|
|
|
202,457 |
|
|
|
166,471 |
|
|
|
82,448 |
|
Net income
per common share (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
1.59 |
|
|
|
1.05 |
|
|
|
0.87 |
|
|
|
0.74 |
|
|
|
0.38 |
|
Diluted |
|
|
1.54 |
|
|
|
1.00 |
|
|
|
0.82 |
|
|
|
0.70 |
|
|
|
0.36 |
|
Weighted average number of common
shares outstanding
(4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
243,935 |
|
|
|
240,065 |
|
|
|
233,101 |
|
|
|
223,485 |
|
|
|
219,482 |
|
Diluted |
|
|
252,530 |
|
|
|
252,101 |
|
|
|
247,547 |
|
|
|
239,267 |
|
|
|
229,206 |
|
Consolidated Statements of Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used by): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
774,519 |
|
|
$ |
570,214 |
|
|
$ |
461,810 |
|
|
$ |
360,960 |
|
|
$ |
168,652 |
|
Investing activities |
|
|
(994,659 |
) |
|
|
(762,513 |
) |
|
|
(856,627 |
) |
|
|
(383,687 |
) |
|
|
(93,550 |
) |
Financing activities |
|
|
177,102 |
|
|
|
198,533 |
|
|
|
283,601 |
|
|
|
154,777 |
|
|
|
(66,251 |
) |
Production (daily): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
31,436 |
|
|
|
27,925 |
|
|
|
22,936 |
|
|
|
20,013 |
|
|
|
19,247 |
|
Natural gas (Mcf) |
|
|
89,442 |
|
|
|
97,141 |
|
|
|
83,075 |
|
|
|
58,696 |
|
|
|
82,224 |
|
BOE (6:1) |
|
|
46,343 |
|
|
|
44,115 |
|
|
|
36,782 |
|
|
|
29,795 |
|
|
|
32,951 |
|
Unit Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(excluding impact of derivative
settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
92.73 |
|
|
$ |
69.80 |
|
|
$ |
59.87 |
|
|
$ |
50.30 |
|
|
$ |
36.46 |
|
Natural gas (per Mcf) |
|
|
8.56 |
|
|
|
6.81 |
|
|
|
7.10 |
|
|
|
8.48 |
|
|
|
6.24 |
|
Unit Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(including impact of derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
90.04 |
|
|
$ |
68.84 |
|
|
$ |
59.23 |
|
|
$ |
50.30 |
|
|
$ |
27.36 |
|
Natural gas (per Mcf) |
|
|
7.74 |
|
|
|
7.66 |
|
|
|
7.10 |
|
|
|
7.70 |
|
|
|
5.57 |
|
Costs per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
18.13 |
|
|
$ |
14.34 |
|
|
$ |
12.46 |
|
|
$ |
9.98 |
|
|
$ |
7.22 |
|
Production taxes and marketing expenses |
|
|
3.76 |
|
|
|
3.05 |
|
|
|
2.71 |
|
|
|
2.54 |
|
|
|
1.55 |
|
General and administrative |
|
|
3.56 |
|
|
|
3.04 |
|
|
|
3.20 |
|
|
|
2.62 |
|
|
|
1.78 |
|
Depletion, depreciation and amortization |
|
|
13.08 |
|
|
|
12.17 |
|
|
|
11.11 |
|
|
|
9.09 |
|
|
|
8.09 |
|
Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
179,126 |
|
|
|
134,978 |
|
|
|
126,185 |
|
|
|
106,173 |
|
|
|
101,287 |
|
Natural gas (MMcf) |
|
|
427,955 |
|
|
|
358,608 |
|
|
|
288,826 |
|
|
|
278,367 |
|
|
|
168,484 |
|
MBOE (6:1) |
|
|
250,452 |
|
|
|
194,746 |
|
|
|
174,322 |
|
|
|
152,568 |
|
|
|
129,369 |
|
Carbon
dioxide (MMcf) (5) |
|
|
5,612,167 |
|
|
|
5,641,054 |
|
|
|
5,525,948 |
|
|
|
4,645,702 |
|
|
|
2,664,633 |
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,589,674 |
|
|
$ |
2,771,077 |
|
|
$ |
2,139,837 |
|
|
$ |
1,505,069 |
|
|
$ |
992,706 |
|
Total long-term liabilities |
|
|
1,363,539 |
|
|
|
1,102,066 |
|
|
|
833,380 |
|
|
|
617,343 |
|
|
|
368,128 |
|
Stockholders equity (6) |
|
|
1,840,068 |
|
|
|
1,404,378 |
|
|
|
1,106,059 |
|
|
|
733,662 |
|
|
|
541,672 |
|
|
|
|
(1) |
|
Effective January 1, 2006, we adopted Statement of Financial Accounting Standards
No. 123(R), Share Based Payment. |
|
(2) |
|
We sold Denbury Offshore, Inc. in July 2004. |
|
(3) |
|
In 2008, we had a full cost ceiling test write-down of
$226 million ($140.1 million net of tax) and pretax expense of $30.6 million
associated with a cancelled acquisition.
These charges were partially offset by pretax income of $200.1 million on our commodity derivative contracts. |
(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 153.8 Bcf at December 31, 2008, of 182.3 Bcf at December 31, 2007, 210.5
Bcf at December 31, 2006, 237.1 Bcf at December 31, 2005, and 178.7 Bcf at December 31, 2004.
(See Note 15 to the Consolidated Financial Statements). |
|
(6) |
|
We have never paid any dividends on our common stock. |
31
Denbury Resources Inc.
Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion and analysis should be read in conjunction with our Consolidated
Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary
Data. Our discussion and analysis includes forward looking information that involves risks and
uncertainties and should be read in conjunction with Risk Factors under Item 1A of this report,
along with Forward Looking Information at the end of this section for information on the risks and
uncertainties that could cause our actual results to be materially different than our forward
looking statements.
Overview
We are a growing independent oil and gas company engaged in acquisition, development and
exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas
producer in Mississippi, own the largest reserves of carbon dioxide (CO2) used for
tertiary oil recovery east of the Mississippi River, and significant operating acreage in the
Barnett Shale play near Fort Worth, Texas, and also hold 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, with our most significant emphasis relating to
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;
Jackson, Mississippi; and Aledo, Texas.
Liquidity. During the last six months, we have taken several steps to improve our liquidity as
a result of the deterioration in the capital markets and the decrease in oil and natural gas prices
(see Capital Resources and Liquidity).
2008 Operating Highlights. Oil and natural gas prices were extremely volatile during 2008,
with NYMEX oil prices setting a record high of approximately $145 per Bbl around mid-year, followed
by a rapid drop during the second half of the year to below $40 per Bbl, a price level not seen
since 2004, finishing the year at $44.60 per Bbl. Natural gas prices followed a similar trend in
2008, beginning the year at $7.48 per Mcf, increasing to approximately $13.60 per Mcf in mid-2008,
and then ending 2008 at slightly under $6.00 per Mcf. See the charts below for further information
on the fluctuations in oil and natural gas prices during 2008.
In spite of the commodity price volatility, our average revenue per BOE for the year was
$79.42, approximately 34% higher than 2007s average of $59.17 per BOE. These higher prices were a
significant contributor to our record cash flow and earnings. Our 2008 cash flow from operations
was $774.5 million, a 36% increase over our 2007 annual cash flow from operations of $570.2
million, and our 2008 net income of $388.4 million was 53% higher than our $253.1 million of net
income during 2007. In addition to higher commodity prices during 2008, we had record high
production levels, partially offset by higher operating costs and a $30.6 million charge related to
the cancellation of the Conroe Field acquisition in early October (see also Capital Resources and
Liquidity below). During 2008, we also had two significant non-cash operational items, (i) a net
gain of $257.6 million ($159.7 million net of tax) associated with our fair value adjustments on
our derivative contracts, the majority of which were related to the 2009 oil price collars acquired
in October 2008, and (ii) a full cost ceiling write-down at December 31, 2008, of $226.0 million
($140.1 million net of tax) incurred because of the significant decrease in oil and natural gas
prices during the latter part of 2008.
32
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
During 2008 our oil and natural gas production averaged 46,343 BOE/d, an 18% increase over our
2007 average production (after adjusting for the sale of our Louisiana natural gas properties in
December 2007 and February 2008), with growth primarily from our tertiary oil operations and
Barnett Shale, partially offset by modest declines in our East Mississippi non-tertiary production.
Our average tertiary oil production increased to 19,377 BOE/d in 2008, a 31% increase over our 2007
tertiary oil production levels, and our average Barnett Shale production increased to 12,699 BOE/d,
a 33% increase year-over-year. (See Results of Operations Operating Results Production for
more information). Our oil and natural gas revenues increased 41% in 2008, with 5% of the increase
associated with the higher production levels and 36% of the increase due to higher oil and natural
gas commodity prices.
Our operating costs have gradually increased over the last few years along with commodity
prices; the cost inflation caused by a corresponding increase in the demand for goods and services
in our business as a result of commodity price escalation. While we recognized some cost savings
during the last quarter of 2008 following the sharp decline in commodity prices during the second
half of the year, operating costs have not decreased at the same rate as commodity prices.
Therefore on average, virtually all of our expenses increased on both an absolute and per BOE basis
during 2008. This continued a trend that we have experienced over the last several years as our
costs have been increasing, due to (i) higher overall industry costs, (ii) a higher percentage of
operations related to tertiary operations (which have higher operating costs per BOE), and (iii)
higher compensation expense resulting from additional employees and increased salaries, which we
consider necessary in order to remain competitive in the industry. We expect to see further cost
reductions in 2009, as we believe that lower spending levels in the industry will reduce demand for
goods and services and eventually lower costs, but it is uncertain how quickly costs will come down
and by how much.
We invested approximately $1.1 billion in capital projects and minor acquisitions during 2008,
of which approximately $462.9 million was spent on CO2 pipelines, facilities and
drilling. During 2008 our proved oil and natural gas reserves increased from 194.7 MMBOE as of
December 31, 2007 to 250.5 MMBOE at December 31, 2008, replacing approximately 525% of our 2008
production, almost entirely from organic growth. The most significant reserve additions during
2008 were approximately 63.4 MMBbls added in our tertiary oil operations, primarily associated with
the booking of proved tertiary reserves at Tinsley, Heidelberg and Lockhart Crossing Fields, and
19.5 MMBOE added in our Barnett Shale operations.
Genesis Transactions. On May 30, 2008, we closed two transactions with Genesis Energy, L.P.
(Genesis) involving our Northeast Jackson Dome (NEJD) and Free State CO2 Pipelines,
which included a long-term transportation service arrangement for the Free State Pipeline and a
20-year financing lease for the NEJD system. We received from Genesis $225 million in cash and $25
million of Genesis common units (1,199,041 units at an average price of $20.85 per unit). These
transactions were treated as financing leases for accounting purposes, with the assets and
liabilities recorded on our balance sheet. We currently project that we will initially pay Genesis
approximately $30 million per annum under the financing lease and transportation services
agreement, with future payments for the NEJD pipeline fixed at $20.7 million per year during the
term of the financing lease, and the payments relating to the Free State Pipeline dependent on the
volumes of CO2 transported therein, with a minimum annual payment thereon of $1.2
million.
Change in Tax Accounting Method for Certain Tertiary Costs. During the third quarter of 2008,
we obtained approval from the Internal Revenue Service (IRS) to change our method of tax
accounting for certain assets used in our tertiary oilfield recovery operations. Previously, we
had capitalized and depreciated these costs, but now we can deduct these costs once the assets are
placed into service. As a result, we expect to receive tax refunds of approximately $10.6 million
for tax years through 2007, along with other tax benefits, and we have reduced our current income
tax expense and increased our deferred income tax expense in 2008 to adjust for the impact of this
change. This change is not expected to have a significant impact on our overall tax rate; however,
it will allow for a quicker deduction of costs for tax purposes.
This change in tax treatment impacts the overall economics of certain financing-type
transactions we have historically utilized, primarily equipment lease financing and certain
transactions with Genesis. Following the favorable ruling, we initially discontinued our leasing
program and pipeline financings with Genesis, but with the recent downturn in commodity prices, we
anticipate that our cash income taxes for 2009 will be minimal, minimizing the effect of this
change in tax accounting. With lower projected cash income taxes expected for the near future, and
given the generally advantageous interest rate inherent in equipment lease transactions, and their
being an alternative source of liquidity, we plan to resume our equipment leasing program in 2009
and budgeted
33
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
$100 million of leasing in 2009, but if possible, we would like to lease as much as $150 million.
Because of the uncertainties that exist in the capital markets, we cannot be certain of the dollar
amount, pricing or availability of such equipment financing leases.
The economic impact of our acceleration of tax deductions will also affect how we view future
asset transactions with Genesis. Transactions which are not sales for tax purposes, such as the
$175 million financing lease on the NEJD CO2 Pipeline (see Overview Genesis
Transactions above) would not be affected provided that they meet other necessary tax criteria.
Those transactions which constitute a sale for tax purposes, such as the $75 million sale and
associated long-term transportation service agreement entered into with Genesis on our Free State
CO2 Pipeline (see Overview Genesis Transactions above), will be less advantageous
from a tax perspective.
Sale of Louisiana Natural Gas Assets. In February 2008, we received the $48.9 million
remaining portion (30%) of the proceeds from the sale of our Louisiana natural gas assets, the
prior 70% of which closed in December 2007. Production attributable to the sold properties
averaged 302 BOE/d (approximately 81% natural gas) during the first quarter of 2008, representing
production prior to the closing date for the portion of the sale that closed in February.
Recent 2009 Transactions
Purchase of Hastings Field. On February 2, 2009, we closed the $201 million acquisition of
the Hastings Field, which is located near Houston, Texas, and is a potential tertiary oil field to
be supplied by the Green CO2 Pipeline which has commenced construction. In August 2008,
we exercised our option with a subsidiary of Venoco, Inc. (Venoco) to purchase Hastings Field,
and in consideration of our exercising the option in 2008 rather than 2009, Venoco agreed to extend
the deadlines for capital expenditures, commencement of CO2 injections and certain other
contractual requirements by one year.
Management Succession Plan. On February 5, 2009, our Board of Directors adopted a management
succession plan under which our current executive officers will assume new roles on or about June
30, 2009. Gareth Roberts, the Companys founder, will relinquish his position as President and CEO
and become Co-Chairman of the Board of Directors and will assume a non-officer role as the
Companys Chief Strategist. Phil Rykhoek, currently Senior Vice President and Chief Financial
Officer, will become CEO; Tracy Evans, currently Senior Vice President Reservoir Engineering,
will become President and Chief Operating Officer; and Mark Allen, currently Vice President and
Chief Accounting Officer, will become Senior Vice President and Chief Financial Officer.
Subordinated Debt Issuance. On February 13, 2009, we issued $420 million of 9.75% Senior
Subordinated Notes due 2016 (the Notes). The Notes were sold to the public at 92.816% of par,
plus accrued interest from February 13, 2009, which equates to an effective yield to maturity of
approximately 11.25% (before offering expenses). Interest on the Notes will be paid on March 1 and
September 1 of each year, beginning September 1, 2009. The Notes will mature on March 1, 2016. We
used the net proceeds from the offering of approximately $381 million to repay most of the then
outstanding debt on our bank credit facility.
Capital Resources and Liquidity
During the last six months, we have taken several steps to improve our liquidity as a result
of the deterioration in the capital markets and the decrease in oil and natural gas commodity
prices. These included a $400 million increase to our bank commitment amount (see Increased Bank
Credit Line below for more details), cancellation of the $600 million acquisition of Conroe Field,
purchase of oil derivative contracts covering approximately 80% of our currently estimated
2009 oil production, and reduction of our capital budget for 2009. Also, in February 2009, we
issued $420 million of Senior Subordinated Notes (see Overview Recent 2009 Transactions
Subordinated Debt Issuance).
Prior to the decline in economic conditions, we had intended, in a tax free exchange, to
exchange the Barnett Shale properties for the Conroe and Hastings Fields, both of which are future
tertiary flood candidates located near Houston, Texas. However, because of the deterioration in
capital market conditions, we believed that the sale of our Barnett Shale properties at a price
that we would consider reasonable was doubtful, and without the certainty of a Barnett Shale
property sale, we did not feel comfortable increasing our leverage. As such, we cancelled our $600
million contract to purchase Conroe Field, forfeiting a $30 million non-refundable deposit which we
expensed in the third quarter. To further protect our liquidity in the event that commodity prices
continued to decline, in October
34
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
2008 we purchased oil derivative contracts for 2009 with a floor price of $75 / Bbl and a ceiling
price of $115 / Bbl for total consideration of $15.5 million. The collars cover 30,000 Bbls/d
representing approximately 80% of our currently anticipated 2009 oil production. See Oil and
Natural Gas Derivative Contracts below in this section for information regarding the
counterparties for these collars. We further significantly increased our liquidity in February
2009 by issuing $420 million of subordinated debt. We used net proceeds from that offering ($381
million) to repay most of our then outstanding bank debt, freeing-up most of our bank credit line
for future capital needs, as our total bank commitment amount of $750 million was not reduced
because of the offering.
We currently estimate that our 2009 total capital spending will be approximately $750 million,
plus the already closed Hastings acquisition of $201 million. Our current 2009 capital budget
includes approximately $485 million relating to our CO2 pipelines, the majority of which
is to build the Green CO2 Pipeline. The budget also assumes that we fund approximately
$100 million of budgeted equipment purchases with operating leases, a practice we had discontinued
in the last half of 2008 as a result of our favorable tax ruling (see Overview Change in Tax
Accounting Method for Certain Tertiary Costs). Use of these operating leases is dependent upon
being able to secure acceptable financing and as of February 27, 2009, we had not yet secured most
of this financing. The 2009 budget incorporates significantly reduced spending in the Barnett
Shale and in other conventional areas such as the Heidelberg Selma Chalk, and a slower development
program for our tertiary operations. Based on our current cash flow projections, using $50.00 per
barrel for oil and $5.00 per Mcf for natural gas prices and including our expected oil derivative
contract settlements, we anticipate that our capital expenditures could exceed projected cash flow
by $400 million to $500 million, including the Hastings acquisition.
We anticipate funding this shortfall during 2009 with the proceeds from our February 2009
subordinated debt issuance and our bank credit line, and expect to have a total bank debt balance
by the end of 2009 of $150 million to $250 million, leaving us $500 million to $600 million of
availability on our $750 million bank commitment amount. We anticipate that this credit line will
be sufficient to fund our 2009 plans and do not expect our bank credit line to be reduced by our
banks unless commodity prices were to further decrease significantly
from current levels. We may raise additional capital
during 2009 if it is possible to do so in a reasonably economic manner. Such additional capital
sources could include the sale or joint venture of assets, a volumetric production payment,
additional operating leases, or other options that become available during the year. We will also
continually monitor our capital expenditures on a regular basis, adjusting them up or down
depending on commodity prices and the resultant cash flow. Therefore, should our cash flow be less
than expected, we would plan to reduce our capital expenditures to the extent possible during the
year, which could in turn, have the impact of reducing our anticipated production levels in future
years. For 2009, we have contracted for certain capital expenditures, including construction of
most of the Green Pipeline already in progress and two drilling rigs, and therefore the portion of
capital that we could eliminate without significant penalty is limited (see also Off-Balance Sheet
Arrangements Commitments and Obligations).
Based on our long-term models, we expect our future capital spending needs to be less in the
future than they have been in recent years, excluding any potential acquisitions. Therefore, if
commodity prices remain at current levels after 2009, we anticipate that we will be able to match
our capital spending with our projected cash flow from operations and preserve our liquidity to the
extent that we deem necessary, although any such spending reductions would most likely lower our
anticipated rate of production growth.
Increased Bank Credit Line. In early October 2008, we amended our bank credit facility, which
increased the banks commitment amount from $350 million to $750 million, maintained our borrowing
base at $1.0 billion, modified the commitment fees and pricing grid for the loan, raising the
pricing grid by 25 basis points, and provided for other transactions, such as the acquisition of
Conroe Field, which were not consummated. The borrowing base represents the amount that can be
borrowed from a credit standpoint while the commitment amount is the amount the banks have
committed to fund pursuant to the terms of the credit agreement. We further amended our bank
credit facility in February 2009 to allow us to issue the subordinated debt at an interest rate
higher than the previously allowed 10% (see Overview Recent 2009 Transactions Subordinated
Debt Issuance).
While bank borrowing bases in our industry are likely to be reduced in the future to reflect
the reduction in commodity prices, with $250 million of cushion between our borrowing base and
commitment amount and the incremental value added by retaining our Barnett Shale properties,
currently we do not expect our bank commitment level to be reduced below $750 million unless prices
were to further decrease significantly from current strip prices of approximately $45.00 per barrel
for oil and $5.00 per Mcf for natural gas. As of February 27, 2009, we had
35
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
outstanding $525 million (principal amount) of 7.5% subordinated notes, $420 million (principal
amount) of 9.75% Senior Subordinated Notes and $60 million of bank debt.
Although we remain interested in acquiring mature oil fields that we believe have potential as
future tertiary flood candidates, with the general lack of liquidity in the capital markets, our
ability to fund any significant acquisitions will be limited and are not likely to be material
unless we are able to obtain additional capital.
Sources and Uses of Capital Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditure Summary |
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands |
|
2008 |
|
|
2007 |
|
|
2006 |
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas exploration and development |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
$ |
244,841 |
|
|
$ |
313,258 |
|
|
$ |
245,350 |
|
Geological, geophysical and acreage |
|
|
18,183 |
|
|
|
22,829 |
|
|
|
31,590 |
|
Facilities |
|
|
170,263 |
|
|
|
118,003 |
|
|
|
98,890 |
|
Recompletions |
|
|
140,451 |
|
|
|
141,264 |
|
|
|
120,438 |
|
Capitalized interest |
|
|
17,627 |
|
|
|
18,305 |
|
|
|
11,059 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas exploration and development expenditures |
|
|
591,365 |
|
|
|
613,659 |
|
|
|
507,327 |
|
Oil and natural gas property acquisitions |
|
|
31,367 |
|
|
|
49,077 |
|
|
|
319,000 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
622,732 |
|
|
|
662,736 |
|
|
|
826,327 |
|
CO2 capital expenditures, including capitalized interest |
|
|
462,889 |
|
|
|
171,182 |
|
|
|
63,586 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,085,621 |
|
|
$ |
833,918 |
|
|
$ |
889,913 |
|
|
|
|
|
|
|
|
|
|
|
Our 2008 capital expenditures were funded with $774.5 million of cash flow from operations,
$225 million from the drop-down of CO2 pipelines to Genesis, and $51.7 million from
property sales proceeds.
Our 2007 capital expenditures were funded with $570.2 million of cash flow from operations,
$150.0 million from the April 2007 issuance of subordinated debt, $135.8 million from property
sales proceeds, and $16.0 million of net bank borrowings.
Our 2006 expenditures were funded with $461.8 million of cash flow from operations, $139.8
million of equity issued, $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.
Off-Balance Sheet Arrangements
Commitments and Obligations
At December 31, 2008, our dollar denominated payment obligations that are not on our balance
sheet include our operating leases, which at year-end 2008 totaled $128.6 million (including $104.5
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. At December 31, 2008, we had a total of
$10.5 million of letters of credit outstanding under our bank credit agreement. Additionally, we
have dollar denominated 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.
Genesis Energy, LLC, our subsidiary that is the general partner of Genesis (a limited
partnership), could under certain circumstances become liable, in its capacity as general partner,
for debts and obligations of Genesis. There were no guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, LLC at December 31, 2008.
36
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
During the
second quarter of 2008, we entered into transactions with Genesis relating to two of our
CO2 pipelines (see Overview Genesis Transactions above). As a result of these two
transactions, we currently project that we will initially pay Genesis approximately $30 million per
annum under the financing lease and transportation services agreement (a pro-rated total of $15.4
million during 2008), with future payments for the NEJD pipeline fixed at $20.7 million per year
during the term of the financing lease, and the payments relating to the Free State Pipeline
dependent on the volumes of CO2 transported therein, with a minimum annual payment
thereon of $1.2 million.
We currently have long-term commitments to purchase CO2 from four
proposed gasification plants, two of which are in the Gulf Coast region and two in the Midwest
region (Illinois / Kentucky area) of the United States. The Midwest plants are not only
conditioned on those specific plants being constructed, but also upon Denbury contracting
additional volumes of
CO2
for purchase in the general area of the proposed plants that
would provide an acceptable economic return on the CO2
pipeline that we would need to construct to transport these volumes to our existing CO2
pipeline system. If all four plants are built, these CO2 sources are currently
anticipated to provide us with aggregate CO2 volumes of around 1 Bcf/d. Due to the
current economic conditions, the earliest we would expect any plant to be completed and provide
CO2 would be 2013, and there is some doubt as to whether they will be constructed at
all. The base price of CO2 per Mcf from these CO2 sources varies by plant
and location, but is generally higher than our most recent all-in cost of CO2 from our
natural sources (Jackson Dome) using current oil prices. Prices for CO2 delivered from
these projects are expected to be competitive with the cost of our natural CO2 after
adjusting for our share of potential carbon emissions reduction credits using estimated futures
prices of carbon emissions reduction credits. If all four plants are built, the aggregate purchase
obligation for this CO2 would be around $135 million per year, assuming a $50 per barrel
oil price, before any potential savings from our share of carbon emissions reduction 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. While it is likely that not every plant
currently under contract will be constructed, there are several other plants under consideration
that could provide CO2 to us that would either supplement or replace the CO2
volumes from the four proposed plants that we currently have contracts with. We are having ongoing
discussions and negotiations with several of these other potential sources. We have not included
any financial commitment attributable to the existing contracts or other potential sources in the
commitment table below as all such payments are contingent on the plants being built.
A summary of our obligations at December 31, 2008, is presented in the following table:
|
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|
|
|
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|
|
|
|
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|
|
|
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|
|
|
|
|
Payments Due by Period |
Amounts in thousands |
|
Total |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
Thereafter |
|
|
Contractual
Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated debt (a) |
|
$ |
525,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
225,000 |
|
|
$ |
300,000 |
|
Senior Bank Loan (a) |
|
|
75,000 |
|
|
|
|
|
|
|
|
|
|
|
75,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated interest payments on
subordinated debt and Senior Bank Loan (a) |
|
|
234,096 |
|
|
|
41,588 |
|
|
|
41,588 |
|
|
|
40,933 |
|
|
|
39,375 |
|
|
|
26,661 |
|
|
|
43,951 |
|
Pipeline financing lease obligations (b) |
|
|
588,414 |
|
|
|
29,358 |
|
|
|
31,759 |
|
|
|
33,205 |
|
|
|
33,438 |
|
|
|
33,518 |
|
|
|
427,136 |
|
Operating lease obligations |
|
|
128,606 |
|
|
|
17,938 |
|
|
|
17,351 |
|
|
|
16,571 |
|
|
|
15,199 |
|
|
|
12,510 |
|
|
|
49,037 |
|
Capital lease obligations (c) |
|
|
9,219 |
|
|
|
2,120 |
|
|
|
1,882 |
|
|
|
1,882 |
|
|
|
1,242 |
|
|
|
700 |
|
|
|
1,393 |
|
Capital expenditure obligations (d) |
|
|
376,827 |
|
|
|
367,980 |
|
|
|
8,847 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Cash Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future development costs on proved oil and gas
reserves, net of capital obligations (e) |
|
|
890,262 |
|
|
|
97,048 |
|
|
|
312,069 |
|
|
|
188,275 |
|
|
|
115,605 |
|
|
|
61,921 |
|
|
|
115,344 |
|
Future development cost on proved CO2
reserves, net of capital obligations (f) |
|
|
116,792 |
|
|
|
18,792 |
|
|
|
|
|
|
|
22,000 |
|
|
|
|
|
|
|
|
|
|
|
76,000 |
|
Asset retirement obligations (g) |
|
|
106,413 |
|
|
|
2,154 |
|
|
|
1,321 |
|
|
|
1,288 |
|
|
|
722 |
|
|
|
1,013 |
|
|
|
99,915 |
|
|
Total |
|
$ |
3,050,629 |
|
|
$ |
576,978 |
|
|
$ |
414,817 |
|
|
$ |
379,154 |
|
|
$ |
205,581 |
|
|
$ |
361,323 |
|
|
$ |
1,112,776 |
|
|
(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. On February 13, 2009 we issued
$420 million of 9.75% Senior Subordinated Notes at a discount, 92.816% of par, for which the obligations
related thereto are not included in the above table. See Note 14 to the Consolidated Financial Statements. |
37
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
(b) |
|
Represents estimated future cash payments under a long-term transportation service agreement
for the Free State Pipeline, and future minimum cash payments in a 20-year financing lease for
the NEJD pipeline system. Both transactions with Genesis were entered into in 2008 and are
being accounted for as financing leases. The payment required for the Free State Pipeline is
variable based upon the amount of the CO2 we ship through the pipeline and the
commitment amounts disclosed above for that line are computed based upon our internal
forecasts. Approximately $338.2 million of these payments represent interest. See Note 3 to
Consolidated Financial Statements. |
|
(c) |
|
Represents future minimum cash commitments of $5.9 million to Genesis under capital leases in
place at December 31, 2008, primarily for transportation of crude oil and CO2, and
$3.3 million for office space and rental equipment. Approximately $2.0 million of these
payments represents interest. |
|
(d) |
|
Represents future cash commitments under contracts in place as of December 31, 2008,
primarily for pipe, pipeline construction contracts, drilling rig services and well related
costs, including approximately $311.2 million for our Green CO2 Pipeline. 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 2009 is currently set at $750
million, exclusive of acquisitions. 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. |
|
(e) |
|
Represents projected capital costs as scheduled in our December 31, 2008 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, 2008 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 $45.1 million, as determined under SFAS No.
143, and is further discussed in Note 4 to the Consolidated Financial Statements. |
During February 2009, we closed our $201 million purchase of Hastings Field (see Recent
2009 Transactions Purchase of Hastings Field above). Under the agreement, we are required to
make aggregate net capital expenditures in this field of approximately $179 million over the next
six years as follows (the following amounts representing cumulative amounts required by that date):
$26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by December
31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If we fail
to spend the required amounts by the due dates, we are required to make a cash payment equal to 10%
of the cumulative shortfall at each applicable date. Further, we are committed to injecting at
least an average of 50 MMcf/day of CO2 (total of purchased and recycled) in the West
Hastings Unit for the 90 day period prior to January 1, 2013. If such injections do not occur, we
must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign to
Venoco all assets previously purchased for the value of such assets at that time based upon the
discounted value of the fields proved reserves using a 20% discount rate, or (2) make an
additional payment of $20 million in January 2013, less any payments made for failure to meet the
capital spending requirements as of December 31, 2012, and a $30 million payment for each
subsequent year (less amounts paid for capital expenditure shortfalls) until the CO2
injection in the Hastings Field equals or exceeds the minimum required injection rate.
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 512 Bcf of
CO2 on a cumulative basis to these customers over the next 19 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 254 Bcf. The maximum volume required in any given year is approximately
136 MMcf/d, although based on our current level of deliveries this would likely be reduced to
approximately 78 MMcf/d. Given the size of our proven CO2 reserves at December 31, 2008
(approximately 5.6 Tcf before deducting approximately 153.8 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.
38
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
CO2 Operations
Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999,
we have gradually increased our emphasis on these types of operations. During this time, we have
learned a considerable amount about tertiary operations and working with carbon dioxide. Our
tertiary operations have grown to the point that approximately 50% of our December 31, 2008 proved
reserves are proved tertiary oil reserves, almost 50% of our forecasted 2009 production is expected
to come from tertiary oil operations (on a BOE basis), and almost all of our 2009 capital
expenditures are related to our current or future tertiary 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
(we estimate our economic break-even per barrel dollar cost on these projects at current oil prices
is in the range of the mid-twenties, 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. In addition, we are pursuing
anthropogenic (man-made) sources of CO2 to use in our tertiary operations, which we
believe will not only help us recover additional oil, but will provide an economical way to
sequester CO2. We have acquired several old oil fields in our areas of operations with
potential for tertiary recovery and plan to acquire additional fields, and we are continuing to
expand our CO2 pipeline infrastructure to transport CO2.
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 is anticipated to 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 320-mile CO2 pipeline which will run from
Southern Louisiana to near Houston, Texas, and is scheduled for completion in 2010. Hastings
Field, a field which we purchased in February 2009 (see Commitments and Contingencies), is our
Phase VII, and the Seabreeze Complex, acquired in 2007, will be our Phase VIII.
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 of the acquisition to approximately
5.6 Tcf as of December 31, 2008. During 2008, the increase in our proven CO2 reserves
was offset by the 233 Bcf of CO2 production during the year. 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 all of these uses. We currently estimate that it will take approximately 1.8 Tcf of
CO2 to develop and produce the proved tertiary recovery reserves we have recorded at
December 31, 2008, in Phases I, II and III.
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, Louisiana
and Texas that could be further exploited through tertiary recovery. As of February 27, 2009, we
estimate that we are capable of producing between 900 MMcf/d and 1 Bcf/d of CO2, over
eight 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 one more well planned for 2009, in
order to further increase our production capacity. Our drilling activity at Jackson Dome will
continue beyond 2009 as our current forecasts for the existing eight phases suggest that we will
need approximately 1.4 Bcf/d of CO2 production by 2013.
39
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 volumetric production
payments for the CO2.
Our average daily CO2 production during 2006, 2007 and 2008 was approximately 342
MMcf/d, 493 MMcf/d and 637 MMcf/d, respectively, of which approximately 75% in 2006, 81% in 2007
and 86% in 2008 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 $0.22 per Mcf in operating expenses to produce our CO2
during 2008, more than our 2007 average of $0.21 per Mcf and our 2006 average of $0.19 per
Mcf, with the higher costs each year primarily due to higher average oil costs, which is the basis
upon which we pay royalty owners for the CO2, and higher operating costs. Our CO2
costs peaked at $0.27 per Mcf in the second quarter of 2008, corresponding to the peak in oil
prices, but decreased during the fourth quarter of 2008 to an average of approximately $0.15 per
Mcf as a result of the decline in oil prices. Our estimated total cost per thousand cubic feet of
CO2 during 2008 was approximately $0.30, after inclusion of depreciation and
amortization expense related to the CO2 production, as compared to approximately $0.29
per Mcf during 2007 and $0.28 per Mcf during 2006.
Man-Made CO2 Sources. In addition to our natural source of CO2, we are
in discussions with the owners of several proposed solid carbon gasification plants which, if
constructed, will convert coal or petroleum coke into various other products, with CO2
being a significant by-product of the process. If built, these plants could provide us with
significant additional sources of CO2 in the future which would enable us to further
expand our tertiary operations, although the earliest date this CO2 is expected to be
available to us is in 2013. These plants have all been delayed due to current economic conditions
and it is uncertain, when, if ever, these plants will be built. We have entered into long-term
commitments to purchase CO2 from four proposed plants (see Commitments and
Obligations), which, if all four plants are built, are currently anticipated to provide us with an
aggregate of approximately 1 Bcf/d of CO2. In addition to the proposed gasification
plants, we have ongoing discussions with existing plants of various types that emit CO2
and we may be able to purchase their volumes. In order to capture such volumes, we (or the
plant owner) would need to install additional equipment, which include at a minimum, compression
and dehydration facilities. Most of these existing plants emit relatively small volumes of
CO2, generally less than the proposed gasification plants, but such volumes
may still be attractive if the source is located near our Green CO2 Pipeline. The
capture of CO2 could also be influenced by anticipated federal legislation, which could
impose economic penalties for the emission of CO2. We believe that we are a likely
purchaser of CO2 produced in our area of operations because of the scale of our tertiary
operations, our CO2 pipeline infrastructure, and the large natural source of
CO2 (Jackson Dome), which can act as a swing CO2 source to balance
CO2 supplies and demands.
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,
but we expect them to be reduced during 2009, and to be at economic break-even dollar costs in the
mid-twenties per barrel if oil prices remain at their current reduced level, 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, 2008, are approximately
$11.30 per BOE. Currently, we forecast that most of these costs will average less than $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, and other
factors, as the finding and development costs to date do not include significant unproven potential
reserves in most of the fields. Our operating costs for tertiary operations are highly dependent
on commodity prices and could range from $15 to $25 per BOE over the life of each field, 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 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.
40
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 can be 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). Since a significant portion of our operating costs vary along with
commodity and electrical prices, these costs are highly variable and will increase in a high
commodity price environment and decrease in a low price environment. As an example (as discussed
above), during 2008, the cost of our CO2 varied from $0.15 per Mcf to $0.27 per Mcf.
Most of our CO2 operating costs are allocated to our tertiary oil fields and recorded as
lease operating expenses or capitalized to those fields at the time the CO2 is injected,
and these costs have historically represented over 25% of the total operating costs for a tertiary
operation. Since we expense all of the operating costs to produce and inject our CO2
(following the commencement of tertiary oil production), the operating costs per barrel will be
higher at the inception of CO2 injection projects because of minimal related oil
production at that time.
Analysis of CO2 Tertiary Recovery Operating Activities. We currently have tertiary
operations ongoing at almost all Phase I fields, at Soso, Martinville, Eucutta and Heidelberg
Fields in Phase II, Tinsley Field in Phase III, and Cranfield (Phase IV). 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, 2008, we had approximately 125.8 MMBbls of proven oil reserves related to tertiary
operations (50.0 MMBbls in Phase I, 41.4 MMBbls in Phase II and 34.4 MMBbls in Phase III)
representing about 50% of our total corporate proved reserves, and have identified and estimate
significant additional oil potential in other fields that we own in this region.
We added 63.4 MMBbls of tertiary-related proved oil reserves during 2008, primarily initial
proven tertiary oil reserves at Heidelberg Field (Phase II),
Tinsley Field (Phase III) and Lockhart Crossing Field (Phase I). In
order to recognize proved tertiary oil reserves, we must either have an oil production response to
the CO2 injections or the field must be analogous to an existing tertiary flood. 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 19,377 Bbls/d during 2008 (21,874
Bbls/d during the fourth quarter of 2008). Tertiary oil production represented approximately 62%
of our total corporate oil production during 2008 and approximately 42% 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 usually does not indicate any issue with the proved
and potential oil reserves recoverable with CO2, because the historical correlation
between oil production and CO2 injections remains high. A detailed discussion of each of
our tertiary oil fields and the development of each is included on
pages 8-11 under Our Tertiary
Oil Fields With Proved Tertiary Reserves. Following is a chart with our tertiary oil production
by field for 2006 and 2007, and by quarter for 2008. In 2008, we had initial production response
from our tertiary floods at Lockhart Crossing Field and Tinsley Field, and we saw continued
improved response from our newer Phase II floods at Martinville, Eucutta and Soso Fields, most of
which were initiated during 2006. We initiated CO2 injections at Cranfield Field in
July 2008 and at Heidelberg Field in December 2008. We anticipate our first response and sales
from the Cranfield CO2 injections in the first quarter of 2009 and from the Heidelberg
Field injections in the second half of 2009. One of our Phase I fields, Little Creek, is a mature
flood and is expected to continue its gradual decline over the next several years. Production at
another Phase I field, Mallalieu, appears to have plateaued and is not expected to increase during
2009.
41
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
|
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
Year Ended December 31, |
Tertiary Oil Field |
|
2008 |
|
|
2008 |
|
|
2008 |
|
|
2008 |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
2,638 |
|
|
|
2,714 |
|
|
|
2,772 |
|
|
|
3,178 |
|
|
|
|
2,826 |
|
|
|
2,048 |
|
|
|
833 |
|
Little Creek area |
|
|
1,807 |
|
|
|
1,661 |
|
|
|
1,556 |
|
|
|
1,706 |
|
|
|
|
1,683 |
|
|
|
2,014 |
|
|
|
2,739 |
|
Mallalieu area |
|
|
6,099 |
|
|
|
6,260 |
|
|
|
5,339 |
|
|
|
5,056 |
|
|
|
|
5,686 |
|
|
|
5,852 |
|
|
|
5,210 |
|
McComb area |
|
|
1,632 |
|
|
|
1,818 |
|
|
|
2,061 |
|
|
|
2,092 |
|
|
|
|
1,901 |
|
|
|
1,912 |
|
|
|
1,235 |
|
Lockhart Crossing |
|
|
|
|
|
|
|
|
|
|
182 |
|
|
|
555 |
|
|
|
|
186 |
|
|
|
|
|
|
|
|
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
793 |
|
|
|
715 |
|
|
|
736 |
|
|
|
1,213 |
|
|
|
|
865 |
|
|
|
709 |
|
|
|
6 |
|
Eucutta |
|
|
2,699 |
|
|
|
2,933 |
|
|
|
3,262 |
|
|
|
3,538 |
|
|
|
|
3,109 |
|
|
|
1,646 |
|
|
|
47 |
|
Soso |
|
|
1,488 |
|
|
|
1,885 |
|
|
|
2,358 |
|
|
|
2,704 |
|
|
|
|
2,111 |
|
|
|
586 |
|
|
|
|
|
Phase III: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
|
|
|
|
675 |
|
|
|
1,518 |
|
|
|
1,832 |
|
|
|
|
1,010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tertiary oil
production |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
19,377 |
|
|
|
14,767 |
|
|
|
10,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition to higher electrical 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 six years we have leased certain equipment
that qualifies for operating lease treatment representing an underlying aggregate cost of
approximately $104.5 million as of December 31, 2008. 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 gradually increased through mid-2008, as oil prices
increased (see CO2 Resources above), with all of these items causing our lease
operating expense for our tertiary operations to peak at $26.81 per Bbl in the third quarter of
2008, before declining along with the drop in oil prices in the latter part of 2008 to an average
of $21.86 per Bbl during the fourth quarter of 2008. Our total tertiary operating expenses and
cost per barrel for each of the last three years are set forth in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
Tertiary operating expenses
(thousands) |
|
$ |
167,156 |
|
|
$ |
106,541 |
|
|
$ |
65,028 |
|
Tertiary operating expenses per Bbl |
|
|
23.57 |
|
|
|
19.77 |
|
|
|
17.69 |
|
Through December 31, 2008, we have invested a total of $1.4 billion in tertiary fields
(including allocated acquisition costs) and have only $105.3 million in unrecovered net cash flow
(revenue less operating expenses and capital expenditures). Of this total invested amount,
approximately $229.6 million (17%) was spent on fields which had little or no proved reserves at
December 31, 2008 (i.e., fields for which significant incremental proved reserves are anticipated
during 2009 and beyond). The proved oil reserves in our CO2 fields have a PV-10 Value
of $1.0 billion, using December 31, 2008, constant NYMEX pricing of $44.60 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.
CO2 Source Field-Related Capital Budget for 2009. Tentatively, we plan to spend
approximately $52 million in 2009 in the Jackson Dome area with the intent to add deliverability
for future operations. Approximately $138 million in capital expenditures is budgeted in 2009 at
the oil field level in Phases I through V, plus an additional $485 million for our Delta and Green
CO2 Pipelines, making our combined CO2 related expenditures just over 90% of
our $750 million 2009 capital budget (excluding the Hastings Field purchase).
42
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Operating Results
Net income and cash flow from operations have increased each year during the last three years.
Production increased 5% between 2007 and 2008 (net of the production that was sold), and 20%
between 2006 and 2007 which, coupled with higher prices, resulted in record annual net income and
cash flow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Amounts in Thousands, Except Per Share Amounts |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Net income |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
|
$ |
202,457 |
|
Net income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.59 |
|
|
$ |
1.05 |
|
|
$ |
0.87 |
|
Diluted |
|
|
1.54 |
|
|
|
1.00 |
|
|
|
0.82 |
|
|
Cash flow from operations |
|
$ |
774,519 |
|
|
$ |
570,214 |
|
|
$ |
461,810 |
|
|
43
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Certain of our operating statistics for each of the last three years are set forth in the
following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
31,436 |
|
|
|
27,925 |
|
|
|
22,936 |
|
Mcf/d |
|
|
89,442 |
|
|
|
97,141 |
|
|
|
83,075 |
|
BOE/d (1) |
|
|
46,343 |
|
|
|
44,115 |
|
|
|
36,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
1,066,917 |
|
|
$ |
711,457 |
|
|
$ |
501,176 |
|
Natural gas sales |
|
|
280,093 |
|
|
|
241,331 |
|
|
|
215,381 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
1,347,010 |
|
|
$ |
952,788 |
|
|
$ |
716,557 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts (in thousands) (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlements of derivative contracts |
|
$ |
(57,553 |
) |
|
$ |
20,480 |
|
|
$ |
(5,302 |
) |
Non-cash fair value adjustment income (expense) |
|
|
257,606 |
|
|
|
(39,077 |
) |
|
|
25,130 |
|
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and natural gas derivative contracts |
|
$ |
200,053 |
|
|
$ |
(18,597 |
) |
|
$ |
19,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
307,550 |
|
|
$ |
230,932 |
|
|
$ |
167,271 |
|
Production taxes and marketing expenses (3) |
|
|
63,752 |
|
|
|
49,091 |
|
|
|
36,351 |
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
371,302 |
|
|
$ |
280,023 |
|
|
$ |
203,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
13,858 |
|
|
$ |
13,630 |
|
|
$ |
9,376 |
|
CO2 operating expenses |
|
|
4,216 |
|
|
|
4,214 |
|
|
|
3,190 |
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
9,642 |
|
|
$ |
9,416 |
|
|
$ |
6,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit sales price including impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
90.04 |
|
|
$ |
68.84 |
|
|
$ |
59.23 |
|
Gas price per Mcf |
|
|
7.74 |
|
|
|
7.66 |
|
|
|
7.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit sales price excluding impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
92.73 |
|
|
$ |
69.80 |
|
|
$ |
59.87 |
|
Gas price per Mcf |
|
|
8.56 |
|
|
|
6.81 |
|
|
|
7.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating revenues and expenses per BOE (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
79.42 |
|
|
$ |
59.17 |
|
|
$ |
53.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas lease operating expenses |
|
$ |
18.13 |
|
|
$ |
14.34 |
|
|
$ |
12.46 |
|
Oil and natural gas production taxes and marketing expenses |
|
|
3.76 |
|
|
|
3.05 |
|
|
|
2.71 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
21.89 |
|
|
$ |
17.39 |
|
|
$ |
15.17 |
|
|
(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. |
|
(3) |
|
For 2008, 2007 and 2006, includes transportation expenses paid to Genesis of $8.0 million,
$6.0 million and $4.4 million, respectively. |
|
(4) |
|
For 2008, 2007 and 2006, includes deferred revenue of $4.5 million, $4.4 million and $4.2
million, respectively, associated with volumetric production payments and transportation
income of $5.5 million, $5.2 million and $4.6 million, respectively, both from Genesis. |
44
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production. Average daily production by area for 2006 and 2007, and each of the quarters of 2008
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 |
|
2008 |
|
|
2008 |
|
|
2008 |
|
|
2008 |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
Tertiary Oil Fields |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
19,377 |
|
|
|
14,767 |
|
|
|
10,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi non-CO2 floods |
|
|
12,128 |
|
|
|
11,617 |
|
|
|
11,694 |
|
|
|
12,150 |
|
|
|
|
11,897 |
|
|
|
12,479 |
|
|
|
12,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
13,522 |
|
|
|
14,068 |
|
|
|
12,701 |
|
|
|
12,576 |
|
|
|
|
13,214 |
|
|
|
10,074 |
|
|
|
4,868 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Louisiana |
|
|
905 |
|
|
|
663 |
|
|
|
512 |
|
|
|
418 |
|
|
|
|
624 |
|
|
|
5,542 |
|
|
|
7,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama and other |
|
|
1,189 |
|
|
|
1,296 |
|
|
|
1,222 |
|
|
|
1,219 |
|
|
|
|
1,231 |
|
|
|
1,253 |
|
|
|
1,164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Company |
|
|
44,900 |
|
|
|
46,305 |
|
|
|
45,913 |
|
|
|
48,237 |
|
|
|
|
46,343 |
|
|
|
44,115 |
|
|
|
36,782 |
|
|
|
|
|
|
|
Average daily production during 2008 increased 18% (7,047 BOE/d) over 2007 levels after
adjusting for the sale of our Louisiana natural gas assets in December 2007 and February 2008. The
production increases in 2008 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 Mississippi non-CO2 floods. Production increases from the
Barnett Shale contributed approximately 3,149 BOE/d of the increase and our tertiary operations
contributed 4,610 BOE/d of the increase, partially offset by decreases of 582 BOE/d at our
Mississippi non-CO2 fields.
See CO2 Operations above for a discussion of our tertiary related production.
Production in the Mississippi non-CO2 floods area decreased slightly each year
from the prior year 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.
Our production in the Barnett Shale area in Texas increased 3,149 BOE/d (33%) during
2008 over our 2007 level, and during 2007 increased 4,690 BOE/d (97%) over our 2006 level
there. We drilled and completed 38 wells during 2008, 45 wells during 2007 and 46 wells drilled
during 2006, and plan to drill 6 wells during 2009. We have severely curtailed our spending plans
in this area for 2009 in an effort to prioritize and reduce our overall capital expenditures. We
expect our Barnett Shale production to gradually decrease throughout 2009 based on our reduced
level of future drilling activity. These wells are characterized by steep decline rates in their
first year of production, 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, the Seabreeze Complex, contributed approximately 506 BOE/d to
our 2008 average production, approximately the same as the 524 BOE/d produced during 2007.
The decrease in onshore Louisiana production in 2008 is due to the December 2007 and February
2008 divesture of these assets, excluding any oil fields that could have tertiary oil potential
(see Overview Sale of Louisiana Natural Gas Assets).
Our production for 2008 was 68% oil as compared to 63% during 2007 and 62% in 2006. This
increase is due to the sale of our Louisiana natural gas assets in December 2007 and February 2008,
and to the increase in our tertiary oil production.
45
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil and Natural Gas Revenues. Our oil and natural gas revenues have increased for each of the
last two years due to increases in both overall commodity prices and production, as seen in the
following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands |
|
2008 vs. 2007 |
|
|
2007 vs. 2006 |
|
|
|
|
|
|
|
Percentage |
|
|
|
|
|
|
Percentage |
|
|
|
Increase in |
|
|
Increase |
|
|
Increase in |
|
|
Increase |
|
|
|
Revenues |
|
|
in Revenues |
|
|
Revenues |
|
|
in Revenues |
|
Change in revenues due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in production |
|
$ |
50,845 |
|
|
|
5 |
% |
|
$ |
142,860 |
|
|
|
20 |
% |
Increase in commodity
prices |
|
|
343,377 |
|
|
|
36 |
% |
|
|
93,371 |
|
|
|
13 |
% |
|
Total increase in
revenues |
|
$ |
394,222 |
|
|
|
41 |
% |
|
$ |
236,231 |
|
|
|
33 |
% |
|
Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX
differentials were as follows during 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Net
Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
92.73 |
|
|
$ |
69.80 |
|
|
$ |
59.87 |
|
Gas price per Mcf |
|
|
8.56 |
|
|
|
6.81 |
|
|
|
7.10 |
|
Price per BOE |
|
|
79.42 |
|
|
|
59.17 |
|
|
|
53.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX
Differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(7.02 |
) |
|
$ |
(2.65 |
) |
|
$ |
(6.41 |
) |
Natural Gas per Mcf |
|
|
(0.33 |
) |
|
|
(0.28 |
) |
|
|
0.13 |
|
Our oil NYMEX differential peaked during 2008 in the second quarter at $(9.64), corresponding
to the peak in oil prices. Differentials have decreased since that time along with the decline in
oil prices, averaging $(3.59) during the fourth quarter of 2008, a relatively low differential
based on our historical averages, but not as low as they were during 2007. 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 had reversed itself by the fourth quarter of 2007, with
average NYMEX oil differentials during that quarter of $(7.27) per Bbl.
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.
46
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil and Natural Gas Derivative Contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
Non-Cash |
|
|
|
|
|
|
Non-Cash |
|
|
|
|
|
|
Non-Cash |
|
|
|
|
|
|
Fair Value |
|
|
Cash |
|
|
Fair Value |
|
|
Cash |
|
|
Fair Value |
|
|
Cash |
|
|
|
Adjustment |
|
|
Settlements |
|
|
Adjustment |
|
|
Settlements |
|
|
Adjustment |
|
|
Settlements |
|
|
|
Income/ |
|
|
Receipt/ |
|
|
Income/ |
|
|
Receipt/ |
|
|
Income/ |
|
|
Receipt/ |
|
|
|
(expense) |
|
|
(payment) |
|
|
(expense) |
|
|
(payment) |
|
|
(expense) |
|
|
(payment) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(38,733 |
) |
|
$ |
(8,048 |
) |
|
$ |
(35,158 |
) |
|
$ |
8,251 |
|
|
$ |
(10,862 |
) |
|
$ |
(768 |
) |
Second quarter |
|
|
(30,223 |
) |
|
|
(28,594 |
) |
|
|
13,330 |
|
|
|
1,719 |
|
|
|
(9,317 |
) |
|
|
(2,212 |
) |
Third quarter |
|
|
86,079 |
|
|
|
(24,072 |
) |
|
|
(5,441 |
) |
|
|
9,414 |
|
|
|
14,582 |
|
|
|
(2,207 |
) |
Fourth quarter |
|
|
240,483 |
|
|
|
3,161 |
|
|
|
(11,808 |
) |
|
|
1,096 |
|
|
|
30,727 |
|
|
|
(115 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
257,606 |
|
|
$ |
(57,553 |
) |
|
$ |
(39,077 |
) |
|
$ |
20,480 |
|
|
$ |
25,130 |
|
|
$ |
(5,302 |
) |
|
|
|
|
|
|
|
During 2008, we had significant fluctuations in our pre-tax income related to non-cash
fair value adjustments in our oil and natural gas derivative contracts due to fluctuating oil and
natural gas prices. During 2008 we made cash payments of $57.5 million on the settlements of our
commodity derivative contracts, with $26.5 million related to our 2008 natural gas swaps, and $31.0
million related to payments on our oil swaps. During 2007, we had settlements on our commodity
derivative contracts of $20.5 million, all related to our natural gas swaps, partially offset by
payments on our oil swaps. 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 fields
acquired in January 2006.
Changing commodity prices cause fluctuations in the mark-to-market value adjustments of our
derivative contracts. The most significant adjustment made in 2008 was for oil derivative
contracts purchased in October 2008 covering 30,000 Bbls/d during calendar year 2009. These
contracts have a floor price of $75 per Bbl and a ceiling price of $115 per Bbl, and were purchased
for $15.5 million. As oil prices declined significantly after we purchased these contracts, we
recognized $234.3 million of non-cash fair value income on these contracts during the fourth
quarter of 2008. The estimated fair value of these contracts recognized as a current asset on our
Consolidated Balance Sheet at December 31, 2008, was $249.7 million. Further, significant
fluctuations in oil commodity prices during 2009 may result in corresponding significant
fluctuations in our 2009 quarterly pretax income due to market value changes in these outstanding
contracts. The remaining $23.3 million of net non-cash fair value income during 2008 was primarily
associated with our oil swap contracts that settled during 2008. During 2007, we expensed $24.6
million related to mark-to-market value adjustments of 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 in 2007, as a result of the increasing oil
price. We recognized a non-cash gain of $25.1 million in 2006 as a result of decreasing prices,
primarily related to the 75 MMcf/d of natural gas swaps for calendar 2007 that we entered into
during December 2006.
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
electrical costs to operate our properties, and (v) increasing lease payments for certain of our
tertiary operating facilities and equipment.
During 2008, operating costs averaged $18.13 per BOE, up from $14.34 per BOE during
2007, and $12.46 per BOE in 2006. On a sequential quarterly basis during 2008, our operating costs
per BOE averaged $16.15, $18.23, $20.20, and finally $17.90 for the fourth quarter, generally
following the changes in oil prices. Operating expenses for our tertiary operations were $167.2
million in 2008, up from $106.5 million during 2007, and $65.0 million during 2006, all as a result
of increased tertiary activity. Tertiary operating expenses were particularly impacted by higher
electrical costs during 2007 and the first half of 2008, higher costs for CO2, and
payments on leased facilities and equipment (see CO2 Operations above). As discussed under
CO2 Operations, we expect our tertiary operating costs to partially correlate with oil
prices. They have steadily risen during the last few years as oil prices have generally gone up,
but with the recent drop in oil prices, these costs are expected to decrease. The sale of our
Louisiana natural gas properties (see Overview Sale of Louisiana Natural Gas Properties)
also
47
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
increased our corporate average operating cost per BOE in 2008. 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 increasing commodity prices.
Transportation and plant processing fees were approximately $8.4 million higher in 2008 than in
2007 and approximately $6.9 million higher in 2007 than in 2006, 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, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Net G&A expense (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Gross G&A expense |
|
$ |
137,979 |
|
|
$ |
115,519 |
|
|
$ |
96,479 |
|
State franchise taxes |
|
|
3,415 |
|
|
|
2,915 |
|
|
|
1,825 |
|
Operator labor and overhead recovery charges |
|
|
(68,556 |
) |
|
|
(59,145 |
) |
|
|
(47,667 |
) |
Capitalized exploration and development costs |
|
|
(12,464 |
) |
|
|
(10,317 |
) |
|
|
(7,623 |
) |
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
60,374 |
|
|
$ |
48,972 |
|
|
$ |
43,014 |
|
|
|
|
|
|
|
|
|
|
|
Average G&A cost per BOE |
|
$ |
3.56 |
|
|
$ |
3.04 |
|
|
$ |
3.20 |
|
Employees as of December 31 |
|
|
797 |
|
|
|
686 |
|
|
|
596 |
|
|
Gross G&A expenses increased $22.5 million, or 19% between 2007 and 2008, and $19.0 million,
or 20%, between 2006 and 2007. The increases are primarily due to higher compensation and
personnel related costs caused by an increase in the number of employees and higher wages which we consider
necessary in order to remain competitive in our industry. During 2007, we increased our employee
count by 15%, and we further increased our employee count 16% during 2008. Stock compensation
expense reflected in gross G&A was $16.2 million during 2008, $12.2 million during 2007 and $18.9
million during 2006. The 2006 amount included $6.0 million of non-recurring charges related to the
retirement and departure of two vice presidents during 2006.
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 16% between 2007 and 2008, and 24% between 2006 and 2007. Capitalized exploration and
development costs increased each year primarily due to additional personnel and increased
compensation costs.
The net effect of the increases in gross G&A expenses, operator overhead recoveries and
capitalized exploration costs was a 23% increase in net G&A expense between 2007 and 2008, and a
14% increase in net G&A expense between 2006 and 2007. On a per BOE basis, G&A increased 17% in
2008 as compared to 2007 but G&A per BOE decreased 5% in 2007 as compared to 2006 levels as higher production more than offset the
increase in gross costs.
48
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE data |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Cash interest expense |
|
$ |
59,955 |
|
|
$ |
49,205 |
|
|
$ |
33,787 |
|
Non-cash interest expense |
|
|
1,802 |
|
|
|
2,010 |
|
|
|
1,121 |
|
Less: Capitalized interest |
|
|
(29,161 |
) |
|
|
(20,385 |
) |
|
|
(11,333 |
) |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
32,596 |
|
|
$ |
30,830 |
|
|
$ |
23,575 |
|
|
|
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
4,834 |
|
|
$ |
6,642 |
|
|
$ |
5,603 |
|
|
|
|
|
|
|
|
|
|
|
Average net cash interest expense
per BOE (1) |
|
$ |
1.59 |
|
|
$ |
1.43 |
|
|
$ |
1.26 |
|
Average debt outstanding |
|
$ |
735,288 |
|
|
$ |
672,376 |
|
|
$ |
455,603 |
|
Average interest rate (2) |
|
|
8.2 |
% |
|
|
7.3 |
% |
|
|
7.4 |
% |
|
(1) |
|
Cash interest expense, less capitalized interest, less interest and other income on a BOE
basis. |
|
(2) |
|
Includes commitment fees but excludes amortization of discount, premium and debt issue costs. |
Interest expense increased $1.8 million, or 6%, between 2007 and 2008, and $7.3 million, or
31%, between 2006 and 2007, primarily as a result of higher debt levels in the 2007 and 2008
periods, partially offset by higher capitalized interest during the 2007 and 2008 periods.
Interest expense increased significantly during 2008 as a result of the two transactions with
Genesis which were recorded as financing leases (see Overview Genesis Transactions) and which
carry a higher imputed rate of interest. The higher rate of interest is partially offset by the
cash distributions that we receive from Genesis, which have increased from $1.7 million in 2007 to
$7.1 million during 2008. However, the cash receipts related to distributions from Genesis are not
recognized in our income statement but rather as an adjustment to our investment account.
Our interest capitalization increased in 2008 because of our growing balance of unevaluated
property expenditures, expenditures on our CO2 pipeline projects and higher overall
interest rates.
Depletion, Depreciation and Amortization (DD&A) and Full Cost Ceiling Test Write-down
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE data |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Depletion and depreciation of oil and natural gas
properties |
|
$ |
192,791 |
|
|
$ |
174,356 |
|
|
$ |
132,880 |
|
Depletion and depreciation of CO2 assets |
|
|
15,644 |
|
|
|
11,609 |
|
|
|
8,375 |
|
Asset retirement obligations |
|
|
3,048 |
|
|
|
2,977 |
|
|
|
2,389 |
|
Depreciation of other fixed assets |
|
|
10,309 |
|
|
|
6,958 |
|
|
|
5,521 |
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
221,792 |
|
|
$ |
195,900 |
|
|
$ |
149,165 |
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.55 |
|
|
$ |
11.02 |
|
|
$ |
10.08 |
|
CO2 assets and other fixed assets |
|
|
1.53 |
|
|
|
1.15 |
|
|
|
1.03 |
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
13.08 |
|
|
$ |
12.17 |
|
|
$ |
11.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Full cost ceiling test write-down |
|
$ |
226,000 |
|
|
$ |
|
|
|
$ |
|
|
|
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, before the $226.0 million ($140.1 million net of tax) full cost ceiling
write-down in 2008, increased 7% between 2007 and 2008, and 10% between 2006 and 2007, primarily
due to capital spending and increased costs. Our proved reserves increased from 174.3 MMBOE as of
December 31, 2006, to 194.7 MMBOE as of December 31, 2007, and further increased to 250.5 MMBOE as
of December 31, 2008. Our 2008 year-end proved reserve quantities represent a 29% increase over
proved reserves at the end of 2007, in spite of an estimated 13.8 MMBOE that were excluded as a
result of the lower commodity prices at the end of 2008.
We added a total of 88.9 MMBOE of proved reserves during 2008 (before netting out 2008
production, property sales and downward reserve revisions due to pricing), replacing approximately
525% of our 2008
49
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
production. The most significant reserve additions during 2008 were approximately
63.4 MMbbls added in our tertiary oil operations and approximately 117 Bcfe (19.5 MMBOE) in the
Barnett Shale, both before netting out 2008 production. Our tertiary-related oil reserves added
during the year were primarily at Tinsley Field in Phase III (34.8 MMBOE), Heidelberg Field in
Phase II (22.4 MMBOE) and Lockhart Crossing Field in Phase I (4.0 MMBOE). Even though the
additional proved reserves were significant, at the same time that we recognize incremental proved
tertiary oil reserves, we move any related costs for that field from unevaluated properties into
the full cost pool. Usually, these unevaluated costs are significant and when combined with the
estimated future development costs, the net impact of the DD&A rate is usually minimal, and in some
cases, increases the rate. Further, we generally do not initially recognize all of the potential
tertiary oil reserves that we believe are recoverable, and therefore we expect to recognize
incremental proved reserves at each of these tertiary fields in the future. These potential future
reserves will have little or no cost associated with the incremental barrels; therefore, as these
potential future reserves are recognized they will reduce the average ultimate cost per barrel.
Approximately $76.6 million of our 2008 capital expenditures were incurred on properties for
which there were no proved reserves at year-end 2008 (primarily our new tertiary floods), and as
such, were classified as unevaluated costs and did not affect our DD&A rate. As part of the
initial recognition of proved reserves at Tinsley, Heidelberg and Lockhart Crossing Fields during
2008, approximately $284.6 million of previously unevaluated costs were moved to the full cost
pool.
Our DD&A rate during the fourth quarter of 2008 was also negatively impacted by the exclusion
of approximately 13.8 MMBOE due to the decrease in commodity prices. Had these reserves been
included, the DD&A rate on oil and gas properties for the fourth quarter of 2008 would have been
approximately $11.32 per BOE, rather than the $11.92 per BOE that was reported.
Our DD&A rate for our CO2 and other fixed assets increased in both 2007 and 2008 as
a result of the Free State CO2 Pipeline that was placed into service in 2006, the
Lockhart Crossing CO2 pipeline placed into service during 2007, the Tinsley and
Heidelberg CO2 pipelines placed into service during 2008, drilling costs for additional
CO2 wells, and the expansion of our corporate office space during 2008.
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, 2006, to be $91.3 million ($41.1 million present value), with an estimated salvage
value of $60.0 million. 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, and
as of December 31, 2008, we estimated our retirement obligations to be $106.4 million ($45.1
million present value), with an estimated salvage value of $76.4 million, the increase related to
2008 activity and higher cost estimates due to the inflation in our industry, partially offset by a
decrease in our obligation of approximately $9.5 million, ($9.3 million present value) related to
the sale of most of our Louisiana natural gas properties in late 2007 and early 2008. 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 have not had any full cost pool ceiling test write-downs since 1998. However,
during 2008, commodity prices were volatile, with oil NYMEX prices moving from $95.98 per Bbl at
December 31, 2007 to $140.00 per Bbl at June 30, 2008 then down to $44.60 per Bbl at December 31,
2008. Likewise, natural gas NYMEX prices went from $7.48 per Mcf as
of December 31, 2007 to $13.35
per Mcf at June 30, 2008 and down to $5.62 per Mcf as of December 31, 2008. Because of the 54%
decrease in NYMEX oil price and 25% decrease in NYMEX natural gas price between year-end 2007 and
year-end 2008, we recognized a full cost pool ceiling test write-down at December 31, 2008 of
$226.0 million, or $13.32 per BOE. Subsequent to December 31, 2008, oil and natural gas prices
have continued their volatility and are currently at levels lower than at year-end 2008. If oil
and natural gas prices remain at these lower levels through March 31, 2009, or subsequent periods,
we may be required to record additional write-downs under the full cost ceiling test in the first
quarter of 2009, or in subsequent periods. The amount of any future write-down is difficult to
predict and will depend upon the oil and natural gas prices at the end of each period, the
incremental proved reserves that might be added during each period and additional capital spent.
50
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Current income tax expense |
|
$ |
40,812 |
|
|
$ |
30,074 |
|
|
$ |
19,865 |
|
Deferred income tax expense |
|
|
195,020 |
|
|
|
110,193 |
|
|
|
107,252 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
235,832 |
|
|
$ |
140,267 |
|
|
$ |
127,117 |
|
|
|
|
|
|
|
|
|
|
|
Average income tax expense per BOE |
|
$ |
13.90 |
|
|
$ |
8.71 |
|
|
$ |
9.47 |
|
Effective tax rate |
|
|
37.8 |
% |
|
|
35.7 |
% |
|
|
38.6 |
% |
Total net deferred tax asset (liability) |
|
$ |
(522,234 |
) |
|
$ |
(334,662 |
) |
|
$ |
(229,925 |
) |
|
Our income tax provision was based on an estimated statutory rate of approximately 38% in 2008
and 2007 and 39% in 2006. Our effective tax rate has generally been less than our estimated
statutory rate due to the impact of certain items such as our domestic production activities
deduction, partially offset by 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 2008 and 2007 was a result of our sale of our Louisiana natural gas assets
during the fourth quarter of 2007. In 2008, we received permission from the IRS to change our
method of tax accounting for certain assets used in our tertiary recovery operations (see Overview
Change in Tax Accounting Method for Certain Tertiary Costs).
In all three periods, the current income tax expense represents our anticipated alternative
minimum cash taxes that we cannot offset with enhanced oil recovery (EOR) credits. As of December
31, 2008, we had an estimated $44 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 2022. Since the
ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we
may earn EOR credits again in the future if oil prices remain at their currently depressed levels.
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 |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Oil and natural gas revenues |
|
$ |
79.42 |
|
|
$ |
59.17 |
|
|
$ |
53.37 |
|
Gain (loss) on settlements of derivative contracts |
|
|
(3.40 |
) |
|
|
1.27 |
|
|
|
(0.39 |
) |
Lease operating expenses |
|
|
(18.13 |
) |
|
|
(14.34 |
) |
|
|
(12.46 |
) |
Production taxes and marketing expenses |
|
|
(3.76 |
) |
|
|
(3.05 |
) |
|
|
(2.71 |
) |
|
Production netback |
|
|
54.13 |
|
|
|
43.05 |
|
|
|
37.81 |
|
Non-tertiary CO2 operating margin |
|
|
0.57 |
|
|
|
0.58 |
|
|
|
0.46 |
|
General and administrative expenses |
|
|
(3.56 |
) |
|
|
(3.04 |
) |
|
|
(3.20 |
) |
Net cash interest expense |
|
|
(1.59 |
) |
|
|
(1.43 |
) |
|
|
(1.26 |
) |
Abandoned acquisition costs |
|
|
(1.80 |
) |
|
|
|
|
|
|
|
|
Current income taxes and other |
|
|
(1.78 |
) |
|
|
(1.37 |
) |
|
|
(0.41 |
) |
Changes in assets and liabilities relating to operations |
|
|
(0.31 |
) |
|
|
(2.38 |
) |
|
|
1.00 |
|
|
Cash flow from operations |
|
|
45.66 |
|
|
|
35.41 |
|
|
|
34.40 |
|
DD&A |
|
|
(13.08 |
) |
|
|
(12.17 |
) |
|
|
(11.11 |
) |
Write-down of oil and natural gas properties |
|
|
(13.32 |
) |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
(11.50 |
) |
|
|
(6.84 |
) |
|
|
(7.99 |
) |
Non-cash commodity derivative adjustments |
|
|
15.19 |
|
|
|
(2.43 |
) |
|
|
1.87 |
|
Changes in assets and liabilities and other non-cash items |
|
|
(0.05 |
) |
|
|
1.75 |
|
|
|
(2.09 |
) |
|
Net income |
|
$ |
22.90 |
|
|
$ |
15.72 |
|
|
$ |
15.08 |
|
|
51
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Market Risk Management
Debt
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. We had $75
million of bank debt outstanding as of December 31, 2008, and $60 million outstanding as of
February 27, 2009. The carrying value of our bank debt 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 adjusted the estimated fair value measurements of our bank debt at
December 31, 2008 in accordance with SFAS No. 157 for
estimated nonperformance risk. This estimated nonperformance risk
totaled approximately $11.0 million and was determined
utilizing industry credit default swaps. None of our existing debt has any triggers or covenants regarding our debt
ratings with rating agencies, although under the NEJD financing lease with Genesis (see Overview Genesis Transactions) in the event of significant downgrades of our corporate credit
rating by the rating agencies, Genesis can require certain credit enhancements from us, and
possibly other remedies under the lease. The fair value of the subordinated debt is based on
quoted market prices. The following table presents the carrying and fair values of our debt, along
with average interest rates at December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
|
Carrying |
|
|
Fair |
|
Amounts in thousands |
|
2011 |
|
|
2013 |
|
|
2015 |
|
|
Value |
|
|
Value |
|
|
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted
average interest rate of
2.95% at December 31, 2008) |
|
$ |
75,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
75,000 |
|
|
$ |
64,000 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due
2013 (fixed rate of 7.5%) |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
224,174 |
|
|
|
171,000 |
|
7.5% subordinated debt due
2015 (fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
300,599 |
|
|
|
213,000 |
|
|
Oil and Natural Gas Derivative Contracts
From time to time, we enter into various oil and natural gas 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. The
production that we hedge has varied from year to year depending on our levels of debt and financial
strength and expectation of future commodity prices. Historically, we hedged up to 80% of our
anticipated production 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. 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 (after the sale of our Louisiana natural gas properties see 2008
Overview Sale of Louisiana Natural Gas Assets) at a weighted average price of $7.91 per Mcf. We
cancelled the December 2008 natural gas swaps in the third quarter of 2008 because of our plans at
that time to sell our Barnett Shale properties, receiving approximately $61,000 from the
cancellation.
As a result of the current economic conditions and in order to protect our liquidity in the
event that commodity prices continue to decline, during early October 2008, we purchased oil
derivative contracts for 2009 with a floor price of $75 / Bbl and a ceiling price of $115 / Bbl for
total consideration of $15.5 million. The collars cover 30,000 Bbls/d representing approximately
80% of our currently anticipated 2009 oil production. These 2009 contracts were entered into with
the following counterparties: JPMorgan Chase Bank (10,000 Bbls/d), Wells Fargo Bank (7,500
Bbls/d), Keybank (5,000 Bbls/d), Fortis Energy Marketing and Trading GP (5,000 Bbls/d) and Comerica
Bank (2,500 Bbls/d).
Historically,
when we made a significant acquisition, we generally attempted 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. For
2008, 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 first three years of
estimated proved producing production at the time we signed the purchase and sale agreement. These
swaps covered 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
52
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
credit risk exposure to counterparties through formal
credit policies, monitoring procedures and diversification. We have included an estimate of
nonperformance risk in the fair value measurement of our oil derivative contracts as required by
SFAS No. 157. At December 31, 2008, all of our oil derivative contracts are in an asset position.
Therefore, in assessing the nonperformance risk of the counterparties to these contracts, we have
measured the risk by using credit default swaps as we believe this data is the most responsive to
current market events. If a counter-party did not have credit default swaps associated with that
specific entity, we utilized industry credit default swaps as an estimate of the fair value of this
risk associated with that entity. At December 31, 2008, the fair value of our oil derivative
contracts was reduced by $3.7 million for the estimated nonperformance risk of our counterparties.
For accounting purposes, we do not apply hedge accounting for our oil and natural
gas derivative 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. 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, 2008, our derivative contracts were recorded at their fair value,
which was a net asset of approximately $249.7 million, an increase of $273.0 million from the $23.3
million fair value liability recorded as of December 31, 2007. This change is primarily related to the declining oil prices which
significantly increased the value of our 2009 oil collars, and the expiration of our natural gas
hedges during 2008. During 2008, we recognized total income related to our hedge contracts of
$200.1 million, consisting of $57.5 million of net cash payments on settlements of expired
contracts, and $257.6 million of income relating to mark-to-market non-cash adjustments.
Based on NYMEX crude oil futures prices at December 31, 2008, we would expect to receive
future cash payments of $229.8 million on our crude oil commodity derivative contracts. If crude
oil futures prices were to decline by 10%, we would expect to receive future cash payments on our
crude oil commodity derivative contracts of $289.0 million, and if futures prices were to increase
by 10% we would expect to receive $170.7 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 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. Further, we do not designate our oil and natural gas derivative contracts as
hedge instruments for accounting purposes under SFAS No. 133, and as a result, these contracts are
not considered in the full cost ceiling test.
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
53
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 3.3% of the previous years estimates and have been both positive and negative.
Changes in commodity prices also affect our reserve quantities. During 2006 and 2007, the
change to reserve quantities related to commodity prices was relatively small as prices were
relatively high each year-end; however, at December 31, 2008 the lower commodity prices lowered our
proved reserves by 13.8 MMBOE. 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 2008 DD&A rate from $13.72 per BOE to
approximately $13.17 per BOE, and a 5% decrease in our proved reserve quantities would have
increased our DD&A rate to approximately $14.33 per BOE. 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.
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 2006 or 2007. However,
during 2008, commodity prices were volatile, with oil NYMEX prices moving from $95.98 per Bbl at
December 31, 2007 to $140.00 per Bbl at June 30, 2008 then down to $44.60 per Bbl at December 31,
2008. Likewise, natural gas NYMEX prices went from $7.48 per Mcf as
of December 31, 2007 to $13.35
per Mcf at June 30, 2008 and down to $5.62 per Mcf as of December 31, 2008. Because of the 54%
decrease in NYMEX oil price and 25% decrease in NYMEX natural gas price between year-end 2007 and
year-end 2008, we recognized a full cost pool ceiling test write-down during 2008 of $226.0
million, or $13.32 per BOE. Commodity prices have historically been volatile and are expected to
be in the future. If oil and natural gas prices remain at these lower levels through March 31,
2009, or subsequent periods, we may be required to record additional write-downs due to the full
cost ceiling test in the first quarter of 2009, or in subsequent periods. The amount of any future
write-down is difficult to predict and will depend upon the oil and natural gas prices at the end
of each period, the incremental proved reserves that might be added during each period and
additional capital spent.
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 have
generally been 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 2006
and 2007 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 and thus on our DD&A rate, full cost ceiling
test calculation, borrowing base and financial statements. See
54
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
also discussion of requirements to
book proven tertiary oil reserves at Results of Operations Depletion, Depreciation and
Amortization.
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, and to pay royalties.
Prior to January 1, 2008, we expensed currently all costs associated with injecting
CO2
that we used 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 began
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. Had the new method of
accounting for tertiary injection costs been used in periods prior to January 1, 2008, the effect
on our financial statements would have been immaterial for all periods presented. During 2008, we
capitalized $10.4 million of tertiary injection costs associated with our tertiary projects that we
would have previously expensed.
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, 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, 2008, 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 more likely than not. A 1% increase in our effective tax rate
would have increased our calculated income tax expense by approximately $6.2 million, $3.9 million
and $3.3 million for the years ended December 31, 2008, 2007 and 2006, respectively. See Note 7 to
the Consolidated Financial Statements for further information concerning our income taxes.
55
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.
We do not designate these derivative commodity contracts as hedge instruments for accounting
purposes under SFAS No. 133. 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 were 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 2008,
2007 and 2006, we recognized expense (income) of ($257.6) million, $39.1 million and ($25.1)
million, respectively, related to changes in the fair market value of our derivative contracts.
Stock Compensation Plans
SFAS No. 123(R), Share-Based Payment requires that we 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. 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, 2008, there was $12.5 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 2.6 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
Business Combinations. In December 2007, the FASB issued SFAS No. 141 (Revised 2008),
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 do not anticipate the adoption of SFAS 141(R) will have a material impact on our
financial condition or results of operations, absent any material business combinations.
Noncontrolling Interests. 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. Since we currently do not have any noncontrolling interests, SFAS No.
160 does not presently have any impact on us.
56
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB
issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activitiesan
amendment of SFAS No. 133. SFAS No. 161 requires entities that utilize derivative
instruments to provide qualitative disclosures about their objectives and strategies for using
such instruments, as well as any details of credit-risk-related contingent features contained
within derivatives. SFAS No. 161 also requires entities to disclose additional information
about the amounts and location of derivatives located within the financial statements, how the
provisions of SFAS No. 133 have been applied, and the impact that hedges have on an entitys
financial position, financial performance, and cash flows. SFAS No. 161 is effective for us
beginning January 1, 2009. As its only requirement is to enhance disclosures, SFAS No. 161
will not have a significant impact on us.
Modernization of Oil and Gas Reporting. On December 31, 2008, the Securities and Exchange
Commission adopted major revisions to its rules governing oil and gas company reporting
requirements. These include provisions that permit the use of new technologies to determine proved
reserves, and that allow companies to disclose their probable and possible reserves to investors.
The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies that have an audit performed of their
reserves to report the independence and qualifications of the auditor of the reserve estimates, and
to file reports when a third party reserve engineer is relied upon to prepare reserve estimates.
The new rules also require that oil and gas reserves be reported and the full cost ceiling value
calculated using an average price based upon the prior 12-month period. The new oil and gas
reporting requirements are effective for annual reports on Forms 10-K for fiscal years ending on or
after December 31, 2009, with early adoption not permitted. We are currently evaluating the impact
the new rules may 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, capital budgets, production rates
and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2
reserves, potential reserves from tertiary operations, hydrocarbon prices, pricing or cost
assumptions based on current and projected oil and gas prices, liquidity, cash flows, availability
of capital, borrowing capacity, regulatory matters, mark-to-market values, competition, long-term
forecasts of production, finding costs, rates of return, estimated costs, or changes in costs,
future capital expenditures and overall economics and other variables surrounding our 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; availability of and fluctuations in the prices of goods and
services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption
of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for
capital or its availability; conditions in the financial and credit markets; 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 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.
57
Denbury Resources Inc.
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 52
through 53.
Item 8. Financial Statements and Supplementary Data
|
|
|
|
|
|
|
Page |
|
|
|
59 |
|
|
|
|
60 |
|
|
|
|
61 |
|
|
|
|
62 |
|
|
|
|
63 |
|
|
|
|
64 |
|
|
|
|
65 |
|
|
|
|
94 |
|
|
|
|
98 |
|
58
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, 2008 and 2007, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2008 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, 2008, 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 Managements Report on Internal
Control over Financial Reporting under Item 9A. 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.
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, 2009 |
59
Denbury Resources Inc.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
(In thousands, except shares) |
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
17,069 |
|
|
$ |
60,107 |
|
Accrued production receivable |
|
|
67,805 |
|
|
|
136,284 |
|
Trade and other receivables, net of allowance of $377 and $369 |
|
|
80,579 |
|
|
|
28,977 |
|
Derivative assets |
|
|
249,746 |
|
|
|
2,283 |
|
Deferred tax assets |
|
|
|
|
|
|
12,708 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
415,199 |
|
|
|
240,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment |
|
|
|
|
|
|
|
|
Oil and natural gas properties (using full cost accounting) |
|
|
|
|
|
|
|
|
Proved |
|
|
3,386,606 |
|
|
|
2,682,932 |
|
Unevaluated |
|
|
235,403 |
|
|
|
366,518 |
|
CO2 properties, equipment and pipelines |
|
|
899,542 |
|
|
|
436,591 |
|
Other |
|
|
70,328 |
|
|
|
50,116 |
|
Less accumulated depletion, depreciation and impairment |
|
|
(1,589,682 |
) |
|
|
(1,143,282 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
3,002,197 |
|
|
|
2,392,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deposits on properties under option or contract |
|
|
48,917 |
|
|
|
49,097 |
|
Other assets |
|
|
43,357 |
|
|
|
32,338 |
|
Investment in Genesis |
|
|
80,004 |
|
|
|
56,408 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,589,674 |
|
|
$ |
2,771,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
202,633 |
|
|
$ |
147,580 |
|
Oil and gas production payable |
|
|
85,833 |
|
|
|
84,150 |
|
Derivative liabilities |
|
|
|
|
|
|
28,096 |
|
Deferred revenue Genesis |
|
|
4,070 |
|
|
|
4,070 |
|
Deferred tax liability |
|
|
89,024 |
|
|
|
|
|
Current maturities of long-term debt |
|
|
4,507 |
|
|
|
737 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
386,067 |
|
|
|
264,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities |
|
|
|
|
|
|
|
|
Long-term debt-Genesis |
|
|
251,047 |
|
|
|
4,544 |
|
Long-term debt |
|
|
601,720 |
|
|
|
675,786 |
|
Asset retirement obligations |
|
|
43,352 |
|
|
|
38,954 |
|
Deferred revenue Genesis |
|
|
19,957 |
|
|
|
24,424 |
|
Deferred tax liability |
|
|
433,210 |
|
|
|
347,370 |
|
Other |
|
|
14,253 |
|
|
|
10,988 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
1,363,539 |
|
|
|
1,102,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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;
248,005,874 and 245,386,951 shares issued at December 31,
2008 and 2007, respectively |
|
|
248 |
|
|
|
245 |
|
Paid-in capital in excess of par |
|
|
707,702 |
|
|
|
662,698 |
|
Retained earnings |
|
|
1,139,575 |
|
|
|
751,179 |
|
Accumulated other comprehensive loss |
|
|
(627 |
) |
|
|
(1,591 |
) |
Treasury stock, at cost, 446,287 and 637,795 shares at December 31,
2008 and 2007, respectively |
|
|
(6,830 |
) |
|
|
(8,153 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,840,068 |
|
|
|
1,404,378 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
3,589,674 |
|
|
$ |
2,771,077 |
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
60
Denbury Resources Inc.
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per share data) |
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Revenues and other income |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and related product sales |
|
$ |
1,347,010 |
|
|
$ |
952,788 |
|
|
$ |
716,557 |
|
CO2 sales and transportation fees |
|
|
13,858 |
|
|
|
13,630 |
|
|
|
9,376 |
|
Interest income and other |
|
|
4,834 |
|
|
|
6,642 |
|
|
|
5,603 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,365,702 |
|
|
|
973,060 |
|
|
|
731,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
307,550 |
|
|
|
230,932 |
|
|
|
167,271 |
|
Production taxes and marketing expenses |
|
|
55,770 |
|
|
|
43,130 |
|
|
|
31,993 |
|
Transportation expense Genesis |
|
|
7,982 |
|
|
|
5,961 |
|
|
|
4,358 |
|
CO2 operating expenses |
|
|
4,216 |
|
|
|
4,214 |
|
|
|
3,190 |
|
General and administrative |
|
|
60,374 |
|
|
|
48,972 |
|
|
|
43,014 |
|
Interest, net of amounts capitalized of
$29,161, $20,385 and $11,333
in 2008, 2007 and 2006, respectively |
|
|
32,596 |
|
|
|
30,830 |
|
|
|
23,575 |
|
Depletion, depreciation and amortization |
|
|
221,792 |
|
|
|
195,900 |
|
|
|
149,165 |
|
Commodity derivative expense (income) |
|
|
(200,053 |
) |
|
|
18,597 |
|
|
|
(19,828 |
) |
Abandoned acquisition cost |
|
|
30,601 |
|
|
|
|
|
|
|
|
|
Write-down of oil and natural gas properties |
|
|
226,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
746,828 |
|
|
|
578,536 |
|
|
|
402,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net income (loss) of Genesis |
|
|
5,354 |
|
|
|
(1,110 |
) |
|
|
776 |
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
624,228 |
|
|
|
393,414 |
|
|
|
329,574 |
|
Income tax provision |
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
40,812 |
|
|
|
30,074 |
|
|
|
19,865 |
|
Deferred income taxes |
|
|
195,020 |
|
|
|
110,193 |
|
|
|
107,252 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
|
$ |
202,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share basic |
|
$ |
1.59 |
|
|
$ |
1.05 |
|
|
$ |
0.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
$ |
1.54 |
|
|
$ |
1.00 |
|
|
$ |
0.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
243,935 |
|
|
|
240,065 |
|
|
|
233,101 |
|
Diluted |
|
|
252,530 |
|
|
|
252,101 |
|
|
|
247,547 |
|
See accompanying Notes to Consolidated Financial Statements.
61
Denbury Resources Inc.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
|
$ |
202,457 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
221,792 |
|
|
|
195,900 |
|
|
|
149,165 |
|
Write-down of oil and natural gas properties |
|
|
226,000 |
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
195,020 |
|
|
|
110,193 |
|
|
|
107,252 |
|
Deferred revenue Genesis |
|
|
(4,466 |
) |
|
|
(4,419 |
) |
|
|
(4,180 |
) |
Stock based compensation |
|
|
14,068 |
|
|
|
10,595 |
|
|
|
17,246 |
|
Non-cash fair value derivative adjustments |
|
|
(257,502 |
) |
|
|
38,952 |
|
|
|
(25,129 |
) |
Other |
|
|
(3,499 |
) |
|
|
4,149 |
|
|
|
1,603 |
|
Changes in assets and liabilities relating to operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued production receivable |
|
|
68,479 |
|
|
|
(63,886 |
) |
|
|
(5,474 |
) |
Trade and other receivables |
|
|
(58,236 |
) |
|
|
(10,409 |
) |
|
|
1,712 |
|
Derivative assets |
|
|
(15,471 |
) |
|
|
|
|
|
|
|
|
Other assets |
|
|
348 |
|
|
|
(819 |
) |
|
|
(672 |
) |
Accounts payable and accrued liabilities |
|
|
254 |
|
|
|
1,576 |
|
|
|
7,038 |
|
Oil and gas production payable |
|
|
1,683 |
|
|
|
31,906 |
|
|
|
10,422 |
|
Other liabilities |
|
|
(2,347 |
) |
|
|
3,329 |
|
|
|
370 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
774,519 |
|
|
|
570,214 |
|
|
|
461,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow used for investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures |
|
|
(591,365 |
) |
|
|
(613,659 |
) |
|
|
(507,327 |
) |
Acquisitions of oil and gas properties |
|
|
(31,367 |
) |
|
|
(49,077 |
) |
|
|
(319,000 |
) |
Change in accrual for capital expenditures |
|
|
59,183 |
|
|
|
(421 |
) |
|
|
13,195 |
|
CO2 capital expenditures, including pipelines |
|
|
(462,889 |
) |
|
|
(171,182 |
) |
|
|
(63,586 |
) |
Investment in Genesis |
|
|
(516 |
) |
|
|
(47,738 |
) |
|
|
|
|
Distributions from Genesis |
|
|
7,139 |
|
|
|
|
|
|
|
|
|
Net purchases of other assets |
|
|
(23,799 |
) |
|
|
(13,672 |
) |
|
|
(10,531 |
) |
Net proceeds from sales of oil and gas properties and equipment |
|
|
51,684 |
|
|
|
142,667 |
|
|
|
42,762 |
|
Other |
|
|
(2,729 |
) |
|
|
(9,431 |
) |
|
|
(12,140 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(994,659 |
) |
|
|
(762,513 |
) |
|
|
(856,627 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(222,000 |
) |
|
|
(265,000 |
) |
|
|
(249,000 |
) |
Bank borrowings |
|
|
147,000 |
|
|
|
281,000 |
|
|
|
383,000 |
|
Income tax benefit from equity awards |
|
|
19,665 |
|
|
|
19,181 |
|
|
|
16,575 |
|
Issuance of subordinated debt |
|
|
|
|
|
|
150,750 |
|
|
|
|
|
Pipeline financing Genesis |
|
|
225,252 |
|
|
|
|
|
|
|
|
|
Issuance of common stock |
|
|
13,972 |
|
|
|
18,222 |
|
|
|
139,834 |
|
Other |
|
|
(6,787 |
) |
|
|
(5,620 |
) |
|
|
(6,808 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
177,102 |
|
|
|
198,533 |
|
|
|
283,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(43,038 |
) |
|
|
6,234 |
|
|
|
(111,216 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
60,107 |
|
|
|
53,873 |
|
|
|
165,089 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
17,069 |
|
|
$ |
60,107 |
|
|
$ |
53,873 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
62
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, 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
155,297 |
|
|
|
(3,762 |
) |
|
|
(3,762 |
) |
Issued pursuant to employee stock
purchase plan |
|
|
|
|
|
|
|
|
|
|
1,176 |
|
|
|
|
|
|
|
|
|
|
|
(346,805 |
) |
|
|
5,085 |
|
|
|
6,261 |
|
Issued pursuant to employee stock
option plan |
|
|
2,578,563 |
|
|
|
3 |
|
|
|
7,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,711 |
|
Issued pursuant to directors
compensation plan |
|
|
12,753 |
|
|
|
|
|
|
|
212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
212 |
|
Restricted stock grants |
|
|
278,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants forfeited |
|
|
(251,366 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
16,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,243 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
|
|
|
|
19,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,665 |
|
Derivative contracts, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
964 |
|
|
|
|
|
|
|
|
|
|
|
964 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
388,396 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
388,396 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
|
248,005,874 |
|
|
$ |
248 |
|
|
$ |
707,702 |
|
|
$ |
1,139,575 |
|
|
$ |
(627 |
) |
|
|
446,287 |
|
|
$ |
(6,830 |
) |
|
$ |
1,840,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
63
Denbury Resources Inc.
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
|
$ |
202,457 |
|
Other comprehensive income (loss), net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of interest rate lock contracts designated as a hedge,
net of tax of $49, ($1,017) and $-, respectively |
|
|
12 |
|
|
|
(1,591 |
) |
|
|
|
|
Interest rate lock derivative contracts reclassified
to income, net of taxes of $583 |
|
|
952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
389,360 |
|
|
$ |
251,556 |
|
|
$ |
202,457 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
64
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 Energy, L.P. (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, Genesis Energy, LLC is the general partner
of, and together with Denburys other subsidiaries, owns an aggregate 12% interest in Genesis, a
publicly traded master limited partnership. We account for our 12% ownership interest in Genesis
under the equity method of accounting. Even though we have significant influence over the limited
partnership in our role as general partner, because our control is limited by the Genesis limited
partnership agreement we do not consolidate Genesis. See Note 3 for more information regarding our
related party transactions with Genesis. All material intercompany balances and transactions have
been eliminated. We have evaluated our consolidation of variable interest entities in accordance
with FASB Interpretation No. 46, Consolidation of Variable Interest Entities, and have concluded
that we do not have any variable interest entities that would require consolidation.
Stock Split
On 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.
Information pertaining to shares and earnings per share has been retroactively adjusted in the
accompanying financial statements and related notes thereto to reflect the stock split, 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.
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, capitalized
interest on qualifying projects, 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
and future development costs, are depleted or depreciated on the unit-of-production method, based
on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and
natural gas reserves are converted to equivalent units based upon the relative energy content,
which is six thousand cubic feet of natural gas to one barrel of crude oil. The depletion and
depreciation rate per BOE associated with our oil and gas producing activities was $12.54 in 2008,
$11.60 in 2007 and $10.54 in 2006.
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
65
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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. We include that portion of net capitalized costs of CO2 assets and
CO2 pipelines that are required for our current proved tertiary reserves in the net
capitalized costs subject to the ceiling test. 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, Supplemental Oil and Natural Gas Disclosures (Unaudited) 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, and 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 began
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 status of some of our tertiary floods, during 2008 this change in
accounting caused us to capitalize certain costs that we historically expensed. During 2008, we
capitalized $10.4 million of tertiary injection costs associated with our tertiary projects that we
would have previously expensed. Had the new method of accounting for tertiary injection 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.
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.
66
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, 2008 and 2007, 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. We do not apply hedge accounting to our oil and
natural gas derivative contracts and accordingly 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 instruments
discussed above. Our cash equivalents represent high-quality securities placed with various
investment-grade institutions. This investment practice limits our exposure to concentrations of
credit risk. Our trade and accrued production receivables are dispersed among various customers
and purchasers; therefore, concentrations of credit risk are limited. Also, most of our
significant purchasers are large companies with excellent credit ratings. If customers are
considered a credit risk, letters of credit are the primary security obtained to support lines of
credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and
natural gas derivative 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 66 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. To evaluate our CO2 assets for impairment, we determine the
CO2 required for our proved tertiary reserves and include the estimated net capitalized
costs of those CO2 assets in the oil and natural gas ceiling test. The remaining net
capitalized CO2 asset cost is evaluated for impairment by comparing our expected future
revenues from these assets to their net carrying value.
67
Denbury Resources Inc.
Notes to Consolidated Financial Statements
CO2 Pipelines
CO2 pipelines are used for transportation of CO2 to our tertiary floods
from our CO2 source field located near Jackson, Mississippi. We are continuing
expansion of our CO2 pipeline infrastructure with several pipelines currently under
construction. At December 31, 2008 and 2007, we had $402.0 million and $106.2 million of costs,
respectively, related to construction in progress, recorded under CO2 properties,
equipment and pipelines in our Consolidated Balance Sheets. These costs of CO2
pipelines under construction were not being depreciated at December 31, 2008 or December 31, 2007.
Depreciation will commence when the pipelines are placed into service. Each pipeline is depreciated
on a straight-line basis over its estimated useful life. We include the net capitalized cost of
the pipelines which provide CO2 to the tertiary floods that have proved tertiary
reserves, in the oil and natural gas ceiling test.
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, 2008 and 2007, we had approximately $7.4 million and $9.5 million,
respectively, of restricted cash and investments held in escrow accounts for future site
reclamation costs. These balances are recorded at cost and are included in Other assets in the
Consolidated Balance Sheets. The estimated fair market value of these investments at December 31,
2008 and 2007 was approximately 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,
non-vested stock appreciation rights (SARs), non-vested restricted stock and any other
convertible securities outstanding.
All shares have been adjusted for the 2-for-1 stock split effective December 5, 2007. For
each of the three years in the period ended December 31, 2008, 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.
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, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares basic |
|
|
243,935 |
|
|
|
240,065 |
|
|
|
233,101 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
7,102 |
|
|
|
10,485 |
|
|
|
12,376 |
|
Restricted stock |
|
|
1,493 |
|
|
|
1,551 |
|
|
|
2,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
252,530 |
|
|
|
252,101 |
|
|
|
247,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount in 2008, 2007 and 2006 excludes 2.2
million, 2.7 million and 2.8 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
68
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 1.1 million shares in 2008, 130,000 shares in
2007 and 256,000 shares in 2006 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 provisions of FASB Interpretation No. 48 (FIN 48),
Accounting for Uncertainties in Income Taxes an interpretation of SFAS No. 109, Accounting for
Income Taxes. This interpretation addresses how tax benefits claimed or expected to be 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,
69
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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.
Recently Adopted Accounting Pronouncement
Fair Value Measurements
During the first quarter of 2008, we adopted 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. On February 12, 2008, the FASB issued FASB Staff Position (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. This deferral of SFAS No. 157 applies to our
asset retirement obligation (ARO), which uses fair value measures at the date incurred to
determine our liability. We do not expect the adoption of SFAS No. 157 to significantly change the
methodology we use to estimate the initial fair value of our ARO.
In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active. FSP FAS 157-3 clarifies the
application of SFAS No. 157 in a market that is not active and provides an example to
illustrate key considerations in determining the fair value of a financial asset when the
market for that financial asset is not active. FSP FAS 157-3 was effective upon issuance,
including prior periods for which financial statements had not been issued. Revisions
resulting from a change in the valuation technique or its application should be accounted for
as a change in accounting estimate following the guidance in FASB Statement No. 154,
Accounting Changes and Error Corrections. FSP FAS 157-3 was effective for the financial
statements included in our quarterly report for the period ended September 30, 2008, but had
no impact on our Consolidated Financial Statements.
As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market participants at the
measurement date (exit price). We utilize market data or assumptions that market participants
would use in pricing the asset or liability, including assumptions about risk and the risks
inherent in the inputs to the valuation technique. These inputs can be readily observable, market
corroborated, or generally unobservable. We primarily apply the market approach for recurring fair
value measurements and endeavor to utilize the best available information. Accordingly, we utilize
valuation techniques that maximize the use of observable inputs and minimize the use of
unobservable inputs. We are able to classify fair value balances based on the observability of
those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (level 1 measurement) and the lowest priority to
unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by
SFAS No. 157 are as follows:
Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting
date. During 2008 we had no level 1 recurring measurements.
Level 2 Pricing inputs are other than quoted prices in active markets included in level 1, which
are either directly or indirectly observable as of the reported date. Level 2 includes those
financial instruments that are valued using models or other valuation methodologies. These models
are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices
for the underlying instruments, as well as other relevant economic measures.
Substantially all of these assumptions are observable in the marketplace throughout the full term
of the instrument,
70