-----BEGIN PRIVACY-ENHANCED MESSAGE-----
Proc-Type: 2001,MIC-CLEAR
Originator-Name: webmaster@www.sec.gov
Originator-Key-Asymmetric:
MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen
TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB
MIC-Info: RSA-MD5,RSA,
GURL8kr9rfvFO38GlVJsBjYvW9hBVESasOYpNVqZOT2yd98TzoFgAJRr21Ie/v9q
/X3mUKNKDlIoePkjVXUTfQ==
<SEC-DOCUMENT>0000899078-01-000150.txt : 20010319
<SEC-HEADER>0000899078-01-000150.hdr.sgml : 20010319
ACCESSION NUMBER: 0000899078-01-000150
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 5
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010316
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: DENBURY RESOURCES INC
CENTRAL INDEX KEY: 0000945764
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 752815171
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-12935
FILM NUMBER: 1570797
BUSINESS ADDRESS:
STREET 1: 5100 TENNYSON PARKWAY, #3000
CITY: PLANO
STATE: TX
ZIP: 75024
BUSINESS PHONE: 9726732000
MAIL ADDRESS:
STREET 1: 17304 PRESTON RD
STREET 2: STE 200
CITY: DALLAS
STATE: TX
ZIP: 75252
FORMER COMPANY:
FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD
DATE OF NAME CHANGE: 19950627
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>0001.txt
<DESCRIPTION>12/31/00 10-K FOR DENBURY RESOURCES INC.
<TEXT>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2000 FORM 10-K
(Mark One)
|X| Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 2000
OR
|_| Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _________ to________
Commission file number 1-12935
------------------------------
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 75-2815171
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
5100 Tennyson Parkway,
Suite 3000, Plano, TX 75024
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (972) 673-2000
Securities registered pursuant to Section 12(b) of the Act:
================================================================================
Title of Each Class Name of Each Exchange on Which Registered
- --------------------------------------------------------------------------------
Common Stock $.001 Par Value New York Stock Exchange
================================================================================
Securities registered pursuant to
Section 12(g) of the Act: 9% Senior Subordinated Notes due 2008
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of March 1, 2001, the aggregate market value of the registrant's Common
Stock held by non-affiliates was approximately $168,142,000.
The number of shares outstanding of the registrant's Common Stock as of
March 1, 2001, was 46,012,608.
DOCUMENTS INCORPORATED BY REFERENCE
Document Incorporated as to
1. Notice and Proxy Statement for 1. Part III, Items 10, 11, 12, and 13
the Annual Meeting of Shareholders
to be held May 23, 2001.
2. Annual Report to Shareholders for 2. Part I, Item 1 and Part II, Items
the year ended December 31, 2000. 5, 6, 7, 8
<PAGE>
<TABLE>
<CAPTION>
Denbury Resources Inc.
2000 Annual Report on Form 10-K
Table of Contents
Item Page
- ---- ----
PART I
<S> <C> <C>
1. Business...........................................................................3
2. Properties.........................................................................8
3. Legal Proceedings..................................................................8
4. Submission of Matters to a Vote of Security Holders................................8
PART II
5. Market for Common Stock and Related Matters........................................9
6. Selected Financial Data............................................................9
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................9
7A. Quantitative and Qualitative Disclosures About Market Risk.........................9
8. Financial Statements and Supplementary Data........................................9
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.....................................................9
PART III
10. Directors and Executive Officers of the Company....................................9
11. Executive Compensation............................................................10
12. Security Ownership of Certain Beneficial Owners and Management....................10
13. Certain Relationships and Related Transactions....................................10
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................10
</TABLE>
-2-
<PAGE>
PART I
Item 1. Business
- ----------------
The Company
Denbury Resources Inc. ("Denbury" or the "Company") is a Delaware
corporation, organized under Delaware General Corporation Law, engaged in the
acquisition, development, operation and exploration of oil and gas properties in
the Gulf Coast region of the United States, primarily in Louisiana and
Mississippi. Denbury's corporate headquarters is located at 5100 Tennyson
Parkway, Suite 3000, Plano, Texas 75024, and its phone number is 972-673-2000.
At December 31, 2000, the Company had 242 employees, 146 of which were employed
in field operations or at the field offices.
Incorporation and Organization
Denbury was originally incorporated in Canada in 1951. In 1992, the
Company acquired all of the shares of a United States operating company, Denbury
Management, Inc. ("DMI"), and subsequent to the merger the Company sold all of
its Canadian assets. Since that time, all of the Company's operations have been
in the United States.
In April 1999, the stockholders approved a move of the Company's
corporate domicile from Canada to the United States as a Delaware corporation.
Along with the move, the Company's 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 the operations and assets of the Company.
The Company has three active wholly owned subsidiaries, Denbury Marine,
L.L.C., Denbury Energy Services, Inc. and Denbury Carbonics L.L.C.
Business Strategy
As part of our corporate strategy, we believe in the following fundamental
principles:
o remain focused in specific regions;
o acquire properties where we believe additional value can be created
through a combination of exploitation, development, exploration and
marketing;
o acquire properties that give us a majority working interest and
operational control or where we believe we can ultimately obtain it;
o maximize the value of our properties by increasing production and
reserves while reducing cost; and
o maintain a highly competitive team of experienced and incentivized
personnel.
Acquisitions of Oil and Gas Properties
Information as to recent acquisitions by the Company is set forth under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - 2000 Acquisitions," appearing on page 28 of the Annual Report and
under "West Mississippi and Little Creek Field," appearing on pages 16 to 19 of
the Annual Report. Such information is incorporated herein by reference.
-3-
<PAGE>
Oil and Gas Operations
Information regarding selected operating data and a discussion of the
Company's significant operating areas and the primary properties within those
three areas are set forth under "Selected Operating Data," appearing on pages 6
through 8 of the Annual Report, and the Operations Sections appearing on pages
10 through 19 of the Annual Report. Such information is incorporated herein by
reference.
Oil and Gas Acreage, Productive Wells, Drilling Activity
Information regarding oil and gas acreage, productive wells and drilling
activity are set forth under "Selected Operating Data," appearing on page 8 of
the Annual Report.
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. The Company
believes that it has good title to its oil and natural gas properties, some of
which are subject to minor encumbrances, easements and restrictions.
Production
Information regarding average production rates, unit sale prices and unit
costs per BOE are set forth under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" appearing on pages 27 and 28 of
the Annual Report.
Significant Oil and Gas Purchasers
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 purchaser would not
be expected to have a material adverse effect upon the Company. For the year
ended December 31, 2000, the Company sold 10% or more of its net production of
oil and gas to the following purchasers: Hunt Refining 24%, Southland Refining
17%, EOTT Energy 16% and Dynegy 10%.
Geographic Segments
All of the Company's operations are in the United States.
Product Marketing
The Company's ability to market oil and gas depends on many factors
beyond its control, including the extent of domestic production and imports of
oil and gas, the proximity of the Company's gas production to pipelines, the
available capacity in such pipelines, the demand for oil and gas, the effects of
weather, and the effects of state and federal regulation. Denbury's production
is primarily from developed fields close to major pipelines or refineries and
established infrastructure. As a result, Denbury has not experienced any
difficulty to date in finding a market for all of its product as it becomes
available or in transporting its product to these markets; however, the Company
cannot assure that it will always be able to market all of its production or
obtain favorable prices. The Company does not currently believe that the loss of
any of its oil or gas purchasers would have a material adverse effect on its
operations.
-4-
<PAGE>
Oil Marketing
Denbury markets its oil to a variety of purchasers, most of which are
large, established companies. The oil is generally sold under a short-term
contract with the sales price based on an applicable posted price, plus a
negotiated premium or the NYMEX price less a discount. This price is determined
on a well-by-well basis and the purchaser generally takes delivery at the
wellhead. Mississippi oil, which accounted for approximately 94% of the
Company's oil production in 2000, is primarily light to medium sour crude and
sells at a significant discount to the NYMEX price. This discount ranged by
field from approximately $0.25 to $9.50 per Bbl in 2000 and the average discount
for the Company's Mississippi oil production was approximately $4.55 per Bbl in
2000. The balance of the oil production, Louisiana oil, is primarily light sweet
crude, which typically sells at a smaller discount to NYMEX.
Natural Gas Marketing
Virtually all of Denbury's natural gas production is close to existing
pipelines and consequently, the Company generally has a variety of options to
market its natural gas. The Company sells the majority of its 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.
Production Price Hedging
The Company enters into various financial contracts to hedge its exposure
to commodity price risk associated with anticipated future oil and natural gas
production. Information as to these activities is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Market Risk Management", appearing on pages 35 through 37 of the Annual Report.
Such information is incorporated herein by reference.
Operating Environment
Price Volatility
The oil and gas industry is affected by many factors that the Company
generally cannot control. Crude oil prices are generally determined by global
supply and demand. After sinking to a five-year low at the end of 1993, oil
prices began a recovery and climbed to prices above $26 during the fourth
quarter 1996. NYMEX crude oil prices ranged from $18 to $22 during most of 1997,
then began to decline throughout 1998 to a year-end price of approximately
$12.00 per Bbl, the lowest level since 1978. After a weak first quarter, oil
prices increased in 1999 because of production cuts by OPEC and other leading
oil exporters, reduced inventories and anticipated increased demand. NYMEX
prices have generally continued to climb throughout 1999 and 2000, and averaged
approximately $19.00 per Bbl for 1999 and approximately $30.00 per Bbl in 2000.
Natural gas prices are influenced by North American supply and demand,
which is often dependent upon weather conditions. Natural gas competes with
alternative energy sources as a fuel for heating and the generation of
electricity. Natural gas prices fluctuate primarily due to weather, storage
concerns and U.S. economic growth. Natural gas prices were high during most of
1996 and 1997, reaching ten year highs. Gas prices declined, however, in
December 1997 and remained lower throughout 1998 and first quarter 1999,
primarily because of a mild winter. Natural gas prices averaged approximately
$2.35 per Mcf in 1999, but increased to an average of approximately $3.90 per
Mcf during 2000, primarily due to low storage levels. As of December 31, 2000,
the NYMEX natural gas prices were almost $10.00 per Mcf, although prices dropped
in the first part of 2001 to between $5.00 and $6.00 per Mcf.
-5-
<PAGE>
The revenues, cash flow and results of operations of the Company are
highly dependent upon the prices of oil and natural gas. During the last three
years, the Company's net income has fluctuated from a loss of $287.1 million in
1998 to net income of $142.2 million in 2000, primarily as a result of
significant changes in oil and natural gas prices. In addition, fluctuations in
commodity prices have a direct impact on the volumes of the Company's proved
reserves and their value.
Oil and Natural Gas Operations
The Company's operations are subject to the usual hazards incident to the
drilling and operation of oil and gas wells, and the processing and
transportation of natural gas and NGLs, such as cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fire, pollution and other
environmental risks. In general, many of these risks increase when drilling at
greater depths under higher pressure conditions. In addition, certain of the
Company's operations are in water and subject to the additional hazards of
marine operations, such as capsizing, collision and damage or loss from severe
weather. Other operations involve the production, handling, processing and
transportation of hazardous substances. These hazards can cause personal injury
and loss of life, severe damage to and destruction of property and equipment,
environmental damage and suspension of operations. Litigation arising from a
catastrophic occurrence in the future at one of the Company's locations could
result in the Company being named as a defendant in lawsuits asserting
potentially large claims. In accordance with customary industry practices,
insurance is maintained for the Company against some, but not all, of the
consequences of these risks. Losses and liabilities arising from such events
could reduce revenues and increase costs to the Company to the extent not
covered by insurance or otherwise already reserved.
Competition and Markets
The Company faces competition from other oil and gas companies in all
aspects of its business, including acquisition of producing properties and oil
and gas leases, marketing of oil and gas, and obtaining goods, services and
labor. Many of its competitors have substantially larger financial and other
resources. Factors that affect the Company's ability to acquire producing
properties include available funds, available information about prospective
properties and the Company's standards established for minimum projected return
on investment. Gathering systems are the only practical method for the
intermediate transportation of natural gas. Therefore, competition for natural
gas delivery is presented by other pipelines and gas gathering systems.
Competition is also presented by alternative fuel sources, including heating oil
and other fossil fuels. Because of the long-lived, high margin nature of the
Company's oil and gas reserves and management's experience and expertise in
exploiting these reserves, management believes that it is effective in competing
in the market.
Federal and State Regulations
There have been, and continue to be, numerous federal and state laws and
regulations governing the oil and gas industry that are often changed in
response to the current political or economic environment. Compliance with this
regulatory burden is often difficult and costly and may carry substantial
penalties for noncompliance. The following are some specific regulations that
may affect the Company. The Company cannot predict the impact of these or future
legislative or regulatory initiatives.
-6-
<PAGE>
Regulation of Natural Gas and Oil Exploration and Production
The Company's 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. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in and the unitization or pooling of oil and gas properties. In
addition, state conservation laws establish maximum rates of production from oil
and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and gas the Company can produce from its
wells and may limit the number of wells or the locations at which the Company
can drill. The regulatory burden on the oil and gas industry increases the
Company's costs of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended and
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
Federal Regulation of Sales Prices and Transportation
Currently, there are no federal, state or local laws that regulate the
price for sales of natural gas, NGLs, crude oil or condensate by the Company.
However, the rates charged and terms and conditions for the movement of gas in
interstate commerce through certain intrastate pipelines and production area
hubs are subject to regulation under the Natural Gas Policy Act of 1978
("NGPA"). Pipeline and hub construction activities are, to a limited extent,
also subject to regulations under the Natural Gas Act of 1938 ("NGA"). While
these controls do not apply directly to the Company, their effect on natural gas
markets can be significant in terms of competition and cost of transportation
services. 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. The Company cannot predict when or if any such proposals
might become effective and their effect, if any, on the Company's 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.
Gathering Regulations
State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements. Such regulation has not generally been applied against gatherers
of natural gas, although natural gas gathering may receive greater regulatory
scrutiny in the future.
Federal, State or Indian Leases
The Company's 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 and other agencies.
Environmental Regulations
Public interest in the protection of the environment has increased
dramatically in recent years. The trend of more expansive and stricter
environmental legislation and regulations could continue. To the extent laws are
enacted or other governmental action is taken that restricts drilling or imposes
environmental protection
-7-
<PAGE>
requirements that result in increased costs to the oil and gas industry in
general, the business and prospects of the Company could be adversely affected.
Various federal, state and local laws regulating the discharge of
materials into the environment, or otherwise relating to the protection of the
environment, directly impact oil and gas exploration, development and production
operations, and consequently may impact the Company's operations and costs.
These regulations include, among others, (i) regulations by the EPA and various
state agencies regarding approved methods of disposal for certain hazardous and
nonhazardous wastes; (ii) the Comprehensive Environmental Response,
Compensation, and Liability Act, Federal Resource Conservation and Recovery Act
and analogous state laws which regulate the removal or remediation of previously
disposed wastes (including wastes disposed of or released by prior owners or
operators), property contamination (including groundwater contamination), and
remedial plugging operations to prevent future contamination; (iii) the Clean
Air Act and comparable state and local requirements which may result in the
gradual imposition of certain pollution control requirements with respect to air
emissions from the operations of the Company; (iv) the Oil Pollution Act of 1990
which contains numerous requirements relating to the prevention of and response
to oil spills into waters of the United States; (v) the Resource Conservation
and Recovery Act which is the principal federal statute governing the treatment,
storage and disposal of hazardous wastes; and (vi) state regulations and
statutes governing the handling, treatment, storage and disposal of naturally
occurring radioactive material ("NORM").
Management believes that the Company is in substantial compliance with
applicable environmental laws and regulations. To date, the Company has 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 the consolidated financial position or results of operations
of the Company.
Estimated Net Quantities of Proved Oil and Gas Reserves and Present Value of
Estimated Future Net Revenues
Estimates of net proved oil and gas reserves as of December 31, 2000 have
been prepared by DeGolyer and MacNaughton, and the estimates as of December 31,
1999 and 1998 were prepared by Netherland, Sewell and Associates, Inc., both
independent petroleum engineers located in Dallas, Texas. See Note 9
"Supplemental Reserve Information" of the Consolidated Financial Statements and
pages 6 and 7 of the Annual Report for disclosure of reserve data. Such
information is incorporated herein by reference.
Item 2. Properties
- -------------------
See Item 1. Business - "Oil and Gas Operations." The Company also has
various operating leases for rental of office space, office equipment, and
vehicles. See Note 7 "Commitments and Contingencies" of the Consolidated
Financial Statements for the future minimum rental payments. Such information is
incorporated herein by reference.
Item 3. Legal Proceedings
- --------------------------
In the opinion of management, there are no material pending legal
proceedings to which the Company or any of its subsidiaries is a party or of
which any of their property is the subject. However, due to the nature of its
business, certain legal or administrative proceedings arise from time to time in
the ordinary course of its business. See Note 7, "Commitments and Contingencies"
of the Consolidated Financial Statements for further disclosure regarding legal
proceedings and contingencies. Such information is included herein by reference.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted for a vote of security holders during the
fourth quarter of 2000.
-8-
<PAGE>
PART II
Item 5. Market for the Common Stock and Related Matters
- --------------------------------------------------------
Information as to the markets in which the Company's common stock is
traded, the quarterly high and low prices for such stock during the last two
years, the restriction on the payment of dividends with respect to the common
stock, and the approximate number of stockholders of record at February 1, 2001,
is set forth under "Common Stock Trading Summary" appearing on page 61 of the
Annual Report. Such information is incorporated herein by reference.
Item 6. Selected Financial Data
- --------------------------------
Selected Financial Data for the Company for each of the last five years
are set forth under "Financial Highlights" appearing on page 2 of the Annual
Report. All such information is incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
- --------------------------------------------------------------------------------
of Operations
- -------------
Information as to the Company's financial condition, changes in financial
condition and results of operations and other matters is set forth in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," appearing on pages 23 through 38 of the Annual Report and is
incorporated herein by reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
- -------------------------------------------------------------------
The information required by Item 7A is set forth under "Market Risk
Management" in "Management's Discussion and Analysis of Financial Condition and
Results of Operations," appearing on pages 35 through 37 of the Annual Report
and is incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data
- ---------------------------------------------------
The Company's consolidated financial statements, accounting policy
disclosures, notes to financial statements, business segment information,
unaudited quarterly information and independent auditors' report are presented
on pages 39 through 60 of the Annual Report. All such information is
incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
- --------------------------------------------------------------------------------
Financial Disclosure
- --------------------
None.
PART III
Item 10. Directors and Executive Officers of the Company
- --------------------------------------------------------
Directors of the Company
Information as to the names, ages, positions and offices with Denbury,
terms of office, periods of service, business experience during the past five
years and certain other directorships held by each director or person nominated
to become a director of Denbury will be set forth in the "Election of Directors"
segment of the Proxy
-9-
<PAGE>
Statement ("Proxy Statement") for the Annual Meeting of Shareholders to be held
May 23, 2001, ("Annual Meeting") and is incorporated herein by reference.
Executive Officers of the Company
Information concerning the executive officers of Denbury will be set
forth in the "Management" section of the Proxy Statement for the Annual Meeting
and is incorporated herein by reference.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 and the rules
thereunder require the Company's executive officers and directors, and persons
who beneficially own more than ten percent (10%) of a registered class of the
Company's equity securities, to file reports of ownership and changes in
ownership with the Securities and Exchange Commission and exchanges and to
furnish the Company with copies. Based solely on its review of the copies of
such forms received by it, or written representations from such persons, the
Company is not aware of any person who failed to file any reports required by
Section 16(a) to be filed for fiscal 2000.
Item 11. Executive Compensation
- -------------------------------
Information concerning remuneration received by Denbury's executive
officers and directors will be presented under the caption "Statement of
Executive Compensation" in the Proxy Statement for the Annual Meeting and is
incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- -----------------------------------------------------------------------
Information as to the number of shares of Denbury's equity securities
beneficially owned as of March 15, 2001, by each of its directors and nominees
for director, its five most highly compensated executive officers and its
directors and executive officers as a group will be presented under the caption
"Security Ownership of Certain Beneficial Owners and Management" in the Proxy
Statement for the Annual Meeting and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
- -------------------------------------------------------
Information on related transactions will be presented under the caption
"Compensation Committee Interlocks and Insider Participation" and "Interests of
Insiders in Material Transactions" in the Proxy Statement for the Annual Meeting
and is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- ------------------------------------------------------------------------
(a) Financial Statements and Schedules. Financial statements and schedules
filed as a part of this report are presented on pages 39 through 60 of the
Annual Report and are incorporated herein by reference.
-10-
<PAGE>
Exhibits. The following exhibits are filed as a part of this report.
Exhibit
No. Exhibit
- ------- -------
3(a) Certificate of Incorporation of Denbury Resources Inc. filed with the
Delaware Secretary of State on April 20, 1999 (incorporated by refer-
ence as Exhibit 3(a) of the Registrant's Form 10-Q for the quarter
ended March 31, 1999).
3(b) Bylaws of Denbury Resources Inc., a Delaware corporation, adopted
April 20, 1999 (incorporated by reference as Exhibit 3(b) of the
Registrant's Form 10-Q for the quarter ended March 31, 1999).
4(a) Form of Indenture between Denbury Management and Chase Bank of Texas,
National Association, as trustee (incorporated by reference as Exhibit
4(b) of Registrant's Registration Statement on Form S-3 dated February
19, 1998).
4(b) First Supplemental Indenture dated as of April 21, 1999, between
Denbury Resources Inc., a Delaware corporation, and Chase Bank of
Texas, National Association, as Trustee, relating to Denbury
Management, Inc.'s 9% Senior Subordinated Notes due 2008 (incorporated
by reference to Exhibit 4(a) of the Registrant's Form 10-Q for the
quarter ended March 31, 1999).
10(a) Second Amended and Restated Credit Agreement, dated October 13, 2000,
between the Company and Bank of America, N.A., as Administrative
Agent, and the financial institutions listed on schedule 2.1 therein
(incorporated by reference to Exhibit 10 of the Registrant's Form 10-Q
for the quarter ended September 30, 2000).
10(b)** Denbury Resources Inc. Stock Option Plan (incorporated by reference as
Exhibit 4(f) of the Registrant's Registration Statement on Form S-8,
No. 333-1006, dated February 2, 1996, and as amended by the Regis-
trant's Registration Statements on Form S-8, Nos. 333-27995, 333-
55999 and 333-70485, dated May 29, 1997, June 4, 1998 and July 12,
1999, respectively).
10(c)** Denbury Resources Inc. Stock Purchase Plan (incorporated by reference
as Exhibit 4(g) of the Registrant's Registration Statement on Form
S-8, No. 333-1006, dated February 2, 1996, and as amended by the Regi-
strant's Registration Statements on Form S-8, No. 333-70485, dated
January 12, 1999 and No. 333-39172, dated June 13, 2000).
10(d) Form of indemnification agreement between Denbury Resources Inc. and
its officers and directors (incorporated by reference as Exhibit 10 of
the Registrant's Form 10-Q for the quarter ended June 30, 1999).
10(e)** Denbury Resources Inc. Directors Compensation Plan (incorporated by
reference as Exhibit 4 of the Registrant's Registration Statement on
Form S-8, No. 333-39172, dated June 13, 2000 and amended March 2,
2001).
10(f)* ** Denbury Resources Severance Protection Plan, dated December 6, 2000.
-11-
<PAGE>
Exhibit
No. Exhibit
- ------- -------
10(g) Stock Purchase Agreement between TPG Partners II, L.L.C. and the
Company dated as of December 16, 1998 (incorporated by reference as
Exhibit 99.1 of the Registrant's Form 8-K dated December 17, 1998).
13* Annual Report to Shareholders.
21* List of Subsidiaries of Denbury Resources Inc.
23* Consent of Deloitte & Touche LLP.
* Filed herewith.
** Compensation arrangements.
(b) Reports on Form 8-K.
(i) On October 10, 2000, the Company filed a Current Report on
Form 8-K that reported under Item 5, "Other Events," that Ms.
Carrie Wheeler had been elected to the Company's Board of
Directors to fill the vacancy created by the resignation of
Mr. David Stanton.
(ii) On October 27, 2000, the Company filed a Current Report on
Form 8-K that reported under Item 2, "Acquisition or
Disposition of Assets," that the Company had purchased or had
signed purchase and sale agreements for the purchase of $66.5
million of oil and natural gas properties located in southwest
Louisiana.
(iii) On January 26, 2001, the Company filed a Current Report on
Form 8-K that reported under Item 2, "Acquisition or
Disposition of Assets," that on January 18, 2001, the Company
had signed a purchase and sale agreement to acquire carbon
dioxide ("CO2") reserves, production and associated assets
from a unit of Airgas Inc. for $42 million, effective January
1, 2001.
-12-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Denbury Resources Inc. has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
DENBURY RESOURCES INC.
March 16, 2001 /s/ Phil Rykhoek
--------------------------------------
Phil Rykhoek
Chief Financial Officer and Secretary
March 16, 2001 /s/ Mark C. Allen
---------------------------------------
Mark C. Allen
Chief Accounting Officer and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of Denbury
Resources Inc. and in the capacities and on the dates indicated.
March 16, 2001 /s/ Ronald G. Greene
---------------------------------------
Ronald G. Greene
Chairman of the Board and Director
March 16, 2001 /s/ Gareth Roberts
---------------------------------------
Gareth Roberts
Director, President and Chief Executive
Officer
(Principal Executive Officer)
March 16, 2001 /s/ Phil Rykhoek
---------------------------------------
Phil Rykhoek
Chief Financial Officer and Secretary
(Principal Financial Officer)
March 16, 2001 /s/ Mark C. Allen
---------------------------------------
Mark C. Allen
Chief Accounting Officer and Controller
(Principal Accounting Officer)
March 16, 2001 /s/ David I. Heather
---------------------------------------
David I. Heather
Director
March 16, 2001 /s/ Wieland F. Wettstein
---------------------------------------
Wieland F. Wettstein
Director
-13-
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>2
<FILENAME>0002.txt
<DESCRIPTION>EXHIBIT 10 (F) - SEVERANCE PROTECTION PLAN
<TEXT>
EXHIBIT 10 (f)
DENBURY RESOURCES
SEVERANCE PROTECTION PLAN
ARTICLE I
ESTABLISHMENT OF PLAN
As of the Effective Date, Denbury Resources, Inc. (the "Company") hereby
establishes a severance compensation plan known as the Denbury Resources
Severance Protection Plan (the "Plan"), as set forth in this document. For
purposes of the Employee Retirement Income Security Act of 1974, as amended
("ERISA"), the Company intends the Plan to be a "Severance Plan" within the
meaning of the applicable ERISA regulations.
ARTICLE II
DEFINITIONS
As used herein, the following words and phrases shall have the following
respective meanings unless the context clearly indicates otherwise.
Section 2.1 Administrator. The Board or any committee thereof as may be
appointed from time to time by the Board to supervise the administration of the
Plan.
Section 2.2 Affiliate. With respect to a specified person, a person that
directly or indirectly through one or more intermediaries, controls, is
controlled by, or is under common control with the specified person.
Section 2.3 Base Salary. The amount a Participant is entitled to receive as
wages or salary on an annualized basis, calculated on the basis of their salary
rate on either the date immediately prior to a Change in Control or their
Termination Date, whichever amount is higher.
Section 2.4 Board. The Board of Directors of the Company.
Section 2.5 Bonus Amount. An amount equal to fifty percent (50%) of the
total amount of bonuses awarded to the Participant during the twenty-four months
prior to the date of the Change in Control.
Section 2.6 Cause. An Employer shall have "Cause" to terminate a
Participant if the Participant (i) willfully and continually fails to
substantially perform his duties with the Employer (other than a failure
resulting from the Participant's incapacity due to physical or mental illness)
which failure continues for a period of at least thirty (30) days after a
written notice of demand for substantial performance has been delivered to the
Participant specifying the manner in which the Participant has failed to
substantially perform, or (ii) willfully engages in conduct which is
demonstrably and materially injurious to the Employer, monetarily or otherwise;
provided, however, that no termination of the Participant's employment shall be
for Cause until there shall have been delivered to the Participant a copy of a
written notice specifying in detail the particulars of the Participant's conduct
which violates either (i) or (ii) above. No act, nor failure to act, on the
Participant's part, shall be considered "willful" unless he has acted or failed
to act with an absence of good faith and without a reasonable belief that his
action or failure to act was in the best interest of the Employer.
Notwithstanding anything contained in this Plan to the contrary, no failure to
perform by the Participant after Notice of Termination is given by or to the
Participant shall constitute Cause.
EX 10 - 1
<PAGE>
Section 2.7 Change in Control. A "Change in Control" shall mean any one of
the following:
(a) "Continuing Directors" no longer constitute a majority of the
Board; the term "Continuing Director" means any individual who has served
in such capacity for one year or more;
(b) after the date of adoption of the severance plan, any person or
group of persons acting together as an entity (other than the Texas Pacific
Group and its Affiliates) become (i) the beneficial owners (as defined in
Rule 13d-3 under the Securities Exchange Act of 1934, as amended) directly
or indirectly, of shares of common stock representing thirty percent (30%)
or more of the voting power of the Company's then outstanding securities
entitled generally to vote for the election of the Company's directors, and
(ii) the largest beneficial owner directly or indirectly of the Company's
then outstanding securities entitled generally to vote for the election of
the Company's directors;
(c) the merger or consolidation to which the Company is a party if
(i) the stockholders of the Company immediately prior to the effective date
of such merger or consolidation have beneficial ownership (as defined in
Rule 13d-3 under the Exchange Act) of less than forty percent (40%) of the
combined voting power to vote for the election of directors of the
surviving corporation or other entity following the effective date of such
merger or consolidation; or (ii) fifty percent (50%) or more of the
individuals constituting the members the Investment Committee are
terminated due to the Change in Control; or
(d) the sale of all or substantially all, of the assets of the Company
or the liquidation or dissolution of the Company.
Notwithstanding the foregoing provisions of this Section 2.6, if a
Participant's employment with the Employer is terminated by the Employer other
than for "Cause" six months prior to the date on which a Change in Control
occurs, such termination shall be deemed to have occurred immediately following
a Change in Control.
Notwithstanding anything herein to the contrary, under no circumstances
will a change in the constitution of the board of directors of any Subsidiary, a
change in the beneficial ownership of any Subsidiary, the merger or
consolidation of a Subsidiary with any other entity, the sale of all or
substantially all of the assets of any Subsidiary or the liquidation or
dissolution of any Subsidiary constitute a "Change in Control" under this Plan.
Section 2.8 Common Shares means shares of common stock, $.001 par value of
Denbury Resources Inc.
Section 2.9 Company. Denbury Resources Inc., a Delaware corporation.
Section 2.10 Effective Date. The date the Plan is approved by the Board of
Directors of the Company, or such other date as the Board shall designate in its
resolution approving the Plan.
Section 2.11 Employer. The Company and any Subsidiary of the Company which
adopts this Plan as a Participating Employer. With respect to a Participant who
is not an employee of the Company, any reference under this Plan to such
Participant's "Employer" shall refer only to the employer of the Participant,
and in no event shall be construed to refer to the Company as well.
Section 2.12 Good Reason. "Good Reason" shall mean the occurrence of any of
the following events or conditions:
(a) a change in the Participant's status, title, position or
responsibilities (including reporting
EX 10 - 2
<PAGE>
responsibilities) which, in the Participant's reasonable judgment,
represents a substantial reduction of the status, title, position or
responsibilities as in effect immediately prior thereto; the assignment to
the Participant of any duties or responsibilities which, in the
Participant's reasonable judgment, are inconsistent with such status,
title, position or responsibilities; or any removal of the Participant
from, or failure to reappoint or reelect him to, any such position with the
Employer, including, but not limited to corporate officer positions or
positions as a member of the Investment Committee, except in connection
with the termination of his employment for Cause or by the Participant
other than for Good Reason;
(b) a reduction in the Participant's Base Salary, as such base salary
may be increased from time to time thereafter, or the failure by the
Employer to provide the Participant with compensation and benefits at least
equal (in terms of benefit levels and/or reward opportunities) to those
provided for under each employee benefit plan, program and practice as in
effect immediately prior to the Change in Control (or as in effect
following the Change in Control, if greater), including, but not limited
to, any stock option plan, stock purchase plan, pension plan, life
insurance plan, health and accident plan or disability plan;
(c) the Employer's requiring the Participant (without the consent of
the Participant) to be based at any place outside a twenty-five (25) mile
radius of his place of employment immediately prior to a Change in Control,
except for reasonably required travel on the Employer's business which is
not materially greater than such travel requirements prior to the Change in
Control, or, in the event the Participant consents to any relocation beyond
such 25 mile radius, the failure by the Employer to pay (or reimburse the
Participant) for all reasonable moving expenses incurred by him relating to
a change of his principal residence in connection with such relocation and
to indemnify the Participant against any loss (defined as the difference
between the actual sale price of such residence and the higher of (i) his
aggregate investment in such residence or (ii) the fair market value of
such residence as determined by a real estate appraiser designated by the
Participant and reasonably satisfactory to the Employer) realized on the
sale of the Participant's principal residence in connection with any such
change of residence;
(d) any material breach by the Employer of any provision of this Plan;
(e) any purported termination of the Participant's employment for
Cause by the Employer which does not otherwise comply with the terms of
this Plan; or
(f) in the case of a Change in Control pursuant to Section 2.6(d),
the failure of the Company to obtain the assumption of, or the agreement to
perform, this Agreement by the purchaser or purchasers of the Company's
assets as contemplated in Article VII.
Section 2.13 Investment Committee. Each employee of the Employer who has
been designated by his Employer as a member of the Investment Committee, as the
membership of such Committee may be changed from time to time. Members of the
Investment Committee as of the date of the Plan's execution are listed on
Schedule B attached hereto.
Section 2.14 Management Group Employee. Each employee of the Employer who
has been designated by his Employer as a "Management Group Employee", as may be
designated from time to time by the Board. Management Group Employees as of the
date of the Plan's execution are listed on Schedule C attached hereto.
Section 2.15 Notice of Termination. A notice which indicates the specific
provisions in this Plan relied upon as the basis for any termination of
employment which sets forth in reasonable detail the facts and circumstances
claimed to provide a basis for termination of the Participant's employment under
the provision so
EX 10 - 3
<PAGE>
indicated; no purported termination of employment shall be effective without
such Notice of Termination.
Section 2.16 Officer. Each employee of the Employer that is a corporate
officer and is so designated from time to time pursuant to the Company's Bylaws.
Officers as of the date of the Plan's execution are listed on Schedule A
attached hereto.
Section 2.17 Participant. A Participant who meets the eligibility
requirements of Article III.
Section 2.18 Participating Employer. A Subsidiary of the Company which
adopts this Plan in accordance with Section 8.4 below, and listed on Schedule D
attached hereto, and as may be amended from time to time pursuant to Article
VIII of the Plan.
Section 2.19 Payment Date. For a Participant, the fifteenth (15th) day
after the event triggering the right of that Participant to a Severance Benefit.
Section 2.20 Severance Benefit. The benefits payable in accordance with
Article IV of the Plan.
Section 2.21 Severance Units. A Participant who is neither a member of the
Investment Committee, nor a Management Group Employee nor Officer shall receive
one (1) Severance Unit, to be used in calculating his Severance Benefit, for (i)
each ten thousand dollars ($10,000) of his Base Salary plus Bonus Amount, and
(ii) each twelve months of employment by the Company or an Employer; the sum of
any partial Severance Units under (i) and (ii) shall be rounded to the nearest
higher whole number of Severance Units. However, the maximum number of Severance
Units that may be granted to a Participant is eighteen (18), and each
Participant shall be granted at least four (4) Severance Units.
Section 2.22 Subsidiary. Any subsidiary of the Company, and any wholly or
partially owned partnership, joint venture, limited liability company,
corporation and other form of investment by the Company.
Section 2.23 Termination Date. In the case of the Participant's death, the
Participant's Termination Date shall be his date of death. In all other cases,
the Participant's Termination Date shall be the date specified in the Notice of
Termination subject to the following:
(a) If the Participant's employment is terminated by the Employer for
Cause, the date specified in the Notice of Termination shall be at least
thirty (30) days from the date the Notice of Termination is given to the
Participant; and
(b) If the Participant terminates his employment for Good Reason, the
date specified in the Notice of Termination shall not be more than sixty
(60) days from the date the Notice of Termination is given to the Employer.
ARTICLE III
ELIGIBILITY AND PARTICIPATION
Section 3.1 Participation. Once a person is employed by their Employer they
shall automatically become a Participant in the Plan.
Section 3.2 Duration of Participation. A Participant shall cease to be a
Participant in the Plan upon the first to occur of: (i) the date he ceases to be
an employee of the Employer at any time six months prior to a Change in Control,
(ii) the date his employment is terminated following a Change in Control under
circumstances
EX 10 - 4
<PAGE>
where he is not entitled to a Severance Benefit under the terms of this Plan, or
(iii) the date on which he has received all of the benefits to which he is
entitled under this Plan.
ARTICLE IV
SEVERANCE BENEFITS
Section 4.1 Right to Severance Benefit.
(a) After a Change in Control has occurred, a Participant shall be
entitled to receive from the Employer a Severance Benefit in the amount
provided in Sections 4.2 and 4.3 if his employment is terminated during the
period beginning six months prior to a Change of Control and ending two
years after a Change of Control, for any reason other than (i) termination
by the Employer for Cause or (ii) termination by the Participant for other
than Good Reason.
(b) A Participant shall be entitled to a Severance Benefit if that
individual satisfies all the conditions under the Plan required to qualify
as a Participant and he or she is not otherwise disqualified or excluded
from eligibility under the terms of the Plan.
(c) Notwithstanding any other provision of the Plan, the sale,
divestiture or other disposition of a Subsidiary, shall not be deemed to be
a termination of employment of employees employed by such Subsidiary, and
such employees shall not be entitled to benefits from the Company or any
Participating Employer under this Plan as a result of such sale,
divestiture, or other disposition, or as a result of any subsequent
termination of employment.
Section 4.2 Amount of Severance Benefit. If a Participant is entitled to a
Severance Benefit under Section 4.1, the employer shall pay to the Participant,
on or before the Payment Date, an amount in cash equal to one of the following
amounts:
(1) for the Company's Chief Executive Officer and for all other
members of the Investment Committee, three (3) times the sum
of the Participant's Base Salary and the Bonus Amount;
(2) for all other Officers that are not members of the
Investment Committee, two and one-half (2-1/2) times the sum
of the Participant's Base Salary and the Bonus Amount;
(3) for all members of the Management Group, two (2) times the
sum of the Participant's Base Salary and the Bonus Amount;
(4) for all other employees, one-twelfth (1/12) of the sum of
the Participant's Base Salary and Bonus Amount multiplied by
the Participant's Severance Units.
Section 4.3 Further Benefits. If a Participant is entitled to a Severance
Benefit under Section 4.1, such Participant shall also be entitled to:
(a) Continuation at Employer's expense, on behalf of the Participant
and his dependents and beneficiaries, all medical, dental, vision, and
health benefits and insurance coverage which were being provided to the
Participant at the time of termination of employment for a period of time
subsequent to the Participant's termination of employment. This period of
time shall be equal to fifty percent (50%) of the
EX 10 - 5
<PAGE>
number of months of compensation represented by the Participants' Severance
Benefit, with the number of months of compensation to be based upon the
Participant's monthly Base Salary immediately prior to the Termination
Date. The benefits provided in this Section 4.3(a) shall be no less
favorable to the Participant, in terms of amounts and deductibles and costs
to him, than the coverage provided the Participant under the plans
providing such benefits at the time of termination of Participant's
employment. An Employer may pay the employee's cost of benefits provided
pursuant to Consolidated Omnibus Budget Reconciliation Act of 1986 and
allowed under the Employer's benefit plans for the applicable period of
time in order to satisfy its obligation under this provision.
(b) The Employer's obligation hereunder to provide a benefit shall
terminate if the Participant obtains comparable coverage under a subsequent
employer's benefit plan. For purposes of the preceding sentence, benefits
will not be comparable during any waiting period for eligibility for such
benefits or during any period during which there is a preexisting condition
limitation on such benefits. The Employer also shall pay a lump sum equal
to the amount of any additional income tax payable by the Participant and
attributable to the benefits provided under subparagraph (a) of this
Section at the time such tax is imposed upon the Participant. At the end of
the period of coverage set forth above, the Participant shall have the
option to have assigned to him at no cost to the Participant and with no
apportionment of prepaid premiums, any assignable insurance owned by the
Employer and relating specifically to the Participant, and the Participant
shall be entitled to all health and similar benefits that are or would have
been made available to the Participant under law.
Section 4.4 Mitigation or Set-off of Amounts Payable Hereunder. The
Participant shall not be required to mitigate the amount of any payment provided
for in this Article IV by seeking other employment or otherwise, nor shall the
amount of any payment provided for in this Article IV be reduced by any
compensation earned by the Participant as the result of employment by the
Company or any successor after the Payment Date or by another employer after the
Termination Date, or otherwise. The Employer's obligations hereunder also shall
not be affected by any set-off, counterclaim, recoupment, defense or other
claim, right or action which the Employer may have against the Participant.
Section 4.5 Company Guarantee of Severance Benefit. In the event a
Participant becomes entitled to receive from the Employer a Severance Benefit
under this Article IV above and such Employer fails to pay such Severance
Benefit, the Company shall assume the obligation of such Employer to pay such
Severance Benefit. In consideration of the Company's assumption of the
obligation to pay such Severance Benefit provided under this Plan, the Company
(as the source of payment of benefits under the Plan) shall be subrogated to any
recovery (irrespective of whether there is recovery from the third party of the
full amount of all claims against the third party) or right to recovery of
either a Participant or his legal representative against the Employer or any
person or entity. The Participant or his legal representative shall cooperate in
doing what is reasonably necessary to assist the Company in exercising such
rights, including but not limited to notifying the Company of the institution of
any claim against a third party and notifying the third party and the third
party's insurer, if any, of the Company's subrogation rights. Neither the
Participant nor his legal representative shall do anything after a loss to
prejudice such rights. In its sole discretion, the Company reserves the right to
prosecute an action in the name of the Participant or his legal representative
against any third parties potentially liable to the Participant. The Company
shall have the absolute discretion to settle subrogation claims on any basis it
deems warranted and appropriate under the circumstances. If a Participant or his
legal representative initiates a lawsuit against any third parties potentially
liable to the Participant, the Company shall not be responsible for any
attorney's fees or court costs that may be incurred in such liability claim. The
Company shall be entitled, to the extent of any payments made to or on behalf of
a Participant or a dependent of the Participant, to be paid first from the
proceeds of any settlement or judgment that may result from the exercise of any
rights of recovery asserted by or on behalf of a Participant or his legal
representative against any person or entity legally responsible for the injury
for which such payment was made. The right is also hereby given the Company to
receive directly from the Employer or any third party(ies), attorney(s) or
insurance company(ies) an amount equal to the amount paid to or on behalf of the
Participant.
EX 10 - 6
<PAGE>
Section 4.6 Agreement to Plan, Election of Severance Benefits. By
acceptance of any Severance Benefit from the Plan, the Participant shall be
deemed to have agreed to adhere to all terms of the Plan. A Participant who is
entitled to severance benefits under an employment agreement with the Employer
may elect, in writing within ten (10) days after his Termination Date, to
receive the severance benefits provided under this Plan in lieu of, but not in
addition to, such other severance benefits as may be provided by such other
agreement. In the event that no election is made, the Participant shall forego
his right to receive the severance benefits provided under this Plan.
Section 4.7 Forfeiture of Severance Benefits. A Participant shall forfeit
any and all entitlement to any Severance Benefit if the Administrator determines
that the Participant has failed to fulfill any requirement of the Plan.
Section 4.8 Payment after Death. If a Participant dies before his or her
Severance Benefits have been paid in full, the remaining Severance Benefits will
be paid to the beneficiaries named in such Participant's last will and
testament, or if no will or beneficiary exist then to such Participant's heirs
at law. The Plan shall be discharged fully and completely to the extent of any
payment made to any such beneficiaries or heirs at law.
ARTICLE V
TERMINATION OF EMPLOYMENT
Section 5.1 Written Notice Required. Any purported termination of
employment, either by the Employer or by the Participant, shall be communicated
by written Notice of Termination to the other.
ARTICLE VI
ADDITIONAL PAYMENTS BY THE COMPANY
Section 6.1 Gross-Up Payment. In the event it shall be determined that any
payment or distribution of any type by the Employer to or for the benefit of an
Officer, whether paid or payable or distributed or distributable pursuant to the
terms of this Plan or otherwise (the "Total Payments"), would be subject to the
excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as
amended (the "Code") or any interest or penalties with respect to such excise
tax (such excise tax, together with any such interest and penalties, are
collectively referred to as the "Excise Tax", then the Officer shall be entitled
to receive an additional payment (a "Gross-Up Payment") in an amount such that
at the time of payment by the Officer of all taxes (including additional excise
taxes under said Section 4999 and any interest, and penalties imposed with
respect to any taxes) imposed upon the Gross-Up Payment, the Officer shall have
an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Total
Payments. The Company shall pay the Gross-Up Payment to the Officer within
twenty (20) business days after the Payment Date or the Termination Date,
whichever is applicable.
Section 6.2 Determination By Accountant. All determinations required to be
made under this Article VI, including whether a Gross-Up Payment is required and
the amount of such Gross-Up Payment, shall be made by the independent accounting
firm retained by the Company on the date of Change in Control (the "Accounting
Firm"), which shall provide detailed supporting calculations both to the Company
and the Officer within fifteen (15) business days of the Payment Date or
Termination Date, whichever is applicable, or such earlier time as is requested
by the Company. If the Accounting Firm determines that no Excise Tax is payable
by the Officer, it shall furnish the Officer with an opinion that he has
substantial authority not to report any Excise Tax on his federal income tax
return. Any determination by the Accounting Firm shall be binding upon the
Company and the Officer. As a result of the uncertainty in the application of
Section 4999 of the Code at the time of the initial determination by the
Accounting Firm hereunder, it is possible that a Gross-Up Payment which will not
have been
EX 10 - 7
<PAGE>
made by the Company should have been made ("Underpayment"), consistent with the
calculations required to be made hereunder. In the event that the Company
exhausts its remedies pursuant to Section 6.3 and the Officer thereafter is
required to make a payment of any Excise Tax, the Accounting Firm shall
determine the amount of the Underpayment that has occurred and any such
Underpayment shall be promptly paid by the Company to or for the benefit of the
Officer.
Section 6.3 Notification Required. The Officer shall notify the Company in
writing of any claim by the Internal Revenue Service that, if successful, would
require the payment by the Company of the Gross-Up Payment. Such notification
shall be given as soon as practicable but no later than ten (10) business days
after the Officer knows of such claim and shall apprise the Company of the
nature of such claim and the date on which such claim is requested to be paid.
The Officer shall not pay such claim prior to the expiration of the thirty (30)
day period following the date on which it gives such notice to the Company (or
such shorter period ending on the date that any payment of taxes with respect to
such claim is due). If the Company notifies the Officer in writing prior to the
expiration of such period that it desires to contest such claim, the Officer
shall:
(a) give the Company any information reasonably requested by the
Company relating to such claim,
(b) take such action in connection with contesting such claim as the
Company shall reasonably request in writing from time to time, including,
without limitation, accepting legal representation with respect to such
claim by an attorney reasonably selected by the Company,
(c) cooperate with the Company in good faith in order to effectively
contest such claim,
(d) permit the Company to participate in any proceedings relating to
such claim, provided, however, that the Company shall bear and pay directly
all costs and expenses (including additional interest and penalties)
incurred in connection with such contest and shall indemnify and hold the
Officer harmless, on an after-tax basis, for any Excise Tax or income tax,
including interest and penalties with respect thereto, imposed as a result
of such representation and payment of costs and expenses. Without
limitation on the foregoing provisions of this Section 6.3, the Company
shall control all proceedings taken in connection with such contest and, at
its sole option, may pursue or forgo any and all administrative appeals,
proceedings, hearings and conferences with the taxing authority in respect
of such claim and may, at its sole option, either direct the Officer to pay
the tax claimed and sue for a refund, or contest the claim in any
permissible manner, and the Officer agrees to prosecute such contest to a
determination before any administrative tribunal, in a court of initial
jurisdiction and in one or more appellate courts, as the Company shall
determine; provided, however, that if the Company directs the Officer to
pay such claim and sue for a refund, the Company shall advance the amount
of such payment to the Officer, on an interest-free basis and shall
indemnify and hold the Officer harmless, on an after-tax basis, from any
Excise Tax or income tax, including interest or penalties with respect
thereto, imposed with respect to such advance or with respect to any
imputed income with respect to such advance; and further provided that any
extension of the statute of limitations relating to payment of taxes for
the taxable year of the Officer with respect to which such contested amount
is claimed to be due is limited solely to such contested amount.
Furthermore, the Company's control of the contest shall be limited to
issues with respect to which a Gross-Up Payment would be payable hereunder
and the Officer shall be entitled to settle or contest, as the case may be,
any other issue raised by the Internal Revenue Service or any other taxing
authority.
Section 6.4 Repayment. If, after the receipt by the Officer of an amount
advanced by the Company pursuant to Section 6.3, the Officer becomes entitled to
receive any refund with respect to such claim, the Officer
EX 10 - 8
<PAGE>
shall (subject to the Company's complying with the requirements of Section 6.3)
promptly pay to the Company the amount of such refund (together with any
interest paid or credited thereon after taxes applicable thereto). If, after the
receipt by the Officer of an amount advanced by the Company pursuant to Section
6.3, a determination is made that the Officer shall not be entitled to any
refund with respect to such claim and the Company does not notify the Officer in
writing of its intent to contest such denial of refund prior to the expiration
of thirty days after such determination, then such advance shall be forgiven and
shall not be required to be repaid and the amount of such advance shall offset,
to the extent thereof, the amount of Gross-Up Payment required to be paid.
ARTICLE VII
SUCCESSORS TO COMPANY
Section 7.1 Successors. This Plan shall bind any successor (whether direct
or indirect, by purchase, merger, consolidation or otherwise) to all or
substantially all of the business and/or assets of the Company, in the same
manner and to the same extent that the Company would be obligated under this
Plan if no succession had taken place. In the case of any transaction in which a
successor would not, by the foregoing provision or by operation of law, be bound
by this Plan, the Company shall require such successor expressly and
unconditionally to assume and agree to perform the Company's obligations under
this Plan, in the same manner and to the same extent that the Company would be
required to perform if no such succession had taken place. Failure of the
Company to obtain such agreement prior to the effectiveness of any such
succession shall be a breach hereof and shall entitle the Participant to
compensation from the Company in the same amount and on the same terms as the
Participant would be entitled hereunder if the Participant terminated his
employment for Good Reason, except that for purposes of implementing the
foregoing, the date on which any such succession becomes effective shall be
deemed the Termination Date. As used herein, "the Company" shall mean the
Company as hereinbefore defined and any successor to its business and/or assets
as aforesaid which executes and delivers the agreement provided for in this
Section 7.1 or which otherwise becomes bound by all the terms and provisions
hereof by operation of law.
ARTICLE VIII
DURATION, AMENDMENT, PLAN TERMINATION
AND ADOPTION BY SUBSIDIARIES
Section 8.1 Duration. This Plan shall continue in effect until terminated
in accordance with Section 8.2. If a Change in Control occurs, this Plan shall
continue in full force and effect, and shall not terminate or expire, until
after all Participants who have become entitled to a Severance Benefit hereunder
shall have received all of such benefits in full.
Section 8.2 Amendment and Termination. The Plan and its attached Schedules
may be terminated or amended in any respect by resolution adopted by two-thirds
of the Board; provided, however, that no such amendment or termination of the
Plan may be made if such amendment or termination would adversely affect any
right of a Participant who became a Participant prior to the later of (i) the
date of adoption of any such amendment or termination, or (ii) the effective
date of any such amendment or termination; and, provided further, that the Plan
no longer shall be subject to amendment, change, substitution, deletion,
revocation or termination in any respect whatsoever following a Change in
Control.
Section 8.3 Form of Amendment. The form of any amendment or termination of
the Plan shall be a written instrument signed by a duly authorized officer or
officers of the Company, certifying that the amendment or termination has been
approved by the Board.
EX 10 - 9
<PAGE>
Section 8.4 Adoption by Subsidiaries. Any Subsidiary of the Company may,
with the approval of the Board of Directors of the Company, adopt and become an
Employer under this Plan by executing and delivering to the Company an
appropriate instrument agreeing to be bound as an Employer by all of the terms
of the Plan with respect to its eligible employees. The adoptive instrument may
contain such changes and amendments in the terms and provisions of the Plan as
adopted by such Subsidiary as may be desired by such Subsidiary and acceptable
to the Company. The adoptive instrument shall specify the effective date of such
adoption of the Plan and shall become as to such adopting Subsidiary a part of
this Plan.
ARTICLE IX
CLAIMS AND APPEAL PROCEDURES
Section 9.1 Claims Procedure. With respect to any claim for Severance
Benefits under the Plan, the Administrator will issue a decision on whether the
claim is denied or granted within fifteen (15) days after receipt of the claim
by the Administrator, unless special circumstances require an extension of time
for processing the claim, in which case a decision will be rendered not later
than twenty (20) days after receipt of the claim. Written notice of the
extension will be furnished to the Participant prior to the expiration of the
initial fifteen (15) day period and will indicate the special circumstances
requiring an extension of time for processing the claim and will indicate the
date the Administrator expects to render its decision. If the claim is denied in
whole or in part, the decision in writing by the Administrator shall include the
specific reasons for the denial and reference to the Plan provisions on which
the denial is based. The decision also shall include a description of any
additional information which the Participant needs to submit in order to refile
the claim, along with an explanation of why such additional information is
necessary and how the procedure for reviewing claims works. If the notice of
denial is not furnished in accordance with the above procedure, the claim shall
be deemed denied and the Participant is permitted to proceed with the review
procedure.
Section 9.2 Appeals Procedure. If his claim is denied in whole or in part,
an Participant may appeal in writing a denial of the claim, in part or in whole,
and request a review by the Administrator. The appeal must be submitted within
sixty (60) days after notice of the denial of the claim. The Participant may
request in writing to review copies of pertinent Plan documents in connection
with the appeal. The Administrator will review the appeal and notify the
Participant of the final decision within fifteen (15) days after receiving the
request for review unless the Administrator requires an extension due to special
circumstances, in which case the final decision will be made within twenty (20)
days after the Administrator receives the request for review. The notice of the
final decision must include the specific reasons for the decision and specific
references to the pertinent Plan provisions on which the Administrator's
decision is based.
Section 9.3 Exclusive Initial Remedy. No action may be brought for benefits
provided by this Plan or to enforce any right hereunder until after a claim has
been submitted to and determined by the Administrator and all appeal rights
under the Plan have been exhausted. Thereafter, the Participant may bring an
action for benefits provided by this Plan or to enforce any right hereunder. The
Participant's beneficiary should follow the same claims procedure in the event
of the Participant's death.
ARTICLE X
PLAN ADMINISTRATION
Section 10.1 In General. The general administration of the Plan and the
duty to carry out its provisions shall be vested in the Administrator, which
shall be the "Plan Administrator" as that term is defined in
EX 10 - 10
<PAGE>
section 3(16)(A) of ERISA. The Plan and Severance Benefits under the Plan shall
be administered by the Administrator appointed from time to time by the Company.
The Administrator may, in its discretion, secure the services of other parties,
including agents and/or employees to carry out the day-to-day functions
necessary to an efficient operation of the Plan. The Administrator's
interpretations, decisions, requests and exercises of power and responsibilities
shall not be subject to review by anyone and shall be final, binding, and
conclusive upon all persons. The Administrator shall, in its sole and absolute
discretion, have the exclusive right to interpret all of the terms of the Plan,
to determine eligibility for coverage and benefits, to resolve disputes as to
eligibility, type, or amount of benefits, to correct any errors or omissions in
the form or operation of the Plan, to make such other determinations with
respect to the Plan, and to exercise such other powers and responsibilities as
shall be provided for in the Plan or as shall be necessary or helpful with
respect thereto. The Administrator under and pursuant to this Plan shall be the
named fiduciary for purposes of section 402(a) of ERISA with respect to all
powers and duties expressly or implicitly assigned to it hereunder. Any
determination or decision by the Company made under or with respect to any
provision of the Plan shall be in the Company's sole and absolute discretion,
shall not be subject to review by anyone and shall be final, binding and
conclusive upon all persons.
Section 10.2 Reimbursement and Compensation. The Administrator shall
receive no compensation for its services as Administrator, but it shall be
entitled to reimbursement for all sums reasonably and necessarily expended by it
in the performance of such duties.
Section 10.3 Rulemaking Powers. The Administrator shall have the power to
make reasonable and uniform rules and regulations required in the administration
of the Plan, to make all determinations necessary for the Plan's administration,
except those determinations which the Plan requires others to make, and to
construe and interpret the Plan wherever necessary to carry out its intent and
purpose and to facilitate its administration.
ARTICLE XI
SOURCE OF SEVERANCE PAYMENT
Section 11.1 No Separate Fund Established All Severance Benefits shall
be paid in cash from the general funds of the Company or an Employer, and no
special or separate fund shall be established. Nothing contained in the Plan
shall create or be construed to create a trust of any kind, and nothing
contained in the Plan nor any action taken pursuant to the provisions of the
Plan shall create or be construed to create a fiduciary relationship between the
Company or an employer and a Participant, beneficiary, employee or other person.
To the extent that any person acquires a right to receive Severance Benefits
from the Company or an Employer under the Plan, such right shall be no greater
than the right of any unsecured general creditor of the Company or Employer. For
purposes of the Code, the Company intends this Plan to be an unfunded, unsecured
promise to pay on the part of the Company. For purposes of ERISA, the Company
intends the Plan to be a "severance plan" within the meaning of the applicable
ERISA regulations.
ARTICLE XII
MISCELLANEOUS
Section 12.1 Participant's Legal Expenses. The Company agrees to pay,
upon written demand therefor by the Participant, fifty percent (50%) of all
legal fees and expenses which the Participant may reasonably incur in order to
collect amounts to be paid or obtain benefits to be provided to such Participant
under the Plan, plus in each case interest at the "applicable Federal rate" (as
defined in Section 1274(d) of the Code). In any such action brought by a
Participant for damages or to enforce any provisions hereof, he shall be
entitled to seek both legal and equitable relief and remedies, including,
without limitation, specific performance of the Company's
EX 10 - 11
<PAGE>
obligations hereunder, in his sole discretion. However, in any instance where a
Participant receives, as the result of a final, nonappealable judgment of a
court of competent jurisdiction or a mutually agreed upon settlement with the
Company, Severance Benefits greater than those first offered by the Company or
its successor to the Participant, then the Company shall pay one hundred percent
(100%) of all such legal fees and expenses incurred by the Participant.
Section 12.2 Employment Status. This Plan does not constitute a contract
of employment or impose on the Employer any obligation to retain a Participant
as an employee, to change the status of a Participant's employment as a
Management Group Employee or in any other position, or to change any employment
policies of the Employer.
Section 12.3 Validity and Severability. The invalidity or
unenforceability of any provision of the Plan shall not affect the validity or
enforceability of any other provision of the Plan, which shall remain in full
force and effect, and any prohibition or unenforceability in any jurisdiction
shall not invalidate or render unenforceable such provision in any other
jurisdiction.
Section 12.4 The Participant's Heirs, etc. This Agreement shall inure to
the benefit of and be enforceable by the Participant's personal or legal
representatives, executors, administrators, successors, heirs, distributees,
devisees and legatees. If the Participant should die while any amounts would
still be payable to him hereunder as if he had continued to live, all such
amounts, unless otherwise provided herein, shall be paid in accordance with the
terms hereof to his designee or, if there be no such designee, to his estate.
Section 12.5 Governing Law. The validity, interpretation, construction and
performance of the Plan shall in all respects be governed by the laws of the
State of Texas.
Section 12.6 Choice of Forum. A Participant shall be entitled to enforce
the provisions of this Plan in any state or federal court located in the Dallas
County, Texas, in addition to any other appropriate forum.
Section 12.7 Notice. For the purposes hereof, notices and all other
communications provided for herein shall be in writing and shall be deemed to
have been duly given when delivered or mailed by United States registered or
certified mail, return receipt requested, postage prepaid, addressed to the
Company at its principal place of business and to the Participant at his address
as shown on the records of the Employer, provided that all notices to the
Company shall be directed to the attention of the Chief Executive Officer of the
Company with a copy to the Secretary of the Company, or to such other in writing
in accordance herewith, except that notices of change of address shall be
effective only upon receipt.
Section 12.8 Alienation. No benefit, right or interest of any person
under the Plan will be subject to alienation, anticipation, sale, transfer,
assignment, pledge, encumbrance or charge, seizure, attachment or legal,
equitable or other process or be liable for or subject to, the debts,
liabilities or other obligations of such persons, except as otherwise required
by law. No Participant, dependent or their beneficiary shall have any right or
claim to benefits from the Plan, except as specified in the Plan.
Section 12.9 Pronouns. A pronoun or adjective in the masculine gender
includes the feminine gender, and the singular includes the plural, unless the
context clearly indicates otherwise.
IN WITNESS WHEREOF, Denbury Resources Inc. has caused these presents to
be executed by its duly authorized officer on the 6th day of December, 2000.
By: /s/ Ronald G. Greene
-------------------------------------------
Name: Ronald G. Greene
Title: Chairman of the Board
By: /s/ Phil Rykhoek
------------------------------------------
Name: Phil Rykhoek
Title: Secretary & Chief Financial Officer
EX 10 - 12
<PAGE>
SCHEDULE A
"Officers", as of December 6, 2000
Gareth Roberts Ron Gramling
Phil Rykhoek Lynda Perrard
Mark Worthey Tracy Evans
Mark Allen
EX 10 - 13
<PAGE>
SCHEDULE B
"Investment Committee", as of December 6, 2000
Gareth Roberts
Phil Rykhoek
Mark Worthey
Tracy Evans
EX 10 - 14
<PAGE>
SCHEDULE C
"Management Group", as of December 6, 2000
Kerry Allen
George Pecorino
Jim Sinclair
EX 10 - 15
<PAGE>
SCHEDULE D
"Participating Employers", as of December 6, 2000
None
EX 10 - 16
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>3
<FILENAME>0003.txt
<DESCRIPTION>EXHIBIT 13 - ANNUAL REPORT TO SHAREHOLDERS
<TEXT>
EXHIBIT 13
PAGE 2, PAGES 6 THROUGH 8 INCLUSIVE, PAGES 10 THROUGH 12 INCLUSIVE, PAGES 14
THROUGH 16 INCLUSIVE, AND PAGES 18 THROUGH 20 INCLUSIVE OF THE COMPANY'S ANNUAL
REPORT TO SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31, 2000, BUT EXCLUDING
PHOTOGRAPHS AND ILLUSTRATIONS SET FORTH ON THESE PAGES, NONE OF WHICH
SUPPLEMENTS THE TEXT AND WHICH ARE NOT OTHERWISE REQUIRED TO BE DISCLOSED IN
THIS ANNUAL REPORT ON FORM 10-K.
-1-
<PAGE>
<TABLE>
<CAPTION>
FINANCIAL HIGHLIGHTS
YEAR ENDED DECEMBER 31, AVERAGE
-------------------------------------------------------- ANNUAL
AMOUNTS IN THOUSANDS OF U.S. DOLLARS UNLESS NOTED 2000 1999 1998 1997 1996 GROWTH (2)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
PRODUCTION (DAILY)
Oil (Bbls) 15,219 12,090 13,603 7,902 4,099 39%
Gas (Mcf) 37,078 27,948 36,605 36,319 24,406 11%
BOE (6:1) 21,399 16,748 19,704 13,955 8,167 27%
REVENUE (NET OF ROYALTIES) 179,372 81,575 81,883 85,333 52,880 36%
UNIT SALES PRICE
Oil (per Bbl) 23.50 13.08 10.29 17.25 18.98 5%
Gas (per Mcf) 3.57 2.34 2.31 2.68 2.73 7%
CASH FLOW FROM OPERATIONS (1) 111,555 31,619 30,096 56,607 34,140 34%
NET INCOME (LOSS) 142,227 4,614 (287,145) 14,903 8,744 101%
AVERAGE COMMON SHARES OUTSTANDING 45,823 39,928 25,926 20,224 13,104 37%
PER SHARE
Cash flow from operations (1)
Basic 2.43 0.79 1.16 2.80 2.61 -2%
Diluted 2.41 0.79 1.15 2.64 2.39 0%
Net income (loss)
Basic 3.10 0.12 (11.08) 0.74 0.67 47%
Diluted 3.07 0.12 (11.08) 0.70 0.63 49%
OIL AND GAS CAPITAL INVESTMENTS 134,021 54,967 102,652 305,427 86,857 11%
TOTAL ASSETS 457,379 252,566 212,859 447,548 166,505 29%
LONG-TERM LIABILITIES 202,428 154,976 226,436 256,637 7,481 128%
STOCKHOLDERS' EQUITY (DEFICIT) 216,165 72,428 (32,265) 160,223 142,504 11%
PROVED RESERVES
Oil (MBbls) 70,667 51,832 28,250 52,018 15,052 47%
Gas (MMcf) 100,550 50,438 48,803 77,191 74,102 8%
MBOE (6:1) 87,425 60,238 36,383 64,883 27,403 34%
Discounted future cash flow - 10% 1,158,969 462,870 115,019 361,329 316,098 38%
PER BOE DATA (6:1)
Revenue 22.90 13.34 11.38 16.75 17.69 7%
Lease operating expenses (4.94) (4.25) (3.49) (3.54) (3.57) 8%
Production taxes (1.02) (0.60) (0.56) (0.82) (0.94) 2%
- -----------------------------------------------------------------------------------------------------------------------
Production netback 16.94 8.49 7.33 12.39 13.18 6%
Administrative expense (1.09) (1.21) (1.02) (1.30) (1.50) -8%
Net cash interest (expense) income (1.54) (2.22) (2.13) 0.02 (0.26) 56%
Current income taxes and other (0.07) 0.11 - - - -
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS (1) 14.24 5.17 4.18 11.11 11.42 6%
- -----------------------------------------------------------------------------------------------------------------------
<FN>
(1) Exclusive of the net change in non-cash working capital balances.
(2) Computed using 1996 as a base year.
</FN>
</TABLE>
Reporting Format
Unless otherwise noted, the disclosures in this report have (i) dollar amounts
presented in U.S. dollars, (ii) production volumes expressed on a net revenue
interest basis, and (iii) gas volumes converted to equivalent barrels at 6:1.
-2-
<PAGE>
SELECTED OPERATING DATA
OIL AND GAS RESERVES
Estimates of our net proved oil and gas reserves as of December 31, 2000 have
been prepared by DeGolyer and MacNaughton, and the estimates as of December 31,
1999 and 1998 were prepared by Netherland, Sewell and Associates, Inc., both
independent petroleum engineers located in Dallas, Texas. The reserves were
prepared using constant prices and costs in accordance with the guidelines of
the Securities and Exchange Commission ("SEC"), based on the prices received on
a field-by-field basis as of December 31 of each year. The reserves do not
include any value for probable or possible reserves which may exist, nor do they
include any value for undeveloped acreage. The reserve estimates represent our
net revenue interest in our properties.
Our proved non-producing reserves primarily relate to additional potential
producing 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 non-producing reserves.
Waterfloods at Heidelberg Field and tertiary (CO2) floods at Little Creek Field
make up 69% of our proved undeveloped oil reserves. We consider these reserves
to be lower risk than most proved undeveloped reserves that require drilling as
there is minimal reservoir risk associated with these reserves because the
reservoirs have previously produced. They are classified as undeveloped because
they require additional capital expenditures in order to obtain the reserves.
The remaining 31% of our undeveloped oil reserves are generally reserves located
up-dip to producing formations. Most of our proved undeveloped natural gas
reserves are located in the Selma Chalk formation at Heidelberg (26%), the Marg
Idio formation at Thornwell Field (22%) and in our offshore High Island 521 and
286 blocks (36%). The High Island properties should begin producing in the first
or second quarter of 2001 and were considered undeveloped as of December 31,
2000 as they were not ready for production at that time. We plan to develop most
of the Heidelberg and Thornwell undeveloped reserves in 2001.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
2000 1999 1998
------------- ------------ -----------
<S> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil (MBbls)................................................ 70,667 51,832 28,250
Natural gas (MMcf)......................................... 100,550 50,438 48,803
Oil equivalent (MBOE)...................................... 87,425 60,238 36,383
PERCENTAGE OF TOTAL MBOE:
Proved producing........................................... 57% 41% 39%
Proved non-producing....................................... 18% 25% 38%
Proved undeveloped......................................... 25% 34% 23%
REPRESENTATIVE OIL AND GAS PRICES: (1)
Oil - NYMEX................................................ $ 26.80 $ 25.60 $ 12.00
Natural gas - NYMEX Henry Hub.............................. 9.78 2.12 2.15
PRESENT VALUES:(2)
Discounted estimated future net cash flow before
income taxes ("PV10 Value") (thousands)................ $ 1,158,969(3) $ 462,870 $ 115,019
Standardized measure of discounted estimated future net
cash flow after income taxes (thousands)............... $ 841,299 $ 448,374 $ 115,019
<FN>
- ---------------
(1) The oil prices as of each respective year-end were based on NYMEX prices
per Bbl and NYMEX Henry Hub ("NYMEX") prices per MMBtu, with these
representative prices adjusted by field to arrive at the appropriate
corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance
with the guidelines of the SEC, discounted at 10% per annum.
(3) For comparative purposes, we also prepared a December 31, 2000 reserve
report using the same prices as used in the 1999 report. The PV10 value in
this report was $559 million.
</FN>
</TABLE>
-6-
<PAGE>
FIELD SUMMARIES
Denbury operates in two primary core areas, Louisiana and Mississippi. Our seven
largest fields constitute approximately 85% of our total proved reserves on a
BOE basis and 77% on a PV10 Value basis. Within these seven fields we own an
average 91% working interest and operate 94% of the wells. The concentration of
value in a relatively small number of fields allows us to benefit substantially
from any operating cost reductions or production enhancements we achieve and
allows us to effectively manage the properties from our two primary field
offices in Houma, Louisiana and Laurel, Mississippi.
<TABLE>
<CAPTION>
2000
Proved Reserves as of December 31, 2000 (1) Average Daily Production
------------------------------------------------------ ------------------------
Average Net
Oil Natural Gas BOE's BOE PV10 Value Oil Natural Gas Revenue
(MBbls) (MMcf) (000's) % of Total (000's) (Bbls/d) (Mcf/d) Interest(2)
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Louisiana
Lirette............... 413 23,962 4,407 5.0% $ 170,490 136 9,611 62%
Thornwell (3)........ 274 14,444 2,681 3.1% 123,794 84 5,815 49%
Other Louisiana....... 1,124 19,839 4,430 5.1% 160,100 627 14,857 36%
--------- ----------- -------- --------- ---------- ------- ------- -----
Total Louisiana...... 1,811 58,245 11,518 13.2% 454,384 847 30,283 42%
--------- ----------- -------- --------- ---------- ------- ------- -----
Offshore Gulf of Mexico
High Island 521....... 13 7,832 1,318 1.5% 61,556 - - 19%
Other offshore........ 45 5,517 965 1.1% 33,051 12 1,037 23%
--------- ----------- -------- --------- ---------- ------- ------- -----
Total offshore....... 58 13,349 2,283 2.6% 94,607 12 1,037 22%
--------- ----------- -------- --------- ---------- ------- ------- -----
Eastern Mississippi
Heidelberg............ 44,254 24,022 48,257 55.2% 369,517 6,685 3,752 80%
Eucutta............... 6,360 454 6,436 7.3% 56,295 2,207 149 76%
King Bee.............. 2,956 - 2,956 3.4% 22,144 738 - 58%
Other E. Mississippi.. 6,678 3,358 7,238 8.3% 70,040 2,660 1,432 65%
--------- ----------- -------- --------- ---------- ------- ------- -----
Total E. Mississippi. 60,248 27,834 64,887 74.2% 517,996 12,290 5,333 75%
--------- ----------- -------- --------- ---------- ------- ------- -----
Western Mississippi
Little Creek.......... 8,291 - 8,291 9.5% 83,390 2,018 - 83%
Other................. 116 - 116 0.1% 974 - - 83%
--------- ----------- -------- --------- ---------- ------- ------- -----
Total W. Mississippi. 8,407 - 8,407 9.6% 84,364 2,018 - 83%
--------- ----------- -------- --------- ---------- ------- ------- -----
Other.................... 143 1,122 330 0.4% 7,618 52 425 -
--------- ----------- -------- --------- ---------- ------- ------- -----
Company Total............ 70,667 100,550 87,425 100.0% $1,158,969 15,219 37,078 68%
========= =========== ======== ========= ========== ======= ======= =====
<FN>
(1) The reserves were prepared using constant prices and costs in accordance
with the guidelines of the SEC based on the prices received on a
field-by-field basis as of December 31, 2000. The prices at that date
were a NYMEX oil price of $26.80 per Bbl adjusted by field and a NYMEX
natural gas price average of $9.78 per MMBtu also adjusted by field.
(2) Only includes wells in which the Company has a working interest as of
December 31, 2000.
(3) Thornwell Field was acquired during the fourth quarter of 2000. The
average production during the period it was owned by the Company was 335
Bbls/d and 23,133 Mcf/d.
</FN>
</TABLE>
-7-
<PAGE>
OIL AND GAS ACREAGE
The following table sets forth Denbury's acreage position at December 31,
2000:
<TABLE>
<CAPTION>
Developed Undeveloped
---------------------------------- ---------------------------------
Gross Net Gross Net
-------------- --------------- --------------- -------------
<S> <C> <C> <C> <C>
Louisiana.................... 24,322 15,999 26,337 15,819
Mississippi.................. 31,568 26,098 37,684 24,249
Offshore Gulf Coast.......... 30,000 10,027 5,000 2,500
-------------- --------------- --------------- -------------
Total............ 85,890 52,124 69,021 42,568
============== =============== =============== =============
</TABLE>
PRODUCTICE WELLS
This table sets forth both the gross and net productive wells of the
Company at December 31, 2000:
<TABLE>
<CAPTION>
Producing Oil Producing Gas
Wells Wells Total
--------------------------- --------------------------- ----------------------------
Gross Net Gross Net Gross Net
----------- ---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Louisiana.................. 41 15.4 60 26.8 101 42.4
Mississippi................ 367 278.3 42 27.9 409 306.2
Offshore Gulf Coast........ - - 6 1.4 6 1.4
----------- ---------- ----------- ----------- ----------- -----------
Total............... 408 293.7 108 56.1 516 350.0
=========== ========== =========== =========== =========== ===========
</TABLE>
DRILLING ACTIVITY
The following table sets forth the results of drilling activities during
each of the three fiscal years in the period ended December 31, 2000.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------
2000 1999 1998
-------------------- ------------------ -------------------
Gross Net Gross Net Gross Net
--------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells: (1)
Productive (2)........................ 3 1.1 3 1.0 - -
Nonproductive (3)..................... 1 0.2 1 1.0 1 0.4
Development Wells: (1)
Productive (2)........................ 38 26.5 12 11.9 33 26.7
Nonproductive (3)(4).................. 2 0.2 - - 1 0.8
-------- -------- -------- -------- -------- --------
Total........................... 44 28.0 16 13.9 35 27.9
======== ======== ======== ======== ======== ========
<FN>
(1) An exploratory well is a well drilled either in search of a new, as-yet
undiscovered oil or gas reservoir or to greatly extend the known limits of
a previously discovered reservoir. A developmental well is a well drilled
within the presently proved productive area of an oil or 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 gas in sufficient quantities to justify
completion as an oil or gas well.
(3) A nonproductive well is an exploratory or development well that is not a
producing well.
(4) During 2000 and 1999, an additional 12 and 4 wells, respectively, were
drilled for water injection purposes.
</FN>
</TABLE>
-8-
<PAGE>
OPERATIONS SECTION OF ANNUAL REPORT
[Graphic Omitted]
South Louisiana and Offshore
- ----------------------------
Denbury operates on the land and marshes of South Louisiana, including
state waters. During 2000, we began an expansion into the federal offshore
waters as a natural extension of our activities onshore. The geology in both
areas is similar, and both rely heavily on the use of 3D seismic to identify
potential reservoirs. Denbury owns interests in 107 wells, both onshore and
offshore, and operates 83 of these wells (77%) from its regional office in
Houma, LA. This region produces most of the Company's natural gas, averaging
50.6 MMcf/d net to Denbury in the 4th quarter of 2000, approximately 84% of our
total gas production. We anticipate future increases in our capital budget in
this region as we attempt to increase the percentage of natural gas production
company-wide.
The majority of our onshore fields lie in the Houma embayment area of
Terrebonne Parish, including Lirette Field, one of our seven largest fields. The
advent of 3D seismic data in these geologically complex areas has become a
valuable tool in exploration and development. We currently own or have a license
to work over 550 square miles of 3D data, and plan to expand our data ownership.
This data, the first 3D seismic to be shot in these swampy areas, was
instrumental in our drilling of two successful step out wells at Lirette in
1999, and one very successful exploration well in 2000. This well, the Leon
Hebert Heirs #1 (formally the Fina Fee #1), averaged 7.0 MMcf/d and 125 Bbls/d
net to the Company during the month of January 2001. During 2001, we plan to
drill four additional wells in the Terrebonne Parish area using the same 3D
interpretation techniques.
Late in 2000, we purchased a majority interest in 15 gas wells at
Thornwell Field in Cameron and Jeff Davis Parishes. This field produced an
average of 25.1 MMcfe/d net to our interest
-10-
<PAGE>
[Graphic Omitted]
during the fourth quarter of 2000. Our primary interest in purchasing this field
was the substantial upside potential that exists in continued development of the
existing producing zones, and the exploration potential of several deeper zones.
These prospects are all defined by a recent 110 square mile 3D seismic survey.
Denbury intends to be very active in this area in 2001, with current plans to
drill at least seven wells.
Our focus offshore is exclusively on the Gulf of Mexico shelf using the
same 3D seismic techniques that we have applied onshore. By the end of 2000, we
had acquired or committed to acquire approximately 500 square miles of 3D data.
Using this data, by the end of 2000 we had acquired interests in nine acreage
blocks in the federal offshore waters by leasing primary term blocks, obtaining
farmouts, and acquiring producing properties. As of February 28, 2001, Denbury
has participated in a total of five offshore wells at the High Island blocks 286
and 521, all of which were successful. Four of the wells are expected to
commence production during the first half of 2001 and the fifth well in the
second half, with an estimated aggregate rate net to us of seven to ten MMcf/d.
Our working interest in these wells ranges from 25% to 50%. We have also
identified four additional prospects in the area that we plan to develop in
2001.
Significant future activity is planned in the West Cameron area, where
at least 10 exploration and development opportunities have been identified. Most
of these are lower risk projects around existing fields, but several are
exploration prospects with unrisked targets of up to 20 Bcf.
[Graphic Omitted]
-11-
<PAGE>
[Graphic Omitted]
Heidelberg and East Mississippi
- -------------------------------
In the Eastern part of the Mississippi salt basin, Denbury operates 366
wells in 20 fields from its office in Laurel, MS. These fields produced an
average of 12,676 Bbls/d and 7.5 MMcf/d during the 4th quarter of 2000. The
largest field in the region, and the Company's largest field, is Heidelberg
Field, which for the fourth quarter of 2000 produced an average of 7,978 BOE/d.
We have been active in this area since the Company was founded in 1990 and are
by far the largest producer in the basin. Our strategy has been to increase
reserves and production in and around existing fields. The fields in this region
are characterized by structural traps that generate prolific production from
stacked or multiple pay sands. As such, they provide opportunities to increase
reserves through infield drilling, performing recompletions, making improvements
in production efficiency, and in some cases, by water flooding producing
reservoirs. Most of our wells produce large amounts of saltwater and require
large pumps, which increase the operating costs per barrel relative to our
properties in Louisiana that are predominantly gas producers. We plan to
continue our basic strategy in the region, supplemented by additional
waterflooding (secondary recovery) and eventually carbon dioxide ("CO2")
flooding (tertiary recovery).
We plan to study the feasibility of CO2 flooding in our East Mississippi
fields. We are already actively using this technology at Little Creek Field in
West Mississippi, and initial tests indicate that this technique should also
work in the fields in Eastern Mississippi. However CO2 flooding in the East will
probably be a few years away, as it requires the construction of a pipeline from
our CO2 source to the eastern part of the state, plus the construction of other
facilities.
Our primary interests at Heidelberg Field were acquired from Chevron in
December of 1997. This field was discovered in 1944 and has produced an
estimated 194 MMBbls of oil and 37 Bcf of gas since its discovery. The Field is
a large salt-cored anticline that is divided into western and eastern segments
due to subsequent faulting. Production is from a series of normally pressured
Cretaceous and Jurassic Age sandstone formations situated between 3,500 feet and
11,500 feet. There are 11 producing formations in the Heidelberg Field
-12-
<PAGE>
[Graphic Omitted]
containing 40 individual reservoirs, with the majority of the past and current
production coming from the Eutaw and Christmas sands at depths of 4,000 to 5,000
feet.
We continue to employ the latest technological advances in artificial
lift, open-hole and cased-hole logging techniques, and most recently, hydraulic
fracturing techniques. The average daily production has increased at Heidelberg
each quarter since we took over operations in January of 1998. When we acquired
the property, production was approximately 2,800 BOE/d. As a result of our
subsequent development work, production for 1998, 1999 and 2000 averaged 3,760
BOE/d, 5,708 BOE/d and 7,310 BOE/d, reaching 7,978 BOE/d for the fourth quarter
of 2000.
We currently operate five waterflood units at Heidelberg; four on the
east side and one expanded unit on the west. These waterflood units produce from
the shallow (approximately 4,400 feet) Eutaw formation. The cumulative
production from these five units since their initial discovery is estimated at
71.4 million barrels, or approximately 24% of the original oil estimated to be
in place. We believe that properly designed and executed waterflood programs
should increase the recovery factor to 40%, similar to our expectations from the
nearby analogous Eucutta Field. All five of the waterflood units were responding
to injection by July 2000.
During 2000, we accelerated our development of the Selma Chalk formation
in Heidelberg, which produces gas at a depth of 3700 feet.
-14-
<PAGE>
Previous operators only partially developed this formation in order to provide
fuel gas for the rest of the field. Using modern hydraulic fracturing techniques
we have been able to increase the gas production at Heidelberg to over 10
MMcf/d. This six-fold increase in natural gas production was obtained by
drilling 14 wells at a total cost of approximately $4 million. We currently plan
to drill 15 wells in 2001, which will effectively reduce the well spacing down
to 40 acres in East Heidelberg. To date, we have not seen any pressure depletion
from existing wells after new wells have been drilled. Based on the results in
similar fields in Mississippi, it may be possible to further reduce the well
spacing down to 20-acres, which would allow for an additional 40 wells.
Several additional zones below the Eutaw formation, including the
Christmas, Tuscaloosa, Paluxy, Rodessa, Hosston, Cotton Valley and Smackover
formations, have produced a combined 80 MMBbls and 20 Bcf from inception through
late 2000. We believe that there may be the potential to add additional reserves
by extending existing reservoirs, locating new reservoirs and implementing
additional waterfloods within the Heidelberg Field area. The wells drilled
during 2000 were positioned to delineate recently discovered reservoirs, while
providing additional production or injection opportunities for planned
waterfloods.
Denbury has pursued the same strategy at its other significant fields
in East Mississippi; Eucutta, Quitman, Davis, Sandersville and King Bee Fields.
After we acquired each of these oil fields, we initiated a rework program to
increase production and reserves. Davis Field, one of our oldest fields, is an
example of our strategy in Mississippi. This field was producing approximately
600 Bbls/d and had reserves of approximately 1.8 MMBbls when we acquired it in
1993. Since then, the field has produced at various rates, with a monthly high
of approximately 1,700 Bbls/d, and a fourth quarter 2000 average rate of 524
Bbls/d. Reserves at the end of 2000 were 1.2 MMBbls, about two-thirds of the
estimated 1993 reserve quantities, while over the seven years we have produced
more than 1.8 MMBbls.
[Graphic Omitted]
-15-
<PAGE>
[Graphic Omitted]
West Mississippi and Little Creek Field
- ---------------------------------------
Denbury began its activities in this part of the basin in September 1999
with the purchase of Little Creek Field, now our 5th largest field based on PV10
values at December 31, 2000. In February 2001, we acquired CO2 reserves and
producing wells near Jackson, Mississippi, which include a 183-mile pipeline
that transports the CO2 to Little Creek Field in the southwestern part of the
state. This acquisition will allow us to expand our tertiary CO2 gas flooding at
Little Creek Field and potentially, at other fields in the area.
Carbon dioxide injection for tertiary recovery purposes is used
extensively in the Permian Basin Region of West Texas, because of the
availability of large reserves of CO2 . Carbon dioxide injection is the most
efficient tertiary recovery mechanism for crude oil, but its application is
limited by the availability of large quantities of the gas, which to date has
been restricted to West Texas and Mississippi. The carbon dioxide acts as a type
of solvent for the oil, removing it from the formation as the CO2 is produced.
For example, in a typical oil field, between 40-50% of the oil in place can be
extracted by primary and secondary (waterflooding) recovery. An additional
amount of oil (17% at Little Creek) can be recovered by injecting CO2 into
certain wells and then recovering oil and CO2 from other wells.
In Mississippi, CO2 reserves have been discovered around Jackson dome, a
volcanic intrusive which was emplaced about 60 million years ago. The CO2
reserves in this area are found in structural
-16-
<PAGE>
[Graphic Omitted]
traps in the Buckner, Smackover and Norphlet formations at depths of about
15,000 feet. Some estimates have suggested that there are 12 Tcf of usable CO2
in this area. Our acquisition includes 10 producing CO2 wells, which were
originally drilled by Shell to supply CO2 to Little Creek Field, with an
estimated one Tcf of proved CO2 reserves. Today, some of that CO2 production is
sold to other commercial users and we use the rest for our tertiary activities.
Part of the rationale behind our purchase of Little Creek Field was to
gain experience in CO2 tertiary recovery, which we knew could potentially
benefit our properties in Eastern Mississippi, particularly Heidelberg and
Eucutta Fields. Not only have we gained experience, but we have sufficiently
increased our proved reserves and production rates to a degree that we are
comfortable expanding our tertiary recovery activities in the area. However,
before we could do that, we needed to assure ourselves that the carbon dioxide
would be available when needed and at a reasonable and determinable cost. For
that reason, we purchased the carbon dioxide reserves and pipeline.
The Western part of Mississippi has produced over 245 cumulative MMBbls
of light sweet crude oil from Tuscaloosa sandstones at a depth of about 10,000
feet. The application of a theoretical recovery factor of 17% of original oil in
place suggests that about 80-100 MMBbls of additional reserves may be available
in fields in this part of the state. Obviously, a great deal of work is required
before these reserves can be recorded as proved reserves, such as acquiring
properties, leasing, reworking and redrilling wells and installing production
facilities; however, preliminary indications suggest that there is considerable
potential for us in this part of Mississippi.
-18-
<PAGE>
Little Creek Field was discovered in 1958, and by 1962 the field had been
unitized and waterflooding had commenced. The pilot phase of CO2 flooding began
in 1974 and the first two phases (which are merely distinct areas of the field)
of the field-wide flooding began in 1985. In 2000, Denbury completed the
development of a third phase and initiated the CO2 injection into a fourth
phase. Our plans in 2001 are to initiate injection into the fifth phase and to
further expand phase III. Currently there are 37 producing wells and 17
injection wells at Little Creek. Based on the results of the two earliest phases
of CO2 flooding at Little Creek, tertiary recovery has increased the ultimate
recovery factor in that portion of the field by approximately 17%, as compared
to approximately 20% for primary recovery and 18% for secondary recovery. The
field has produced a cumulative 57 MMBbls of light sweet crude and we currently
estimate that an additional 9 MMBbls will be recovered.
During 2000, we acquired a 3D seismic survey covering Little Creek Field.
This survey identified areas of the field that were previously considered to be
non-productive. We anticipate that the combination of the 3D survey and the
benefits of CO2 flooding will allow us to expand the current productive area of
Little Creek Field, and to develop other fields within the immediate area. We
have identified several additional fields covered by the 3D survey that will
benefit from CO2 flooding and that can be developed using the Little Creek
facilities.
Production from Little Creek Field averaged 2,206 BOE/d in the fourth
quarter of 2000. We expect the production from Little Creek to increase
throughout 2001 and peak during 2003 at an estimated net rate of 3,500 to 4,500
BOE/d.
[Graphic Omitted]
-19-
<PAGE>
SELECTED ABBREVIATIONS
Bbl One stock tank barrel, of 42 U.S. gallons liquid volume,
used herein in reference to crude oil or other liquid
hydrocarbons.
Bbls/d Barrels of oil produced per day.
Bcf One billion cubic feet of natural gas.
BOE One barrel of oil equivalent using the ratio of one barrel
of crude oil, condensate or natural gas liquids to 6 Mcf of
natural gas.
BOE/d BOEs produced per day.
Btu 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.
MBbls One thousand barrels of crude oil or other liquid
hydrocarbons.
MBOE One thousand BOEs.
MBtu One thousand Btus.
Mcf One thousand cubic feet of natural gas.
Mcf/d One thousand cubic feet of natural gas produced per day.
MMBbls One million barrels of crude oil or other liquid hydro-
carbons.
MMBOE One million BOEs.
MMBtu One million Btus.
MMcf One million cubic feet of natural gas.
PV10 Value When used with respect to oil and natural gas reserves, PV10
Value means the estimated future gross revenue to be
generated from the production of proved reserves, net of
estimated production and future development costs, using
prices and costs in effect at the determination date, before
income taxes, and without giving effect to non-property-
related expenses, discounted to a present value using an
annual discount rate of 10% in accordance with the
guidelines of the Securities and Exchange Commission.
Proved Developed Reserves that can be expected to be recovered through
Reserves existing wells with existing equipment and operating
methods.
Proved Reserves The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic
and operating conditions.
Tcf One trillion cubic feet of natural gas.
-20-
<PAGE>
Management's Discussion and Analysis of Financial Condition
and Results of Operations
Denbury is a growing independent oil and gas company engaged in
acquisition, development and exploration activities in the U.S. Gulf Coast
region. The Company is the largest oil and natural gas producer in Mississippi,
holds key operating acreage onshore Louisiana and has a growing presence in the
offshore Gulf of Mexico areas. The Company increases the value of acquired
properties through a combination of exploitation, drilling, and proven
engineering extraction processes. Denbury's corporate headquarters is in Dallas,
Texas, and it has two primary field offices located in Houma, Louisiana and
Laurel, Mississippi.
CAPITAL RESOURCES AND LIQUIDITY
ELEMENTS OF INCREASED CASH FLOW. As more fully described under "Results
of Operations" below, as a result of improved product prices and increased
production, the Company posted record earnings and cash flow from operations in
2000, up sharply from these results for 1999 and 1998.
HIGHER COMMODITY PRICES. NYMEX oil prices have improved from the 1998
year-end price of approximately $12.00 per Bbl to an average of approximately
$19.00 per Bbl for 1999 and an average of approximately $30.25 per Bbl for 2000
(as compared to a net corporate average price received of $25.89 per Bbl for
2000 before the impact of hedging). Natural gas prices have also increased
dramatically, particularly during 2000, from a NYMEX price of approximately
$2.15 per Mcf at year-end 1998 to an average of approximately $2.35 per Mcf in
1999 and an average of approximately $3.90 per Mcf for 2000 (as compared to a
net corporate average price received of $4.45 per Mcf for 2000 before the impact
of hedging). As of December 31, 2000, the NYMEX natural gas prices were almost
$10.00 per Mcf, although they dropped back to between $5.00 and $6.00 per Mcf
during February 2001.
<TABLE>
<CAPTION>
Graph depicting the NYMEX crude oil price postings by month from January 1997
through December 2000:
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Jan-97 Feb-97 Mar-97 Apr-97 May-97 Jun-97 Jul-97 Aug-97 Sep-97 Oct-97 Nov-97 Dec-97
25.18 22.17 20.97 19.73 20.87 19.22 19.66 19.95 19.78 21.28 20.22 18.32
Jan-98 Feb-98 Mar-98 Apr-98 May-98 Jun-98 Jul-98 Aug-98 Sep-98 Oct-98 Nov-98 Dec-98
16.73 16.08 15.05 15.47 14.93 13.67 14.08 13.38 14.98 14.46 12.96 11.24
Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99
12.49 12.02 14.68 17.30 17.77 17.92 20.10 21.28 23.79 22.67 24.77 26.09
Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00
26.88 29.37 30.06 25.64 28.95 31.46 30.05 31.17 33.76 32.90 34.40 28.35
</TABLE>
INCREASED PRODUCTION. In addition, the Company's average daily production
has increased for the seventh consecutive quarter, setting new company records
for both the fourth quarter and fiscal 2000 (see "Results of Operations -
Production").
LARGER PROVED RESERVES. Along with the growth in production, the
Company's proved reserve quantities increased 45% between 1999 and 2000, with an
even larger increase in reserve values due to higher commodity prices (see
"Results of Operations - Depletion, Depreciation and Site Restoration" for a
discussion of the changes in proved reserves).
Bank Credit Facility
Between September 1999 and October 2000, the Company did not borrow any
funds on its bank credit facility and repaid $6.5 million during the first nine
months of 2000. In the fourth quarter of 2000, the Company borrowed $61 million
under its bank credit facility to fund acquisitions (see "Results of Operations
- - 2000 Acquisitions") and the cost of "puts" or floors purchased to hedge a
portion of the Company's production for 2001 and 2002 (see "Market Risk
Management"). With the excess cash flow
-23-
<PAGE>
Graph depicting the Company's bank debt by quarter for 2000 (in millions of
dollars):
1st Qtr 2nd Qtr 3rd Qtr 4th Qtr
27.5 23.5 21.0 74.0
generated from these acquisitions, strong commodity prices and reduced spending
in the fourth quarter of 2000 due to unforeseen delays, the Company repaid $8
million to its banks in late December 2000, leaving the Company with outstanding
bank borrowings of $74 million as of December 31, 2000, and total long-term
debt, including the Company's Senior Subordinated Notes, of $199 million.
The Company's bank credit facility provides for a semi-annual
redetermination of the borrowing base on April 1st and October 1st. On October
13, 2000, the Company amended and restated its bank credit facility with Bank of
America, as agent for a group of seven other banks. This amendment (i) extended
the maturity of the credit line for one additional year to December 31, 2003,
(ii) increased the interest rate on the loan by increasing the LIBOR margin for
Eurodollar loans by 0.25%, (iii) reduced the number of banks in the line by one
and re-allocated the loan among the remaining eight banks, and (iv) increased
the Company's conforming borrowing base from $60 million to $110 million. The
total borrowing base of $110 million was not changed at that time.
In December 2000, at the request of the Company, the banks conducted a
redetermination of the Company's credit facility and increased the borrowing
base from $110 to $150 million. An additional $21 million was borrowed on the
bank credit line on February 2, 2001 to partially fund a $42 million acquisition
of carbon dioxide reserves, producing wells, facilities and a 183-mile pipeline
(the "CO2 Acquisition"). In late February 2001, $8 million was repaid, leaving
the Company with $87 million of total bank debt and $63 million of available
credit as of March 1, 2001.
In keeping with its fiscal policy during the last two years, the Company
plans to continue to reserve its credit line primarily for potential
acquisitions. The next scheduled borrowing base redetermination will be as of
April 1, 2001. The Company anticipates that the borrowing base will either
increase or remain unchanged as a result of the additional collateral and assets
provided by the CO2 Acquisition, although the borrowing base can always be
reduced at the banks' discretion and is based in part, upon external factors
over which the Company has no control.
Graph comparing the Company's 2000 development and exploration expenditures to
its cash flow, by quarter for 2000 (in millions of dollars):
1st Qtr 2nd Qtr 3rd Qtr 4th Qtr
Expenditures 14.6 21.7 22.8 14.6
Cash flow from operations 19.6 21.3 27.5 43.2
Capital Spending and Resources
Although the Company's total debt has risen from $152.5 million at year-
end 1999 to $212 million as of March 1, 2001, the Company's leverage in relation
to its cash flow from operations (before the change in working capital items)
has decreased. Denbury's debt-to-cash-flow ratio was 1.2 to 1 comparing its debt
as of March 1, 2001 to the annualized fourth quarter of 2000 cash flow from
operations, a significant improvement from the debt-to-cash-flow ratio of 2.9 to
1 a year earlier, computed in the same manner.
The Company's capital budget for 2001, excluding acquisitions, is
currently set at $150 million, which includes approximately $10 million of
projects that were carried over from 2000. Approximately 20% of the
-24-
<PAGE>
2001 expenditures are targeted for Heidelberg Field, 15% for Little Creek Field
and other CO2 floods, 15% for the recently acquired Thornwell Field, 17% for
offshore activities, and the balance for various other fields. Of the total
budget, approximately 17% is related to exploratory drilling, seismic or other
exploratory type expenditures. During 2001, the Company plans to follow a fiscal
policy similar to that followed in 1999 and 2000, whereby it will keep its
capital expenditures at, or less than, cash flow from operations. The Company
reviews its budget on a quarterly basis and thus may adjust its spending levels
if there are significant changes in cash flow.
Due to high commodity prices and the resultant cash flow, the Company
increased its budget three times during 2000. These adjustments were made to add
additional projects and to adjust for continually increasing costs. Due to the
increased levels of activity in the industry, the cost of goods and services
have continued to rise, and they have become harder to obtain. Thus, a portion
of the projects budgeted in the fourth quarter were delayed and moved into 2001
due to delays in obtaining equipment and services. Subject to the availability
of equipment and personnel and assuming that commodity prices and cash flow
remain strong, it is likely that the Company will add additional projects to its
budget during 2001 as current budget totals are below projected cash flow
levels. In addition, with costs continuing to rise, it is probable that there
will be some increases in the budget solely due to cost inflation.
At the Company's current capital spending levels and with the current
level of commodity prices, the Company anticipates that during 2001 it will
increase its average production rate approximately 34% when compared to 2000's
average production. The Company has purchased "puts" or floors which cover
approximately 80% of its expected 2001 production (see "Market Risk
Management"), which helps assure that a majority of the Company's capital
program can be implemented and that it can achieve a minimum rate of return on
its recent acquisitions, provided that its other assumptions related to the
recent acquisitions are correct. Therefore, although the level of the Company's
projected cash flow is highly variable and difficult to predict due to
volatility in product prices, the success of its drilling and developmental work
and other factors, the Company currently does not expect its 2001 capital
spending program to use all of the cash flow generated from operations and
expects to use the excess cash flow to reduce bank debt during the year, or to
partially fund any acquisitions.
The Company is also continuing to pursue acquisitions which, if
accomplished, should be accretive to the Company's operating results. There can
be no assurance that suitable acquisitions will be identified in the future or
that such acquisitions will be successful in achieving desired profitability
objectives. Though the Company has a significant inventory of development and
exploration projects in-house, on a long-term basis the Company will need
acquisitions to replace its production. The Company's future growth could be
limited or even eliminated if the Company is unable to complete suitable
acquisitions or is unable to fund such acquisitions for an extended period of
time.
Sources and Uses of Funds
During 2000, the Company spent approximately $73.7 million on exploration
and development activities and approximately $60.3 million on acquisitions. The
exploration and development expenditures included approximately $37.8 million
spent on drilling, $8.5 million of geological, geophysical and acreage
expenditures and $27.4 million spent on facilities and
Graph depicting the Company's capital expenditures during the last three years
(in millions of dollars):
1998 1999 2000
----- ----- -----
Development 89.0 34.5 73.7
Acquisitions 13.7 20.5 60.3
----- ----- -----
Total 102.7 55.0 134.0
===== ===== =====
-25-
<PAGE>
recompletion costs. These exploration and development expenditures were funded
by cash flow from operations. The acquisitions were funded by both cash flow and
net incremental bank debt of $46.5 million (see also "Results of Operations -
2000 Acquisitions").
During 1999, the Company spent approximately $34.5 million on exploration
and development activities and approximately $20.5 million on acquisitions. The
exploration and development expenditures included approximately $8.6 million
spent on drilling, $5.7 million of geological, geophysical and acreage
expenditures and $20.2 million spent on facilities and recompletion costs. These
exploration and development expenditures were funded primarily by cash flow from
operations. The acquisitions were funded by both cash flow and incremental bank
debt of $17.9 million.
During 1998, the Company spent approximately $89.0 million on exploration
and development activities and approximately $13.7 million on acquisitions. The
exploration and development expenditures included approximately $53.0 million
spent on drilling, $17.8 million of geological, geophysical and acreage
expenditures and $18.2 million spent on recompletion costs. These expenditures
were funded by bank debt ($60.0 million), cash flow from operations ($20.3
million) and cash and other sources ($22.4 million). Of the total 1998
expenditures of $102.7 million, approximately 26% or $27 million of the
development expenditures were directed to long-term projects such as production
facilities, waterflood units, and undeveloped properties such as acreage and
seismic that were not expected to benefit the Company until 1999 or beyond.
2001 CO2 ACQUISITION. In February 2001, the Company acquired carbon
dioxide reserves, production and associated assets for $42 million. The
acquisition included ten producing CO2 wells and production facilities located
near Jackson, Mississippi, and a 183-mile 20-inch pipeline which is currently
transporting CO2 to Denbury's tertiary recovery operations at Little Creek
Field, as well as to commercial customers. As of March 1, 2001, Denbury was
using approximately 30 million cubic feet of CO2 per day in its tertiary
recovery operations at Little Creek and selling approximately 40 million cubic
feet of CO2 per day to commercial customers in other industries. Ownership of
the CO2 and the related benefits of assured availability and determinable cost,
make it easier for the Company to expand its tertiary recovery operations to
areas around Little Creek Field, and perhaps in time, to other parts of the
state. The operating results from these assets will be accounted for separately
from the Company's oil and gas operations.
RESULTS OF OPERATIONS
Operating Income
During 2000, the Company set records for production, revenue, cash flow
and net income. This was made possible primarily due to record high commodity
prices and, to a lesser extent, due to record production levels. Certain of
these statistics are set forth in the following chart.
-26-
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
AVERAGE DAILY PRODUCTION VOLUME
Bbls 15,219 12,090 13,603
Mcf 37,078 27,948 36,605
BOE(1) 21,399 16,748 19,704
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 130,898 $ 57,713 $ 51,080
Natural gas sales 48,474 23,862 30,803
- -----------------------------------------------------------------------------------------------------------
Total oil and natural gas revenues 179,372 81,575 81,883
- -----------------------------------------------------------------------------------------------------------
Lease operating costs 38,676 26,029 25,113
Production taxes 8,051 3,662 4,049
- -----------------------------------------------------------------------------------------------------------
Total production expenses 46,727 29,691 29,162
- -----------------------------------------------------------------------------------------------------------
Production netback $ 132,645 $ 51,884 $ 52,721
===========================================================================================================
UNIT PRICES-INCLUDING IMPACT OF HEDGES(2)
Oil price per Bbl $ 23.50 $ 13.08 $ 10.29
Gas price per Mcf 3.57 2.34 2.31
UNIT PRICES-EXCLUDING IMPACT OF HEDGES(2)
Oil price per Bbl $ 25.89 $ 15.03 $ 10.29
Gas price per Mcf 4.45 2.42 2.32
- -----------------------------------------------------------------------------------------------------------
NETBACK PER BOE (1)
Oil and natural gas revenues $ 22.90 $ 13.34 $ 11.38
- -----------------------------------------------------------------------------------------------------------
Lease operating costs 4.94 4.25 3.49
Production taxes 1.02 0.60 0.56
- -----------------------------------------------------------------------------------------------------------
Total production expenses $ 5.96 $ 4.85 $ 4.05
- -----------------------------------------------------------------------------------------------------------
<FN>
(1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of
natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the
Company's hedging transactions.
</FN>
</TABLE>
PRODUCTION. In the fourth quarter of 2000, production volumes reached the
highest quarterly rate in the Company's history at 26,296 BOE/d. The 2000 annual
average of 21,399 BOE/d also set a new record high. The prior quarterly high of
21,927 BOE/d occurred in the second quarter of 1998, after which production
volumes decreased because of the sharp decline in oil prices in 1998, which led
to (i) shutting in uneconomic wells, (ii) declines in existing production,
particularly from horizontal wells, and (iii) postponement of several oil
development projects due to low oil prices. These declines continued through the
first quarter of 1999, after which oil prices began to increase and the Company
resumed its development program. In addition, in early 1999, the Company began
to experience a production response from its Heidelberg waterflood units that
had been initiated during the prior years. Since the first quarter of 1999, the
Company's average daily production has increased each quarter.
-27-
<PAGE>
Graph depicting the Company's average daily production by quarter from 1997
through 2000 (MBOE per day):
1997 1998
--------------------------- ---------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
----- ---- ---- ----- ----- ---- ---- -----
Oil 7.2 7.5 8.1 8.7 14.7 15.6 12.8 11.3
Natural Gas 5.1 5.9 6.1 7.2 6.7 6.3 6.6 4.8
----- ---- ---- ----- ----- ---- ---- -----
Total 12.3 13.4 14.2 15.9 21.4 21.9 19.4 16.1
===== ==== ==== ===== ===== ==== ==== =====
1999 2000
--------------------------- ---------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
----- ---- ---- ----- ----- ---- ---- -----
Oil 10.3 11.5 12.5 14.0 14.4 14.8 15.4 16.3
Natural Gas 5.1 4.5 4.5 4.5 4.7 4.8 5.1 10.0
----- ---- ---- ----- ----- ---- ---- -----
Total 15.4 16.0 17.0 18.5 19.1 19.6 20.5 26.3
===== ==== ==== ===== ===== ==== ==== =====
The Company's recent production increases have primarily resulted from
development and exploitation work on the Company's largest fields, combined with
occasional acquisitions. Since its December 1997 $202 million acquisition of
Heidelberg Field from Chevron, the Company's largest acquisitions have been the
$4.9 million acquisition of King Bee Field in May 1999, the $12.3 million
acquisition of Little Creek Field in August 1999, and the $56.5 million
acquisitions of Thornwell, Porte Barre and Iberia Fields in the fourth quarter
of 2000 (see "2000 Acquisitions" below). These acquisitions contributed
approximately 1,850 BOE/d (40%) of the 4,651 BOE/d production volume increase
between 1999 and 2000 and contributed approximately 1,000 BOE/d of incremental
production in 1999. The remaining increase has resulted from development and
exploitation work, with the most significant increases in the Company's largest
fields, Heidelberg, Lirette, and Little Creek Fields.
The Company has increased production each quarter on its largest
acquisition to date, Heidelberg Field. At the time of acquisition in December
1997, this property was producing approximately 2,800 BOE/d. Production under
Denbury's ownership has subsequently averaged 3,760, 5,708 and 7,310 BOE/d for
1998, 1999 and 2000. During 1998 the primary emphasis was to implement the
field's largest waterflood unit, the East Heidelberg Waterflood Unit, plus other
developmental drilling. During 1999, the Company began to see response from its
waterflood efforts. Production on the East Heidelberg Waterflood Unit went from
approximately 250 Bbls/d in the summer of 1998 to approximately 1,425 Bbls/d in
1999, and to an average of 1,775 Bbls/d for 2000. The Company added other
waterflood units there during 1999 and 2000 and also has expanded its drilling
for natural gas at Heidelberg in the Selma Chalk formation since the second half
of 1999. As a result of this, the natural gas production at Heidelberg has
increased from 0.5 MMcf/d in 1998 to 1.0 MMcf/d in 1999 and to 3.8 MMcf/d in
2000.
Another significant increase in production has come from Lirette Field,
which increased approximately 217 BOE/d between 1999 and 2000, from 1,521 to
1,738 BOE/d, although the increase was more pronounced in the fourth quarter of
2000. During the fourth quarter of 2000, production at Lirette averaged 2,812
BOE/d after production commenced in late September 2000 from a new discovery,
the Leon Hebert Heirs #1 (formerly the Fina Fee #1).
Production at Little Creek Field has also increased each quarter since
the Company acquired it in August 1999. At the time of acquisition, this field
was producing approximately 1,350 BOE/d. The production has gradually increased
each quarter to a 2,206 BOE/d average for the fourth quarter of 2000 and an
annual average of 2,018 BOE/d for 2000. The Company is continuing to expand its
tertiary recovery operations at Little Creek and anticipates that production
will continue to increase at this field until 2002 or 2003.
2000 ACQUISITIONS. During the fourth quarter of 2000, the Company
completed $56.5 million of acquisitions in the Thornwell, Porte Barre and Iberia
Fields located in Southwestern Louisiana. The current daily production from
these acquisitions is approximately 80% natural gas. These acquisitions added
estimated net proved reserves of approximately 23.4 billion cubic feet of
natural gas equivalents (3.9 MMBOE) and contributed 1,162 BOE/d to the Company's
average production rate for 2000 and approximately
-28-
<PAGE>
4,626 BOE/d to the 2000 fourth quarter average production volumes. In order to
help protect its rate of return on these acquisitions, the Company purchased
price floors (i.e. puts) at a cost of $2.5 million covering approximately 100%
of the Company's forecasted proven natural gas production for 2001 and 2002 from
these fields (see "Market Risk Management").
REVENUE. Oil and natural gas revenues more than doubled between 1999 and
2000, after being relatively unchanged from 1998 to 1999. Between 1999 and 2000,
revenues increased 120% as both commodity prices and production increased
substantially. Approximately 77% of the revenue increase between 1999 and 2000
is attributable to the increase in oil and natural gas prices and 23% of the
revenue increase is attributable to the Company's higher production levels.
Between 1998 and 1999, production decreased 15%, but oil and natural gas
revenues declined less than 1% due to a 27% ($2.79 per Bbl) increase in the net
oil price, and a slight increase in natural gas prices.
Graph depicting the Company's average net oil price by year (dollars per Bbl):
1998 1999 2000
---- ---- ----
10.29 15.03 25.89
Oil and natural gas revenues and net product prices were also impacted by
hedging gains and losses during the three years. During 2000, the Company lost
$13.3 million ($2.39 per Bbl) on its oil hedges and $11.9 million ($0.88 per
Mcf) on its natural gas hedges. All of these hedges expired as of December 31,
2000, and the Company does not currently have any hedges other than price floors
or "puts" in 2001 or beyond. Included in the 1999 net oil price is an $8.6
million loss on oil hedging ($1.95 per Bbl). The Company also realized a
$126,000 loss on its natural gas hedges and expensed $672,000 that it paid to
reduce the amount of its gas hedge for November 1999 through December 2000 by
six MMBtu/d (see also "Market Risk Management").
Graph depicting the Company's average net gas price by year (dollars per Mcf):
1998 1999 2000
---- ---- ----
2.31 2.34 3.57
OPERATING EXPENSES. Between 1999 and 2000, the total of production taxes
and operating expenses increased 57% (23% on a per BOE basis), primarily due to
an increase in production taxes related to higher product prices, the addition
of Little Creek Field during the third quarter of 1999 (which has higher
operating costs per barrel due to tertiary recovery operations), and overall
increases in the number of wells and in the cost of equipment and services.
Operating costs at Little Creek Field averaged $12.45 and $11.89 per BOE for
1999 and 2000, almost double the average for such costs on the Company's other
properties. Operating expenses are expected to remain high on this field,
particularly for the next year or two, as the Company is initiating additional
phases of tertiary recovery. Over the life of the property, the operating
expenses are expected to average approximately $2 to $4 per BOE less than the
current levels as the Company should be able to recover and recycle more carbon
dioxide in the future. Overall, production and operating expenses are expected
to continue to increase during 2001 due to the rising costs of goods and
services in the industry.
Between 1998 and 1999 operating expenses were relatively unchanged,
although the cost per BOE increased 20% between the two years due to declines in
average production levels. Increases were more pronounced in the fourth quarter
of 1999, when operating costs averaged $5.56 per BOE. This increase was the
result of several wells being returned to production, an increase in production
taxes related to higher product prices, and the addition of Little Creek Field
during the third quarter of 1999.
-29-
<PAGE>
Operating expenses per BOE on the Heidelberg Field have been between
$5.00 and $6.50 per BOE since the Company acquired the field in late 1997. At
the time of acquisition, operating expenses on the field were averaging $6.38
per BOE. Since that time, operating expenses have averaged $5.04, $5.12 and
$6.33 per BOE for 1998, 1999 and 2000, respectively. The initial savings were a
result of general cost saving measures, the shut-in of wells during the drop in
oil prices in 1998, and increased productivity per well through overall
production increases. These savings were offset in 2000 by the increased cost of
waterflood operations as several wells were returned to production, shut-in
wells were put back on production, the number of productive wells increased, and
goods and services became more costly as commodity prices have increased.
General and Administrative Expenses
On a BOE basis, G&A expenses decreased 10% between 1999 and 2000 due to
increased production levels, even though net G&A expense increased 16%. Between
1998 and 1999, G&A expenses increased 19% on a BOE basis, largely related to
decreases in production levels, as the net G&A expense between the two years was
almost identical. In general, G&A expenses have increased along with the
Company's growth.
<TABLE>
<CAPTION>
Year Ended December 31,
- ------------------------------------------------------------------------------------------------
G&A Expenses 2000 1999 1998
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gross G&A expense (thousands) $ 24,941 $ 20,119 $ 18,962
State franchise taxes 467 346 785
Operator overhead charges (13,684) (10,278) (9,749)
Capitalized exploration expense (3,202) (2,812) (2,657)
- ------------------------------------------------------------------------------------------------
Net G&A expense $ 8,522 $ 7,375 $ 7,341
- ------------------------------------------------------------------------------------------------
Average G&A expense per BOE $ 1.09 $ 1.21 $ 1.02
Employees as of December 31 242 220 205
- ------------------------------------------------------------------------------------------------
</TABLE>
Generally, the Company was very active during the first part of 1998, but
then significantly reduced its field expenditures and activity during the second
half of 1998 due to the decline in oil prices. The activity level gradually
resumed in 1999 as oil prices rebounded. Between 1998 and 1999, the single
largest component of the increase in gross G&A expenses was the reinstatement of
a bonus accrual in the third quarter of 1999, as no bonus accrual was made
during the last half of 1998 or the first half of 1999 due to depressed
commodity prices and corresponding poor financial results. Also contributing to
the G&A increases in 1999 were higher consultant fees as a result of the
increased activity and higher rent expense as a result of an increase in office
space and the expiration of a below-market lease in May 1999. These same items,
as well as a general increase in activity level, caused a 24% increase in gross
expenses between 1999 and 2000. In addition, overall costs have also increased
across the entire industry as demand for personnel, goods and services has
increased.
Another significant factor affecting net G&A expense is the amount of
well overhead charged during the period. The respective well operating
agreements allow the Company, when it is the operator, to charge a specified
overhead rate during the drilling phase and to charge a monthly fixed overhead
rate for each producing well. As a result of the resumption of development
activity in 1999 as compared to 1998, this recovery of G&A increased to $10.3
million in 1999 from $9.7 million in 1998. In 2000, the amount recovered from
operator's overhead charges increased even further to $13.7 million as a result
of acquisitions and increased drilling activity. As a result, net G&A expense
increased only 16% between 1999 and 2000 even though gross G&A expense increased
24%.
-30-
<PAGE>
Interest and Financing Expenses
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest expense $ 15,255 $ 15,795 $ 17,534
Non-cash interest expense (945) (834) (627)
- ---------------------------------------------------------------------------------------------------------
Cash interest expense 14,310 14,961 16,907
Interest and other income (2,279) (1,415) (1,623)
- ---------------------------------------------------------------------------------------------------------
Net cash interest expense $ 12,031 $ 13,546 $ 15,284
- ---------------------------------------------------------------------------------------------------------
Average net cash interest expense per BOE $ 1.54 $ 2.22 $ 2.13
Average debt outstanding $ 160,884 $ 172,010 $ 205,087
Average interest rate (1) 8.9% 8.7% 8.2%
- ---------------------------------------------------------------------------------------------------------
<FN>
(1) Includes commitment fees but excludes amortization of debt issue costs.
</FN>
</TABLE>
In 1999, the Company began the year with $225 million of total debt and
further increased this to $234.6 million by the end of the first quarter. This
debt was reduced by $100 million in April 1999 with the proceeds from the sale
of common shares to affiliates of the Texas Pacific Group. An additional $17.9
million was borrowed during the second and third quarters to fund acquisitions,
bringing total bank debt to $27.5 million as of December 31, 1999, or total
outstanding debt of $152.5 million after inclusion of the $125 million of 9%
Senior Subordinated Notes issued in 1998. The net result was an average level of
debt that was 16% lower in 1999 than in 1998. This was partially offset by an
increase in interest rates during the year, resulting in an overall decrease of
11% in net cash interest expense. On a BOE basis, net cash interest expense
increased slightly (4%) between 1998 and 1999 as a result of the overall decline
in production between the two years.
During 2000, the Company made small reductions in its bank debt during the
first three quarters, reducing total debt outstanding from $152.5 million as of
December 31, 1999 to $146 million as of September 30, 2000. During the fourth
quarter of 2000, the Company borrowed $61 million to fund property acquisitions
(see "2000 Acquisitions" above) and to purchase floors or "puts" for 2001 and
2002 (see "Market Risk Management"). In December 2000 the Company paid back $8.0
million of its bank debt, ending the year with $199 million of long-term debt
outstanding. The net effect was a 6% average lower level of debt in 2000 as
compared to 1999, although the debt was at slightly higher average interest
rates. The Company generated $864,000 of incremental interest and other income
during 2000 as a result of the higher cash flow levels which also helped reduce
the net cash interest expense. Overall, the Company had an 11% reduction in net
cash interest expense between 1999 and 2000 with a 31% reduction on a BOE basis
due to the increase in production levels during 2000.
-31-
<PAGE>
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") decreased between 1998
and 1999 as a result of the reduced oil and gas property basis resulting from
the full cost pool writedowns in 1998 and the increase in reserve quantities
during 1999. Conversely, DD&A expense increased between 1999 and 2000 primarily
as a result of the acquisitions made during 2000 at a higher than average cost
per BOE.
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2000 1999 1998
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Depletion and depreciation $ 34,530 $ 24,277 $ 50,820
Site restoration provision 560 384 419
Depreciation of other fixed assets 1,124 854 995
- --------------------------------------------------------------------------------------------------------
Total DD&A $ 36,214 $ 25,515 $ 52,234
- --------------------------------------------------------------------------------------------------------
Average DD&A cost per BOE $ 4.62 $ 4.17 $ 7.26
Writedown of oil and gas properties - - 280,000
- --------------------------------------------------------------------------------------------------------
</TABLE>
As a result of higher oil prices, the Company's proved oil reserve
quantities and values changed significantly between year-end 1998 and 1999. Oil
price impacts reserve quantities due to the effect on a well's economic life and
the economics of proved undeveloped locations. The oil prices used in the
December 31, 1998 reserve report were based on a NYMEX oil price of $12.00 per
Bbl, with these representative prices adjusted by field to arrive at the
appropriate corporate net price in accordance with the rules of the Securities
and Exchange Commission ("SEC"). The oil prices used in the December 31, 1999
reserve report were based on a NYMEX oil price of $25.60 per Bbl, as adjusted.
The dramatic change in year-end oil prices caused an increase in reserve
quantities in 1999 solely due to prices of 15.8 million BOE. In addition to the
increased reserves due to prices, the Company also added 14.2 MMBOE during 1999
from acquisitions, other development work, and upward revisions. In summary, the
Company's total proved reserves increased 65%, from 36.4 MMBOE as of December
31, 1998 to 60.2 MMBOE as of December 31, 1999, a significant factor in the
reduction of DD&A. When coupled with the full cost pool writedowns in 1998,
which lowered the cost basis of the Company's oil and gas properties, these
factors resulted in a decrease in DD&A from $7.26 per BOE in 1998 to $4.17 per
BOE in 1999.
Between 1999 and 2000, the NYMEX oil price used for the reserve report
only slightly increased from $25.60 as of December 31, 1999 to $26.80 per Bbl as
of December 31, 2000, although natural gas prices increased almost five fold,
from $2.12 per Mcf in 1999 to $9.78 in 2000. However, since the economic lives
of most of the Company's natural gas properties are generally not as sensitive
to changes in commodity price, this change in price only increased the proved
reserve quantities by 730,000 BOE between the two respective year-ends. During
2000, the Company also added 34.9 MMBOEs from acquisitions, other development
work, and upward revisions. Consequently, the Company's total proved reserve
quantities increased 45% from 60.2 MMBOE as of December 31, 1999 to 87.4 MMBOE
as of December 31, 2000.
The DD&A rate increase from $4.17 per BOE in 1999 to $4.62 per BOE in
2000 was primarily a result of the acquisition of properties in the fourth
quarter of 2000 at a higher than average cost per BOE (see also "2000
Acquisitions" above). Due to high commodity prices, the average acquisition cost
in 2000 of $11.94 per BOE was significantly higher than the Company's average
historical acquisition or finding cost per BOE and higher than the 1999 DD&A
rate per BOE. Even though these acquisitions had a high cost per BOE, the
-32-
<PAGE>
Company expects a good rate of return on these properties. In addition, the
Company has protected its downside by purchasing price floors to protect against
certain levels of unforeseen commodity price weakness (see "Market Risk
Management").
Fluctuations in commodity prices also significantly impact reserve
values. Under full cost accounting rules, the Company is required each quarter
to perform a ceiling test calculation. In determining the limitation on property
carrying values, SEC accounting rules require the discounting of estimated
future net revenues before income taxes from its proved reserves at 10% per year
using unescalated current prices ("PV10 Value"). The PV10 Value of the Company's
proved reserves was $115 million as of December 31, 1998, $463 million as of
December 31, 1999, and $1.16 billion as of December 31, 2000 ($559 million at
December 31, 2000 using December 31, 1999 prices). Due to the significant drop
in PV10 Value in 1998, the Company had full cost pool writedowns of $280 million
in 1998. With the increase in commodity prices in 1999 and 2000, no writedown
was necessary during either of those years.
The Company also provides for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision is included in DD&A expense and has
increased each year along with an increase in the number of properties owned by
the Company.
Income Taxes
As a result of the pre-tax loss of $302.8 million for the year ended
December 31, 1998, a normal deferred income tax provision for 1998 would have
resulted in a $96.4 million net deferred tax asset. The Company fully impaired
its $96.4 million net deferred tax asset based upon management's view at that
time that it was more likely than not that the Company would not be able to
generate sufficient taxable income to realize the benefit of its net deferred
tax asset.
For the year ended December 31, 1999, a normal deferred tax provision
would have resulted in a deferred income tax provision of $1.7 million. However,
the Company utilized a portion of its deferred tax asset and its corresponding
valuation allowance to offset this provision, leaving a net deferred tax asset
as of December 31, 1999 of $95.1 million. Since the Company continued to believe
at that time that it was more likely than not that future taxable income would
not be sufficient to realize the benefit from the Company's deferred tax assets,
the deferred tax asset was left fully impaired.
For the year ended December 31, 2000, the Company had taxable income of
$27.6 million, but was able to offset this income with its tax net operating
loss carryforwards ("NOLs"). However, the Company did incur $558,000 of current
income tax expense during 2000 which related to alternative minimum taxes that
could not be offset by NOLs.
For the year ended December 31, 2000, a normal tax provision would have
resulted in income tax expense of $27.7 million. However, the Company utilized a
portion of its deferred tax assets and its corresponding valuation allowance to
offset this provision. The Company also re-evaluated the remaining balance of
$67.9 million relating to its net deferred tax asset as of December 31, 2000.
The Company concluded that it is more likely than not that there will be
sufficient future taxable income to be able to realize the tax benefits of its
deferred tax asset, resulting in a deferred tax benefit of $67.9 million. In
reaching this conclusion, the Company considered current production levels,
current expectations regarding near-term oil and gas prices, current hedging
positions, anticipated capital expenditures, the estimated reversal of book and
tax temporary differences, available tax planning strategies and the Company's
expectations regarding future taxable income.
-33-
<PAGE>
This results in a net deferred tax asset balance as of December 31, 2000 of
$67.9 million, none of which is impaired.
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Unit Amounts 2000 1999 1998
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Current income tax expense $ 558 $ - $ -
Deferred income tax benefit (67,852) - (15,620)
- --------------------------------------------------------------------------------------------------------
Total income tax benefit $ (67,294) $ - $ (15,620)
- --------------------------------------------------------------------------------------------------------
Average income tax benefit per BOE $ (8.59) $ - $ (2.17)
Net operating loss carryforwards 112,690 139,859 118,619
- --------------------------------------------------------------------------------------------------------
Net deferred tax asset $ 67,852 $ 95,137 $ 96,402
Valuation allowance - (95,137) (96,402)
- --------------------------------------------------------------------------------------------------------
Total net deferred tax asset $ 67,852 $ - $ -
- --------------------------------------------------------------------------------------------------------
</TABLE>
Results of Operations
As a result of the decline in product prices in 1998 and an associated $280.0
million non-cash writedown of its oil and natural gas properties, the Company
had a net loss of $287 million in 1998. Between 1998 and 1999, even though
production was down, improved product prices coupled with the reduced DD&A per
BOE resulted in net income of $4.6 million for the year as outlined below. Cash
flow from operations, before changes in working capital balances, was only
slightly higher (5%) in 1999 as compared to 1998, as the improved product prices
were almost offset by the decreased production level. Between 1999 and 2000, as
a result of the significant increases in both production and commodity prices
and the deferred tax benefit, net income and cash flow increased dramatically.
Each of the factors that contributed to this increase are more fully discussed
in the preceding paragraphs.
Graph depicting the Company's cash flow from operations by quarter, excluding
the change in working capital items (in millions of dollars):
1998 1999 2000
- ----------------------- --------------------- ----------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
- ---- --- --- --- --- --- --- ---- ---- ---- ---- ----
11.5 9.1 6.8 2.8 2.5 6.6 9.5 13.0 19.6 21.3 27.5 43.2
<TABLE>
<CAPTION>
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income (loss) $ 142,227 $ 4,614 $ (287,145)
Net income (loss) per common share:
Basic $ 3.10 $ 0.12 $ (11.08)
Diluted 3.07 0.12 (11.08)
Cash flow from operations (1) $ 111,555 $ 31,619 $ 30,096
- -----------------------------------------------------------------------------------------------------------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
-34-
<PAGE>
The following table summarizes the cash flow, DD&A and results of operations on
a BOE basis for the comparative periods. Each of the individual components are
discussed above.
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Per BOE Data 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Oil and natural gas revenue $ 22.90 $ 13.34 $ 11.38
Lease operating costs (4.94) (4.25) (3.49)
Production taxes (1.02) (0.60) (0.56)
- ---------------------------------------------------------------------------------------------------------
Production netback 16.94 8.49 7.33
General and administrative expense (1.09) (1.21) (1.02)
Net cash interest expense (1.54) (2.22) (2.13)
Current income taxes and other non-cash items (0.07) 0.11 -
- ---------------------------------------------------------------------------------------------------------
Cash flow from operations (1) 14.24 5.17 4.18
DD&A (4.62) (4.17) (7.26)
Deferred income taxes 8.66 - 2.17
Writedown of oil and natural gas properties - - (38.93)
Other non-cash items (0.12) (0.25) (0.09)
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 18.16 $ 0.75 $ (39.93)
- ---------------------------------------------------------------------------------------------------------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
Market Risk Management
The Company uses fixed and variable rate debt to partially finance
budgeted expenditures. These agreements expose the Company to market risk
related to changes in interest rates. The Company does not hold or issue
derivative financial instruments for trading purposes.
The following table presents the carrying and fair values of the
Company's debt along with average interest rates. The fair value of the
Company's bank debt is considered to be the same as the carrying value since the
interest rate is based on floating short-term interest rates. The fair value of
the subordinated debt is based on quoted market prices.
<TABLE>
<CAPTION>
Expected Maturity Dates
- -----------------------------------------------------------------------------------------------------------------------
Total Fair
Amounts in Thousands 2001-2002 2003 2004-2007 2008 Value Value
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Variable rate debt:
Bank debt............................... $ - $ 74,000 $ - $ - $ 74,000 $ 74,000
The average interest rate on the bank debt at December 31, 2000 is 7.9%.
Fixed rate debt:
Subordinated debt....................... $ - $ - $ - $ 125,000 $ 125,000 $ 108,400
The interest rate on the subordinated debt is a fixed rate of 9%.
</TABLE>
-35-
<PAGE>
The Company also enters into various financial contracts to hedge its
exposure to commodity price risk associated with anticipated future oil and
natural gas production. These contracts consist of price ceilings and floors,
no-cost collars and fixed price swaps.
As of December 31, 1998, the Company had no-cost financial contracts
("collars") in place that hedged a total of 40 MMcf/d through August 1999 and 30
MMcf/d thereafter through December 2000. The first set of contracts had a
weighted average ceiling price of approximately $2.95 per MMBtu and the second
set of contracts had a ceiling price of $2.58 per MMBtu. Both contracts had a
floor price of $1.90 per MMBtu. During the first half of 1999, the Company
collected $603,000 on these contracts, but paid out $729,000 during the second
half of the year. During the second half of 1999, the Company also retired six
MMcf/d of the 30 MMcf/d collar at a cost of approximately $672,000. The net
out-of-pocket cost during 1999 on the natural gas collars was $798,000,
including the cost of the buyouts. During 2000, the Company paid out $11.9
million relating to these natural gas collars, reducing the net average natural
gas price it received by $0.88 per Mcf. All of the natural gas collars expired
as of December 31, 2000.
During March and April 1999, the Company entered into two collars to
hedge a portion of its oil production. The first contract was a fixed price swap
for 3,000 Bbls/d for the period of April through December 1999 at a price of
$14.24 per Bbl. The second contract was a collar to hedge 3,000 Bbls/d for the
period of May 1999 through December 2000 with a floor price of $14.00 per Bbl
and a ceiling price of $18.05 per Bbl. The Company paid approximately $8.6
million on these contracts during 1999, which lowered the effective net oil
price received by the Company for the year by $1.95 per barrel. During 2000, the
Company paid out $13.4 million relating to these oil collars, reducing the net
average oil price it received by $2.39 per Bbl. All of the oil collars expired
as of December 31, 2000.
In the aggregate, the Company paid out a net amount of $9.4 million
during 1999 and $25.3 million during 2000 on its commodity hedges. All of these
contracts expired as of December 31, 2000.
For the years 2001 and 2002, the Company acquired puts or floors in 2000
to hedge a portion of its anticipated oil and natural gas production. For 2001,
the Company acquired a $22.00 floor on 12,800 Bbls/d and a $2.80 floor on 37.5
MMBtu/d for an aggregate cost of $2.6 million, which together cover
approximately 75% of the Company's anticipated production, excluding the
anticipated production from the acquisitions made in the fourth quarter of 2000.
At the time of signing the purchase and sale agreements on these acquisitions,
the Company purchased puts or floors on the anticipated proven natural gas
production from these properties during 2001 and 2002. The floors relating to
the acquisitions cost a total of approximately $2.5 million and have varying
volume and price floors each quarter for 2001 and 2002. The price floors vary
by quarter, but have a weighted average price of $3.51 for 2001 and $3.23 for
2002. The volumes on the floors also vary by quarter, with a weighted average
volume of 23.0 MMBtu/d for 2001 and 7.8 MMBtu/d for 2002. If the prices on the
futures market were to decline or increase 10% from those in effect at December
31, 2000, there would be no cash flow impact to the Company as a result of the
put options. The Company has recorded the cost of these floors in either current
or long-term other assets in its Consolidated Balance Sheet as of December 31,
2000, depending on their expiration dates. The fair value of these positions as
of December 31, 2000 was $6.7 million. The following table lists all of the
individual floors in place as of December 31, 2000.
-36-
<PAGE>
<TABLE>
<CAPTION>
Volume Floor Volume Floor
Period Per Day Price Period Per Day Price
----------------------------------- ------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Oil Options or "puts" (Bbls/d): Gas Options or "puts" (MMBtu/d):
2001 12,800 $22.00 Q1 - 2002 5.3 $3.65
Q1 - 2002 6.7 $3.07
Gas Options or "puts" (MMBtu/d): Q2 - 2002 3.8 $3.40
2001 37.5 $2.80 Q2 - 2002 4.4 $3.04
Q3 - 2002 2.9 $3.38
Q1 - 2001 11.5 $4.25 Q3 - 2002 3.5 $2.99
Q1 - 2001 15.1 $3.52 Q4 - 2002 2.1 $3.38
Q2 - 2001 10.5 $3.95 Q4 - 2002 2.5 $2.93
Q2 - 2001 13.9 $3.23
Q3 - 2001 10.0 $3.70
Q3 - 2001 13.0 $3.07
Q4 - 2001 7.9 $3.56
Q4 - 2001 10.4 $2.94
</TABLE>
Recently Issued Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." This
statement establishes accounting and reporting standards for derivative
instruments and hedging activities. It requires that every derivative instrument
be recorded on the balance sheet as either an asset or liability measured at
fair value. The statement requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. If hedge accounting criteria are met, the change in a derivative's fair
value (for a cash flow hedge) is deferred in stockholders' equity as a component
of comprehensive income to the extent the hedge is effective. These deferred
gains and losses are recognized in income in the period in which the hedge item
and hedging instrument are settled. The ineffective portions of hedge returns
are recognized currently in earnings.
SFAS No. 137, issued in August 1999, postponed for one year the mandatory
effective date for SFAS No. 133, to January 1, 2001. In June 2000, the FASB
issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities," as an amendment to SFAS No. 133.
All derivatives within the Company have been identified. The Company has
designated, documented and assessed the hedging relationships, all of which are
cash flow hedges. Adoption by the Company of this accounting standard as of
January 1, 2001 resulted in the recognition of $1.6 million of derivative assets
with a cumulative effect increase to other comprehensive income of approximately
$1.0 million after tax for the transition adjustment as of January 1, 2001.
Forward-Looking Information
The statements contained in this Annual Report on Form 10-K that are not
historical facts, including, but not limited to, statements found in this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, are forward-looking statements, as that term is defined in Section
21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward-looking statements may be or
may concern, among other things, capital expenditures, drilling activity,
acquisition plans and proposals and dispositions, development activities, cost
savings, production efforts and
-37-
<PAGE>
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters
and competition. Such forward-looking statements generally are accompanied by
words such as "plan," "estimate," "expect," "predict," "anticipate,"
"projected," "should," "assume," "believe" or other words that convey the
uncertainty of future events or outcomes. Such forward-looking information is
based upon management's current plans, expectations, estimates and assumptions
and is subject to a number of risks and uncertainties that could significantly
affect current plans, anticipated actions, the timing of such actions and the
Company's financial condition and results of operations. As a consequence,
actual results may differ materially from expectations, estimates or assumptions
expressed in or implied by any forward-looking statements made by or on behalf
of the Company. Among the factors that could cause actual results to differ
materially are: fluctuations of the prices received or demand for the Company's
oil and natural gas, the uncertainty of drilling results and reserve estimates,
operating hazards, acquisition risks, requirements for capital, general economic
conditions, competition and government regulations, as well as the risks and
uncertainties discussed in this annual report, including, without limitation,
the portions referenced above, and the uncertainties set forth from time to time
in the Company's other public reports, filings and public statements.
-38-
<PAGE>
Independent Auditors' Report
To the Stockholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc. as of
December 31, 2000 and 1999 and the related consolidated statements of
operations, stockholders' equity (deficit) and cash flows for each of the three
years in the period ended December 31, 2000. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly in all
material respects, the financial position of the Company as of December 31, 2000
and 1999 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 22, 2001
-39-
<PAGE>
Consolidated Balance Sheets
<TABLE>
<CAPTION>
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31,
------------------------------
2000 1999
------------- -------------
ASSETS
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents........................................... $ 22,293 $ 11,768
Accrued production receivables...................................... 37,527 15,836
Trade and other receivables......................................... 5,739 2,942
Other current assets................................................ 4,305 -
Deferred tax asset.................................................. 28,126 -
------------- -------------
Total current assets ..................................... 97,990 30,546
------------- -------------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties...................................... 746,062 587,412
Unevaluated oil and natural gas properties.......................... 13,810 41,371
Less accumulated depletion and depreciation......................... (452,358) (417,828)
------------- -------------
Net property and equipment.................................. 307,514 210,955
------------- -------------
OTHER ASSETS........................................................... 12,149 11,065
NONCURRENT DEFERRED TAX ASSET.......................................... 39,726 -
------------- -------------
TOTAL ASSETS................................................ $ 457,379 $ 252,566
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities............................ $ 26,628 $ 18,042
Oil and gas production payable...................................... 12,158 7,120
------------- -------------
Total current liabilities................................... 38,786 25,162
------------- -------------
LONG-TERM LIABILITIES
Long-term debt...................................................... 199,000 152,500
Provision for site reclamation costs................................ 2,770 1,820
Other............................................................... 658 656
------------- -------------
Total long-term liabilities................................. 202,428 154,976
------------- -------------
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding.......................................... - -
Common stock, $.001 par value, 100,000,000 shares authorized;
45,979,981 and 45,718,486 shares issued and outstanding at
December 31, 2000 and December 31, 1999, respectively........... 46 46
Paid-in-capital in excess of par.................................... 329,339 327,829
Accumulated deficit................................................. (113,220) (255,447)
------------- -------------
Total stockholders' equity.................................. 216,165 72,428
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 457,379 $ 252,566
============= =============
</TABLE>
See Notes to Consolidated Financial Statements.
-40-
<PAGE>
Consolidated Statements of Operations
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS (U.S. DOLLARS) 2000 1999 1998
------------- ----------- ------------
<S> <C> <C> <C>
REVENUES
Oil, natural gas and related product sales................. $ 179,372 $ 81,575 $ 81,883
Interest income and other.................................. 2,279 1,415 1,623
------------- ----------- ------------
Total revenues....................................... 181,651 82,990 83,506
------------- ----------- ------------
EXPENSES
Lease operating costs...................................... 38,676 26,029 25,113
Production taxes........................................... 8,051 3,662 4,049
General and administrative................................. 8,055 7,029 6,556
Interest................................................... 15,255 15,795 17,534
Depletion and depreciation................................. 36,214 25,515 52,234
Franchise taxes............................................ 467 346 785
Writedown of oil and natural gas properties................ - - 280,000
------------- ----------- ------------
Total expenses...................................... 106,718 78,376 386,271
------------- ----------- ------------
Income (loss) before income taxes............................... 74,933 4,614 (302,765)
Income tax benefit.............................................. 67,294 - 15,620
------------- ----------- ------------
NET INCOME (LOSS)............................................... $ 142,227 $ 4,614 $ (287,145)
============= =========== ============
NET INCOME (LOSS) PER COMMON SHARE
Basic...................................................... $ 3.10 $ 0.12 $ (11.08)
Diluted.................................................... 3.07 0.12 (11.08)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic...................................................... 45,823 39,928 25,926
Diluted.................................................... 46,352 39,987 25,926
</TABLE>
See Notes to Consolidated Financial Statements.
-41-
<PAGE>
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS 2000 1999 1998
------------ ------------- ------------
CASH FLOW FROM OPERATING ACTIVITIES:
<S> <C> <C> <C>
Net income (loss).............................................. $ 142,227 $ 4,614 $ (287,145)
Adjustments needed to reconcile to net cash flow provided
by operations:
Depletion and depreciation................................. 36,214 25,515 52,234
Deferred income taxes...................................... (67,852) - (15,620)
Writedown of oil and natural gas properties................ - - 280,000
Other...................................................... 966 1,490 627
------------ ------------- ------------
111,555 31,619 30,096
Changes in working capital items relating to operations:
Accrued production receivables............................. (21,691) (10,341) 3,197
Trade and other receivables................................ (2,797) 13,448 (1,028)
Other assets............................................... (5,109) - -
Accounts payable and accrued liabilities................... 8,586 4,472 (11,046)
Oil and gas production payable............................. 5,038 2,002 (934)
Other liabilities.......................................... 390 - -
------------ ------------- ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES......................... 95,972 41,200 20,285
------------ ------------- ------------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures........................... (73,736) (34,479) (88,978)
Acquisition of oil and natural gas properties.............. (60,285) (20,488) (13,674)
Net purchases of other assets.............................. (1,629) (1,381) (1,145)
Increase in cash restricted for future site reclamation.... (322) (2,347) -
Disposition of oil and gas properties...................... 2,932 400 -
------------ ------------- ------------
NET CASH USED FOR INVESTING ACTIVITIES............................ (133,040) (58,295) (103,797)
------------ ------------- ------------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments............................................ (14,500) (100,000) (200,000)
Bank borrowings............................................ 61,000 27,500 60,000
Issuance of subordinated debt.............................. - - 125,000
Net proceeds from issuance of common stock................. 1,491 100,079 94,657
Costs of debt financing.................................... (398) (765) (3,402)
Other...................................................... - - (20)
------------ ------------- ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES......................... 47,593 26,814 76,235
------------ ------------- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.............. 10,525 9,719 (7,277)
Cash and cash equivalents at beginning of year.................... 11,768 2,049 9,326
------------ ------------- ------------
CASH AND CASH EQUIVALENTS AT END OF YEAR.......................... $ 22,293 $ 11,768 $ 2,049
============ ============= ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for interest.................... $ 13,936 $ 15,805 $ 11,821
Cash paid during the year for income taxes................ 275 - -
</TABLE>
See Notes to Consolidated Financial Statements.
-42-
<PAGE>
Consolidated Statement of Changes in Stockholders' Equity (Deficit)
<TABLE>
<CAPTION>
PAID-IN RETAINED
CAPITAL IN EARNINGS
COMMON STOCK EXCESS OF (ACCUMULATED
($.001 PAR VALUE) PAR DEFICIT) TOTAL
---------------------------- ------------- ----------------- -----------
DOLLAR AMOUNTS IN THOUSANDS OF U.S.
DOLLARS Shares Amount
-------------- ------------
<S> <C> <C> <C> <C> <C>
BALANCE - JANUARY 1, 1998 20,388,683 $ 20 $ 133,119 $ 27,084 $ 160,223
-------------- ------------ ------------- ----------------- -----------
Issued pursuant to employee stock
option plan........................ 132,256 - 954 - 954
Issued pursuant to employee stock
purchase plan...................... 101,561 - 1,139 - 1,139
Conversion of warrants................. 625,000 1 4,624 - 4,625
Public placement of common stock....... 5,554,180 6 87,933 - 87,939
Net loss............................... - - - (287,145) (287,145)
-------------- ------------ ------------- ----------------- -----------
BALANCE - DECEMBER 31, 1998 26,801,680 27 227,769 (260,061) (32,265)
-------------- ------------ ------------- ----------------- -----------
Issued pursuant to employee stock
purchase plan...................... 363,930 - 1,544 - 1,544
Sale of common stock to TPG............ 18,552,876 19 98,516 - 98,535
Net income............................. - - - 4,614 4,614
-------------- ------------ ------------- ----------------- -----------
BALANCE - DECEMBER 31, 1999 45,718,486 46 327,829 (255,447) 72,428
-------------- ------------ ------------- ----------------- -----------
Issued pursuant to employee stock
option plan........................ 40,458 - 186 - 186
Issued pursuant to employee stock
purchase plan..................... 218,493 - 1,305 - 1,305
Issued pursuant to directors
compensation plan................. 2,544 - 19 - 19
Net income............................. - - - 142,227 142,227
-------------- ------------ ------------- ----------------- -----------
BALANCE - DECEMBER 31, 2000 45,979,981 $ 46 $ 329,339 $ (113,220) $ 216,165
============== ============ ============= ================= ===========
</TABLE>
See Notes to Consolidated Financial Statements.
-43-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
Denbury Resources Inc. ("Denbury" or the "Company") is a Delaware corporation,
organized under Delaware General Corporation Law, engaged in the acquisition,
development, operation and exploration of oil and gas properties. The Company
operates as one business segment, with its operating activities related to the
exploration, development and production of oil and natural gas in the U.S. Gulf
Coast region.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance
with generally accepted accounting principles ("GAAP") in the United States and
include the accounts of the Company and its subsidiaries, all of which are
wholly owned. All material intercompany balances and transactions have been
eliminated.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS. The Company follows 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 the Company's
activities undertaken exclusively in the United States. Such costs include lease
acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and non-productive
wells and general and administrative expenses directly related to exploration
and development activities and do not include any costs related to production,
general corporate overhead or similar activities. Proceeds received from
disposals are credited against accumulated costs except when the sale represents
a significant disposal of reserves, in which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION. The costs capitalized, including production
equipment, are depleted or depreciated on the unit-of-production method, based
on proved oil and natural gas reserves as determined by independent petroleum
engineers. Oil and natural gas reserves are converted to equivalent units based
upon the relative energy content which is six thousand cubic feet of natural gas
to one barrel of crude oil.
C) SITE RECLAMATION. Estimated future costs of well abandonment and site
reclamation, including the removal of production facilities at the end of their
useful life, are provided for on a unit-of-production basis. Costs are based on
engineering estimates of the anticipated method and extent of site restoration,
valued at year-end prices, net of estimated salvage value, and in accordance
with the current legislation and industry practice. The annual provision for
future site reclamation costs is included in depletion and depreciation expense
and reported under long-term liabilities in the Consolidated Balance Sheets as
"Provision for site reclamation costs."
D) CEILING TEST. The net capitalized costs of oil and 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 (discounted at 10%), based on unescalated year-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.
E) JOINT INTEREST OPERATIONS. Substantially all of the Company's oil and natural
gas exploration and production activities are conducted jointly with others.
These financial statements reflect only the Company's proportionate interest in
such activities and any amounts due from other partners are included in trade
receivables.
-44-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Restricted Cash
At December 31, 2000 and 1999, the Company had approximately $2.7 million and
$2.3 million, respectively, of restricted cash held in escrow for future site
reclamation costs. This restricted cash is included in Other Assets in the
Consolidated Balance Sheets.
Net Income (Loss) Per Common Share
Basic net income or loss per common share is computed by dividing the net income
or loss attributable to common stockholders by the weighted average number of
shares of common stock outstanding during the period. Diluted net income or loss
per common share is calculated in the same manner, but also considers the impact
to net income and common shares for the potential dilution from stock options,
stock warrants and any other outstanding convertible securities.
The following is a reconciliation of the numerator and denominator used for the
computation of basic and diluted net income or loss per common share.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE DATA 2000 1999 1998
------------- ------------- -------------
<S> <C> <C> <C>
Net income (loss)............................... $ 142,227 $ 4,614 $ (287,145)
============= ============= =============
Weighted average common shares - basic.......... 45,823 39,928 25,926
Effect of diluted securities:
Stock options........................... 529 59 -
------------- ------------- -------------
Weighted average common shares - diluted........ 46,352 39,987 25,926
============= ============= =============
Net income (loss) per common share
Basic................................... $ 3.10 $ 0.12 $ (11.08)
Diluted................................. 3.07 0.12 (11.08)
============= ============= =============
</TABLE>
For the years ended December 31, 2000 and 1999, approximately 1.6 million shares
of common stock under options were excluded from the diluted net income per
share computation as the exercise price exceeded the average market price of the
Company's common stock. Warrants representing 75,000 shares of common stock were
also excluded from the 1999 diluted net income per share computation as the
exercise price exceeded the average market price of the Company's common stock.
For the year ended December 31, 1998, all dilutive securities were excluded from
the calculation of diluted loss per share, as their effect would have been
anti-dilutive.
Statement of Cash Flows
For purposes of the Statement of Cash Flows, cash equivalents include time
deposits, certificates of deposit and all liquid debt instruments with
maturities at the date of purchase of three months or less.
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any
amounts due from purchasers of oil and natural gas are included in accrued
production receivables.
The Company follows the "sales method" of accounting for its oil and natural gas
revenue, whereby the Company recognizes sales revenue on all oil or natural gas
sold to its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A receivable or liability is recognized
only to the extent that the Company has an imbalance on a specific property
greater than the expected remaining proved reserves. As of December 31, 2000 and
1999, the Company's aggregate oil and natural gas imbalances were not material
to its consolidated financial statements.
-45-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
The Company recognizes revenue and expenses of purchased producing properties
commencing from the closing or agreement date, at which time the Company also
assumes control.
Income Taxes
Income taxes are accounted for using the liability method under which deferred
income taxes are recognized for the tax consequences of "temporary differences"
by applying enacted statutory tax rates applicable to future years to
differences between the financial statement carrying amounts and the tax basis
of existing assets and liabilities. The effect on deferred taxes for a change in
tax rates is recognized in income in the period that includes the enactment
date.
Comprehensive Income
Effective January 1, 1998, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 130, "Reporting Comprehensive Income." This statement
establishes standards for reporting of comprehensive income and its components
in the financial statements. For the years ended December 31, 2000, 1999 and
1998, there were no differences between net income (loss) and comprehensive
income.
Financial Instruments with Off-Balance-Sheet Risk
and Concentrations of Credit Risk
The Company's product price hedging activities are described in Note 6 to the
consolidated financial statements. The Company enters into financial
transactions to hedge anticipated future production. Hedge accounting is
utilized when there is a high degree of correlation between price movements in
the derivative and the underlying item designated as being hedged. The impact of
changes in the market value of the financial transactions, which serve as
hedges, is deferred until the related physical transaction is completed. The
changes, when recognized, are included in oil and gas revenues. If a financial
transaction that has been accounted for as a hedge is closed before the date of
the anticipated future transaction, the accumulated change in the value of the
financial transactions is deferred until the related physical transaction is
completed. In the event it becomes likely that an anticipated transaction will
not occur or that adequate correlation no longer exists, hedge accounting is
terminated and future changes in the fair value of the derivative are recognized
as gains or losses in the statement of operations. Credit risk relating to these
hedges is minimal because of the credit risk standards required for
counter-parties and monthly settlements. The Company only has entered into
hedging contracts with large and financially strong companies. See "Recently
Issued Accounting Pronouncements" below for information regarding the Company's
adoption of new accounting rules for hedging activities and derivative
instruments.
The Company's financial instruments that are exposed to concentrations of credit
risk consist primarily of cash equivalents, short-term investments and trade and
accrued production receivables in addition to the product price hedges discussed
above. The Company's cash equivalents and short-term investments represent high-
quality securities placed with various investment grade institutions. This
investment practice limits the Company's exposure to concentrations of credit
risk. The Company's trade and accrued production receivables are dispersed among
various customers and purchasers; therefore, concentrations of credit risk are
limited.
Also, the Company's more 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.
Fair Value of Financial Instruments
As of December 31, 2000 and 1999, the carrying value of the Company's bank debt
and most other financial instruments approximates their fair market value. The
Company's bank debt is based on a floating interest rate and thus adjusts to
market as interest rates change. During 1998, the Company issued $125 million of
9% Senior Subordinated Notes due 2008. As of December 31, 2000 and 1999, these
notes had a market value of approximately $108.4 million and $113.8 million,
respectively, based on quoted market prices. The Company's other financial
instruments are primarily cash, cash equivalents, short-term receivables and
payables which approximate fair value due to the nature of the instrument and
the relatively short maturities.
-46-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amount of certain assets, liabilities, revenues and expenses
as of and for the reporting period. Estimates and assumptions are also required
in the disclosure of contingent assets and liabilities as of the date of the
financial statements. Actual results may differ from such estimates.
Recently Issued Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." This
statement establishes accounting and reporting standards for derivative
instruments and hedging activities. It requires that every derivative instrument
be recorded on the balance sheet as either an asset or liability measured at
fair value. The statement requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. If hedge accounting criteria are met, the change in a derivative's fair
value (for a cash flow hedge) is deferred in stockholders' equity as a component
of comprehensive income to the extent the hedge is effective. These deferred
gains and losses are recognized in income in the period in which the hedge item
and hedging instrument are settled. The ineffective portions of hedge returns
are recognized currently in earnings.
SFAS No. 137, issued in August 1999, postponed for one year the mandatory
effective date for SFAS No. 133, to January 1, 2001. In June 2000, the FASB
issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities," as an amendment to SFAS No. 133.
All derivatives within the Company have been identified. The Company has
designated, documented and assessed the hedging relationships, all of which are
cash flow hedges. Adoption by the Company of this accounting standard as of
January 1, 2001 resulted in the recognition of $1.6 million of derivative assets
with a cumulative effect increase to other comprehensive income of approximately
$1.0 million after tax for the transition adjustment as of January 1, 2001.
-47-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
NOTE 2. PROPERTY AND EQUIPMENT
Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, the Company may exclude certain unevaluated costs
from the amortization base pending determination of whether proved reserves have
been discovered or impairment has occurred. A summary of the unevaluated
properties excluded from oil and natural gas properties being amortized at
December 31, 2000 and 1999 and the year in which they were incurred follows:
<TABLE>
<CAPTION>
DECEMBER 31, 2000 DECEMBER 31, 1999
--------------------------------------------- -------------------------------------------
Costs Incurred During: Costs Incurred During:
--------------------------------- ---------------------------------
2000 1999 1998 Total 1999 1998 1997 Total
---------- ---------- --------- ---------- --------- --------- --------- --------
AMOUNTS IN THOUSANDS
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Property acquisition costs.. $ 10,709 $ 750 $ 65 $ 11,524 $ 1,283 $ 4,693 $ 30,566 $ 36,542
Exploration costs........... 1,332 193 761 2,286 1,427 3,402 - 4,829
---------- ---------- --------- ---------- --------- --------- --------- --------
Total................... $ 12,041 $ 943 $ 826 $ 13,810 $ 2,710 $ 8,095 $ 30,566 $ 41,371
========== ========== ========= ========== ========= ========= ========= ========
</TABLE>
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
Pending determination of proved reserves attributable to the above costs, the
Company cannot assess the future impact on the amortization rate. As of December
31, 2000, approximately $10.0 million of the total unevaluated property balance
of $13.8 million related to the Company's purchase of Thornwell Field in
Southwestern Louisiana in the fourth quarter of 2000. This cost will be
transferred into the amortization base as the undeveloped areas are tested. The
Company anticipates that the majority of this activity should be completed
during 2001 and 2002.
1998 Writedown of Oil and Gas Properties Resulting
From Full Cost Ceiling Test
Due to low oil prices in 1998, the Company incurred a writedown of its oil and
gas properties pursuant to the full cost pool ceiling test mandated by the
Securities and Exchange Commission. As of June 30, 1998, the Company incurred a
$165 million writedown and as of December 31, 1998, incurred an additional $115
million writedown, or a total of $280 million for the year ended December 31,
1998.
Capitalized Costs
Capitalized general and administrative costs that directly relate to exploration
and development activities were $3.2 million, $2.8 million and $2.7 million for
the years ended December 31, 2000, 1999 and 1998, respectively.
Amortization per BOE, excluding the full cost pool writedown, was $4.62, $4.17
and $7.26 for the years ended December 31, 2000, 1999 and 1998, respectively.
-48-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
NOTE 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31,
----------------------------
2000 1999
------------ ------------
AMOUNTS IN THOUSANDS
Senior bank loan................................ $ 74,000 $ 27,500
9% Senior Subordinated Notes due 2008........... 125,000 125,000
------------ ------------
Total long-term debt......................... $ 199,000 $ 152,500
============ ============
Senior Bank Loan
The Company has a credit facility with Bank of America, as agent for a group of
seven other banks. The credit facility is secured by substantially all of the
Company's producing oil and gas properties and matures on December 31, 2003.
This credit facility has several restrictions including, among others: (i) a
prohibition on the payment of dividends, (ii) a requirement for a minimum equity
balance, (iii) a requirement to maintain positive working capital, as defined,
(iv) a minimum interest coverage test and (v) a prohibition of most debt and
corporate guarantees. The Company's bank credit facility provides for a
semi-annual redetermination of the borrowing base on April 1st and October 1st.
On October 13, 2000, the Company amended and restated its bank credit facility.
Among other things, this amendment (i) extended the maturity of the credit line
for one additional year, to December 31, 2003, (ii) increased the interest rate
on the loan by increasing the LIBOR margin for Eurodollar loans by 0.25%, (iii)
reduced the number of banks in the line by one and re-allocated the loan among
the remaining eight banks, and (iv) increased the Company's conforming borrowing
base from $60 million to $110 million. In December 2000, at the request of the
Company, the banks conducted an additional review of the Company's credit
facility and increased the borrowing base from $110 million to $150 million.
As of December 31, 2000, the Company had $74.0 million outstanding under the
facility, at a weighted average interest rate of 7.9%, $370,000 of letters of
credit outstanding and a borrowing base of $150 million. The next scheduled
redetermination of the borrowing base will be as of April 1, 2001, based on
December 31, 2000 assets and proved reserves.
Subordinated Debt
On February 26, 1998, Denbury Management Inc. ("DMI"), a wholly owned subsidiary
of the Company at that time, issued $125 million in aggregate principal amount
of 9% Senior Subordinated Notes due 2008 which require only semi-annual interest
payments until maturity. In April 1999, DMI was merged into Denbury Resources
Inc., which expressly assumed all liabilities of DMI, including the 9% Senior
Subordinated Notes. These notes contain certain debt covenants, including
covenants that limit (i) indebtedness, (ii) certain restricted payments
including dividends, (iii) sale/leaseback transactions, (iv) transactions with
affiliates, (v) liens, (vi) asset sales and (vii) mergers and consolidations.
The net proceeds to the Company from the debt offering were approximately $121.8
million, before offering expenses.
-49-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Indebtedness Repayment Schedule
The Company's indebtedness as of December 31, 2000 is repayable as follows:
AMOUNTS IN THOUSANDS
- -------------------------------------------------------
YEAR
2001.......................................$ -
2002....................................... -
2003....................................... 74,000
2004....................................... -
2005....................................... -
Thereafter................................. 125,000
------------
Total indebtedness................$ 199,000
============
NOTE 4. INCOME TAXES
The Company's income tax provision (benefit) is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS 2000 1999 1998
----------- ---------- -----------
<S> <C> <C> <C>
Current income tax expense
Federal........................................$ 558 $ - $ -
State.......................................... - - -
----------- ---------- -----------
Total current income tax expense........$ 558 $ - $ -
=========== ========== ===========
Deferred income tax benefit
Federal........................................$ (67,852) $ - $ (15,620)
State.......................................... - - -
----------- ---------- -----------
Total deferred income tax benefit.......$ (67,852) $ - $ (15,620)
=========== ========== ===========
Total income tax benefit............$ (67,294) $ - $ (15,620)
=========== ========== ===========
</TABLE>
The Company's income tax benefit for 2000 is primarily the result of the
elimination of the Company's valuation allowance on its net deferred tax assets
as of December 31, 2000. The valuation allowance on the Company's net deferred
tax assets was initially recorded at December 31, 1998 and remained recorded at
December 31, 1999 based upon management's belief that it was more likely than
not that the Company would not be able to generate sufficient taxable income to
realize the benefit of its net deferred tax assets. In reaching this conclusion,
management considered both historical results and its expectations regarding
future taxable income based on oil and gas pricing consistent with the Company's
long-term forecasting and anticipated levels of capital spending. As a result of
the near-term recovery of oil and natural gas prices that began in the latter
part of 1999 and continued throughout 2000, the Company was able to generate net
income for 2000 and taxable income that utilized approximately $27.2 million of
the Company's net operating losses. Based on current production levels, current
expectations regarding near-term oil and gas prices, current hedging positions,
anticipated capital expenditures, the estimated reversal of book and tax
temporary differences, available tax planning strategies and the Company's
expectations regarding future taxable income, management concluded that the
valuation allowance on its net deferred tax assets was no longer necessary and
at December 31, 2000 eliminated the entire valuation allowance. The Company's
current income tax expense in 2000 is for alternative minimum taxes that may not
be offset by net operating losses.
-50-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
At December 31, 2000, the Company had net operating loss carryforwards for U.S.
federal income tax purposes of approximately $112.7 million and approximately
$47.7 million for alternative minimum tax purposes. The net operating losses are
scheduled to expire as follows:
INCOME ALTERNATIVE
AMOUNTS IN THOUSANDS TAX MINIMUM TAX
- ----------------------------------------------------- ---------------
YEAR
2012 .................................$ 20,200 $ -
2018 ................................. 70,777 32,157
2019 ................................. 21,713 15,585
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 2000 and 1999 balance sheet dates.
At December 31, 2000 and 1999, the Company's deferred tax assets and liabilities
were as follows:
DECEMBER 31,
----------------------------
AMOUNTS IN THOUSANDS 2000 1999
------------- ------------
Deferred tax assets:
Loss carryforwards........................ $ 41,695 $ 51,748
Basis difference of exploration and
production assets..................... 26,144 43,883
Tax credit carryover...................... 558 -
Deferred tax liabilities:
Other..................................... (545) (494)
------------- ------------
Net deferred tax asset......................... 67,852 95,137
Less: Valuation allowance................. - (95,137)
------------- ------------
Total net deferred tax asset.......... $ 67,852 $ -
============= ============
The Company's income tax provision (benefit) varies from the amount that would
result from applying the statutory income tax rate to income before income taxes
as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
AMOUNTS IN THOUSANDS 2000 1999 1998
------------ ------------ -------------
<S> <C> <C> <C>
Income tax provision (benefit) calculated using the
statutory income tax rate............................. $ 26,227 $ 1,615 $ (105,968)
State income taxes and other............................. 1,616 (350) (6,054)
Change in valuation allowance............................ (95,137) (1,265) 96,402
------------ ------------ -------------
Total income tax benefit........................... $ (67,294) $ - $ (15,620)
============ ============ =============
</TABLE>
-51-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Note 5. Stockholders' Equity
Authorized
The Company is authorized to issue 100 million shares of Common Stock, par value
$.001 per share, and 25 million shares of Preferred Stock, par value $.001 per
share. The preferred shares may be issued in one or more series with rights and
conditions determined by the board of directors.
1999 Sale of Stock to the Texas Pacific Group
In April 1999, the stockholders approved the sale of 18,552,876 shares of common
stock to an affiliate of the Texas Pacific Group ("TPG") for $100 million or
$5.39 per share. As a result of this transaction, TPG's ownership of the
Company's outstanding common stock increased from approximately 32% to
approximately 60%. The net proceeds from this sale of common stock of
approximately $98.5 million were used to pay down the Company's revolving credit
facility.
1998 Equity Offering
On February 26, 1998, the Company closed on a public offering of 5,240,780
shares of common stock at a price to the public of $16.75 per share and a net
price to the Company of $15.955 per share (the "Equity Offering"). Concurrently
with the Equity Offering, TPG purchased 313,400 shares of common stock from the
Company at $15.955 per share, equal to the price to the public per share less
underwriting discounts and commissions (the "TPG Purchase"). The net proceeds to
the Company from the Equity Offering and TPG Purchase were approximately $88.6
million, before offering expenses.
Warrants
On May 5, 2000, 75,000 warrants that were previously outstanding at an exercise
price of Cdn. $8.40 expired. Each warrant entitled the holder thereof to
purchase one share of common stock at any time prior to the expiration date.
Stock Option Plan
As of December 31, 2000, the Company had a total of 4,535,000 shares of Common
Stock reserved for issuance pursuant to its Stock Option Plan. On February 22,
2001, the Board of Directors of the Company authorized a 600,000 increase to the
number of shares that may be issued pursuant to this plan, subject to the
approval of shareholders at the May 23, 2001 annual meeting. Under the terms of
the plan, incentive and non-qualified options may be issued to officers, key
employees and consultants. Options generally become exercisable over a four year
vesting period with the specific terms of vesting determined by the Board of
Directors at the time of grant. The options expire over terms not to exceed ten
years from the date of grant, ninety days after termination of employment or
permanent disability or one year after the death of the optionee. The options
are granted at the fair market value at the time of grant, which is generally
defined as the average closing price of the Company's shares of Common Stock for
the ten trading days prior to issuance. The plan is administered by the Stock
Option Committee of the Board.
-52-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Following is a summary of stock option activity during the years ended December
31, 2000, 1999 and 1998:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------
2000 1999 1998
--------------------------- ---------------------------- ---------------------------
Number Weighted Number Weighted Number Weighted
of Options Average Price of Options Average Price of Options Average Price
----------- --------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of
year......................... 3,317,384 $ 8.66 1,890,531 $ 13.04 1,546,256 $ 11.06
Granted........................ 595,635 4.11 1,830,503 4.38 488,559 17.71
Exercised...................... (40,458) 4.60 - - (132,256) 7.29
Forfeited...................... (70,439) 6.70 (403,650) 9.78 (12,028) 7.15
----------- --------------- ------------- -------------- ------------ --------------
Outstanding at end of year..... 3,802,122 $ 8.03 3,317,384 $ 8.66 1,890,531 $ 13.04
=========== =============== ============= ============== ============ ==============
Exercisable at end of year..... 1,310,382 $ 9.35 622,001 $ 9.39 398,474 $ 8.85
=========== =============== ============= ============== ============ ==============
Weighted average fair value of
options granted.............. $ 2.26 $ 2.56 $ 7.64
=============== ============== ==============
</TABLE>
The Company applies the intrinsic value method in accounting for options granted
under the Stock Option Plan and accordingly no compensation cost is recognized.
Had compensation expense been recognized based on the fair value of the options
on the date they were granted, the Company's net income (loss) and net income
(loss) per common share would have been reduced (increased) to the following pro
forma amounts:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
------------ ----------- ------------
<S> <C> <C> <C>
NET INCOME (LOSS):
As reported (thousands).............................................$ 142,227 $ 4,614 $ (287,145)
Pro forma (thousands)............................................... 139,574 772 (289,463)
NET INCOME (LOSS) PER COMMON SHARE:
As reported:
Basic...........................................................$ 3.10 $ 0.12 $ (11.08)
Diluted......................................................... 3.07 0.12 (11.08)
Pro forma:
Basic...........................................................$ 3.05 $ 0.02 $ (11.16)
Diluted......................................................... 3.05 0.02 (11.16)
</TABLE>
The Company estimated the fair value of each option grant using the
Black-Scholes option pricing method while using the following weighted average
assumptions:
2000 1999 1998
------------ ------------ ----------
Risk-free interest rate 6.5% 4.7% 5.7%
Expected life 5 years 5 years 5 years
Expected volatility 55.0% 64.7% 39.2%
Dividend yield - - -
-53-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
The following table summarizes information on the Company's stock options
outstanding at December 31, 2000:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------------- --------------------------
Weighted
Number Average Weighted Number Weighted
of Options Remaining Average of Options Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices at 12/31/00 Life Price at 12/31/00 Price
- ------------------------------ --------------- -------------- ------------- ------------- -----------
<S> <C> <C> <C> <C> <C>
$ 3.77 - $ 5.50 2,172,847 8.0 years $ 4.18 383,149 $ 4.25
5.51 - 8.00 294,507 5.5 years 6.64 253,625 6.72
8.01 - 11.50 222,282 4.9 years 9.92 220,550 9.93
11.51 - 14.50 627,938 5.7 years 13.38 321,240 13.39
14.51 - 22.25 484,548 6.7 years 18.32 131,818 18.40
-----------------------------------------------------------------------------
$ 3.77 - $22.25 3,802,122 7.1 years $ 8.03 1,310,382 $ 9.35
-----------------------------------------------------------------------------
</TABLE>
Stock Purchase Plan
The Company maintains a Stock Purchase Plan which authorizes the sale of up to
750,000 shares of Common Stock to all full-time employees. Under the plan, the
employees may contribute up to 10% of their base salary and the Company matches
75% of the employee contribution. The combined funds are used to purchase
previously unissued Common Stock of the Company based on its current market
value at the end of each quarter. The Company recognizes compensation expense
for the 75% Company matching portion, which totaled $560,000, $501,000 and
$648,000 for the years ended December 31, 2000, 1999 and 1998, respectively.
This plan is administered by the Stock Purchase Plan Committee of the Board.
401(k) Plan
The Company offers a 401(k) Plan to which employees may contribute tax deferred
earnings subject to Internal Revenue Service limitations. The Company matches
75% of employee contributions up to an employee's contribution of 6% of their
salary. This Company match becomes vested over a four year period. During 2000,
1999 and 1998, the Company made matching contributions of $427,000, $239,000 and
$217,000, respectively, to the 401(k) Plan.
NOTE 6. PRODUCT PRICE HEDGING CONTRACTS
The Company enters into various financial contracts to hedge its exposure to
commodity price risk associated with anticipated future oil and natural gas
production. These contracts consist of price ceilings and floors, no- cost
collars and fixed price swaps.
As of December 31, 1998, the Company had no-cost financial contracts ("collars")
in place that hedged a total of 40 million cubic feet of natural gas per day
("MMcf/d") through August 1999 and 30 MMcf/d thereafter through December 2000.
The first set of contracts had a weighted average ceiling price of approximately
$2.95 per MMBtu and the second set of contracts had a ceiling price of $2.58 per
MMBtu. Both contracts had a
-54-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
floor price of $1.90 per MMBtu. During the first half of 1999, the Company
collected $603,000 on these contracts, but paid out $729,000 during the second
half of the year. During the second half of 1999, the Company also retired six
MMcf/d of the 30 MMcf/d collar at a cost of approximately $672,000. The net
out-of-pocket cost during 1999 on the natural gas collars was $798,000,
including the cost of the buyouts. During 2000, the Company paid out $11.9
million relating to these natural gas collars, reducing the net average natural
gas price it received by $0.88 per Mcf. All of the natural gas collars expired
as of December 31, 2000.
During March and April 1999, the Company entered into two collars to hedge a
portion of its oil production. The first contract was a fixed price swap for
3,000 Bbls/d for the period of April through December 1999 at a price of $14.24
per Bbl. The second contract was a collar to hedge 3,000 Bbls/d for the period
of May 1999 through December 2000 with a floor price of $14.00 per Bbl and a
ceiling price of $18.05 per Bbl. The Company paid approximately $8.6 million on
these contracts during 1999, which lowered the effective net oil price received
by the Company for the year by $1.95 per barrel. During 2000, the Company paid
out $13.4 million relating to these oil collars, reducing the net average oil
price it received by $2.39 per Bbl. All of the oil collars expired as of
December 31, 2000.
In the aggregate, the Company paid out a net amount of $9.4 million during 1999
and $25.3 million during 2000 on its commodity hedges. All of these contracts
expired as of December 31, 2000.
For the years 2001 and 2002, the Company acquired puts or floors in 2000 to
hedge a portion of its anticipated oil and natural gas production. For 2001, the
Company acquired a $22.00 floor on 12,800 Bbls/d and a $2.80 floor on 37.5
MMBtu/d for an aggregate cost of $2.6 million, which together cover
approximately 75% of the Company's anticipated production, excluding the
anticipated production from the acquisitions made in the fourth quarter of 2000.
The floors relating to the acquisitions cost a total of approximately $2.5
million and have varying volume and price floors each quarter for 2001 and 2002.
The price floor varies by quarter, but have a weighted average price of $3.51
for 2001 and $3.23 for 2002. The volumes on the floors also vary by quarter with
a weighted average volume of 23.0 MMBtu/d for 2001 and 7.8 MMBtu/d for 2002. The
Company has recorded the cost of these floors in either current or long-term
other assets in its Consolidated Balance Sheet as of December 31, 2000,
depending on their expiration dates. The fair value of these floors as of
December 31, 2000 was $6.7 million. The following table lists all of the
individual floors in place as of December 31, 2000.
<TABLE>
<CAPTION>
Volume Floor Volume Floor
Period Per Day Price Period Per Day Price
----------------------------------- ------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Oil Options or "puts" (Bbls/d): Gas Options or "puts" (MMBtu/d):
2001 12,800 $22.00 Q1 - 2002 5.3 $3.65
Q1 - 2002 6.7 $3.07
Gas Options or "puts" (MMBtu/d): Q2 - 2002 3.8 $3.40
2001 37.5 $2.80 Q2 - 2002 4.4 $3.04
Q3 - 2002 2.9 $3.38
Q1 - 2001 11.5 $4.25 Q3 - 2002 3.5 $2.99
Q1 - 2001 15.1 $3.52 Q4 - 2002 2.1 $3.38
Q2 - 2001 10.5 $3.95 Q4 - 2002 2.5 $2.93
Q2 - 2001 13.9 $3.23
Q3 - 2001 10.0 $3.70
Q3 - 2001 13.0 $3.07
Q4 - 2001 7.9 $3.56
Q4 - 2001 10.4 $2.94
</TABLE>
NOTE 7. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles that totaled $1.4 million, $1.2 million and $672,000 for
the years ended December 31, 2000, 1999 and 1998, respectively. At December 31,
2000, long-term commitments for these items require the following future minimum
rental payments:
AMOUNTS IN THOUSANDS
2001.............................$ 1,475
2002............................. 1,457
2003............................. 1,327
2004............................. 1,346
2005............................. 1,477
Thereafter ...................... 5,663
---------------
Total lease commitments.....$ 12,745
===============
-55-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
The Company is subject to various possible contingencies which arise primarily
from interpretation of federal and state laws and regulations affecting the oil
and natural gas industry. Such contingencies include differing interpretations
as to the prices at which oil and natural gas sales may be made, the prices at
which royalty owners may be paid for production from their leases, environmental
issues and other matters. Although management believes that it has complied with
the various laws and regulations, administrative rulings and interpretations
thereof, adjustments could be required as new interpretations and regulations
are issued. In addition, production rates, marketing and environmental matters
are subject to regulation by various federal and state agencies.
The Company and its subsidiaries are involved in various lawsuits, claims and
regulatory proceedings incidental to their businesses. In the opinion of
management, the outcome of such matters will not have a material adverse effect
on the Company's business, consolidated financial position, results of
operations or cash flows.
NOTE 8. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon operations. For the year
ended December 31, 2000, the Company sold 10% or more of its net production of
oil and natural gas to the following purchasers: Hunt Refining (24%), Southland
Refining (17%), EOTT Energy (16%), and Dynegy (10%). For the year ended December
31, 1999, four purchasers each accounted for more than 10% of the Company's net
production of oil and natural gas and 68% in the aggregate. For the year ended
December 31, 1998, three purchasers each accounted for more than 10% of the
Company's net production of oil and natural gas and 62% in the aggregate.
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural
gas property acquisition, exploration and development activities. Property
acquisition costs are those costs incurred to purchase, lease, or otherwise
acquire property, including both undeveloped leasehold and the purchase of
reserves in place. Exploration costs include costs of identifying areas that may
warrant examination and in examining specific areas that are considered to have
prospects containing oil and natural gas reserves, including costs of drilling
exploratory wells, geological and geophysical costs and carrying costs on
undeveloped properties. Development costs are incurred to obtain access to
proved reserves, including the cost of drilling development wells, and to
provide facilities for extracting, treating, gathering and storing the oil and
natural gas.
Costs incurred in oil and natural gas activities for the years ended December
31, 2000, 1999 and 1998 are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------
AMOUNTS IN THOUSANDS 2000 1999 1998
----------- ----------- -----------
Property acquisitions:
Proved......................... $ 50,285 $ 20,488 $ 13,674
Unevaluated.................... 11,741 1,283 6,604
Exploration......................... 6,782 7,672 12,222
Development......................... 65,213 25,524 70,152
----------- ----------- -----------
Total costs incurred........... $ 134,021 $ 54,967 $ 102,652
=========== =========== ===========
-56-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Property Acquisitions
During the fourth quarter of 2000, the Company completed acquisitions totaling
$56.5 million in the Thornwell, Porte Barre and Iberia Fields located in
southwestern Louisiana. Approximately $10.0 million of these acquisition costs
were recorded as unevaluated property costs at December 31, 2000. The Company
also completed other minor acquisitions totaling $3.8 million during 2000.
During 1999, the Company completed acquisitions totaling $20.5 million,
primarily comprised of a $12.3 million acquisition of a tertiary recovery oil
field (Little Creek) in southern Mississippi and a $4.9 million acquisition of
the King Bee Field, also in Mississippi.
NOTE 9. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31, 2000 were
prepared by DeGolyer and MacNaughton, and as of December 31, 1999 and 1998 were
prepared by Netherland & Sewell, independent petroleum engineers located in
Dallas, Texas. The reserves were prepared in accordance with guidelines
established by the Securities and Exchange Commission and, accordingly, were
based on existing economic and operating conditions. Oil and natural gas prices
in effect as of the reserve report date were used without any escalation except
in those instances where the sale is covered by contract, in which case the
applicable contract prices including fixed and determinable escalations were
used for the duration of the contract, and thereafter the last contract price
was used (See "Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves" below for a
discussion of the effect of the different
prices on reserve quantities and values.) Operating costs, production and ad
valorem taxes and future development costs were based on current costs with no
escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in the United States.
-57-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
<TABLE>
<CAPTION>
Estimated Quantities of Reserves
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
2000 1999 1998
---------------------- ---------------------- ----------------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
--------- ---------- ---------- --------- --------- ----------
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR................ 51,832 50,438 28,250 48,803 52,018 77,191
Revisions of previous estimates........ 4,078 8,271 83 418 (7,267) (15,369)
Revisions due to price changes......... 412 1,905 15,884 75 (14,921) (990)
Extensions and discoveries............. 2,746 25,593 4,383 8,910 678 1,951
Improved recovery (1).................. 16,466 5,613 - - - -
Production............................. (5,555) (13,533) (4,413) (10,201) (4,965) (13,361)
Acquisition of minerals in place....... 1,182 23,209 7,722 2,693 2,998 21
Sales of minerals in place............. (494) (946) (77) (260) (291) (640)
--------- ---------- ---------- --------- --------- ----------
BALANCE AT END OF YEAR...................... 70,667 100,550 51,832 50,438 28,250 48,803
========= ========== ========== ========= ========= ==========
PROVED DEVELOPED RESERVES
Balance at beginning of year........... 32,767 41,635 20,357 44,995 31,355 69,805
Balance at end of year................. 52,353 77,358 32,767 41,635 20,357 44,995
<FN>
(1) For years prior to December 31, 2000, the changes related to improved
recovery were not material and were included with revisions of previous
estimates.
</FN>
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does
not purport to present the fair market value of the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates. It should be noted that
estimates of reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. The product prices used
in calculating these reserves have varied widely during the three year period.
These prices have a significant impact on both the quantities and value of the
proven reserves as the reduced oil price causes wells to reach the end of their
economic life much sooner and also makes certain proved undeveloped locations
uneconomical, both of which reduce the reserves. The following representative
oil and natural gas year-end prices were used in the Standardized Measure. These
prices were adjusted by field to arrive at the appropriate corporate net price.
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998
------------- ------------ -------------
Oil (NYMEX) $ 26.80 $ 25.60 $ 12.00
Natural Gas (NYMEX Henry Hub) 9.78 2.12 2.15
-58-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Future cash inflows were reduced by estimated future production and development
costs based on year-end costs to determine pre-tax cash inflows. Future income
taxes were computed by applying the statutory tax rate to the excess of pre-tax
cash inflows over the Company's tax basis in the associated proved oil and
natural gas properties. Tax credits and net operating loss carryforwards were
also considered in the future income tax calculation. Future net cash inflows
after income taxes were discounted using a 10% annual discount rate to arrive at
the Standardized Measure.
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------
AMOUNTS IN THOUSANDS 2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows....................................................... $ 2,609,306 $ 1,222,590 $ 317,148
Future production costs................................................... (600,195) (370,385) (112,521)
Future development costs.................................................. (95,068) (69,642) (23,887)
------------ ------------ ------------
Future net cash flows before taxes ................................... 1,914,043 782,563 180,740
10% annual discount for estimated timing of cash flows.................... (755,074) (319,693) (65,721)
------------ ------------ ------------
Discounted future net cash flows before taxes......................... 1,158,969 462,870 115,019
Discounted future income taxes............................................ (317,670) (14,496) -
------------ ------------ ------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS.................. $ 841,299 $ 448,374 $ 115,019
============ ============ ============
</TABLE>
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
AMOUNTS IN THOUSANDS 2000 1999 1998
------------- ------------- --------------
<S> <C> <C> <C>
BEGINNING OF YEAR...................................................... $ 448,374 $ 115,019 $ 335,308
Sales of oil and natural gas produced, net of production costs......... (132,645) (51,884) (52,721)
Net changes in sales prices............................................ 255,917 253,244 (198,836)
Extensions and discoveries, less applicable future development
and production costs................................................ 200,966 48,918 6,605
Improved recovery (1).................................................. 77,702 - -
Previously estimated development costs incurred........................ 20,623 8,402 30,742
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production................. 48,018 6,433 (76,532)
Accretion of discount.................................................. 46,287 11,502 33,531
Acquisition of minerals in place....................................... 183,634 71,631 12,869
Sales of minerals in place............................................. (4,403) (395) (1,968)
Net change in income taxes............................................. (303,174) (14,496) 26,021
------------- ------------- --------------
END OF YEAR............................................................ $ 841,299 $ 448,374 $ 115,019
============= ============= ==============
<FN>
(1) For years prior to December 31, 2000, the changes related to improved
recovery were not material and were included with revisions of previous
estimates.
</FN>
</TABLE>
-59-
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
Note 10. Subsequent Event
On January 18, 2001, the Company entered into a purchase and sale agreement,
effective January 1, 2001, to acquire certain carbon dioxide ("CO2") reserves,
production and associated assets from a division of Airgas Inc. for $42 million.
The acquisition included ten producing CO2 wells and production facilities
located near Jackson, Mississippi, and a 183-mile 20-inch pipeline which is
currently transporting CO2 to Denbury's tertiary recovery operation at Little
Creek Field, as well as to other commercial customers. The Company completed the
purchase of these assets on February 2, 2001. The operating results from these
assets in future periods will be accounted for separately from the Company's oil
and gas producing activities.
NOTE 11. UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 2000 and 1999:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
IN THOUSANDS EXCEPT PER SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
- ------------------------------------------------------------------------------------------------------------------
2000
- ----
<S> <C> <C> <C> <C>
Revenues ....................................... $ 35,767 $ 37,550 $ 44,749 $ 63,585
Expenses ....................................... 24,232 23,927 25,629 32,930
Net income ..................................... 11,515 13,603 19,039 98,070
Net income per share: ..........................
Basic .................................... 0.25 0.30 0.42 2.14
Diluted .................................. 0.25 0.30 0.41 2.09
Cash flow from operations (a)................... 19,562 21,340 27,502 43,151
Cash flow used for investing activities......... 16,088 21,462 24,069 71,421
Cash flow provided by (used for) financing
activities................................ 308 (3,806) (2,131) 53,222
1999
- ----
Revenues ....................................... $ 15,064 $ 18,228 $ 22,378 $ 27,320
Expenses ....................................... 18,092 17,736 19,974 22,574
Net income (loss) .............................. (3,028) 492 2,404 4,746
Net income (loss) per share: ...................
Basic .................................... (0.11) 0.01 0.05 0.10
Diluted .................................. (0.11) 0.01 0.05 0.10
Cash flow from operations (a)................... 2,497 6,598 9,547 12,977
Cash flow used for investing activities......... 6,917 13,232 21,841 16,305
Cash flow provided by financing activities...... 9,155 7,441 10,179 39
<FN>
(a) Exclusive of the net change in non-cash working capital balances.
</FN>
</TABLE>
-60-
<PAGE>
Common Stock Trading Summary
The following table summarizes the high and low last reported sales prices on
days in which there were trades of the Company's common stock on the New York
Stock Exchange ("NYSE"), and on The Toronto Stock Exchange ("TSE") (as reported
by such exchange) for each quarterly period for the last two fiscal years. The
trades on the NYSE are reported in U.S. dollars and the TSE trades are reported
in Canadian dollars.
As of February 1, 2001, to the best of the Company's knowledge, the common stock
was held of record by approximately 1,300 holders, of which approximately 300
were U.S. residents holding approximately 80% of the outstanding common stock of
the Company.
The Company has never paid any dividends on its common stock and currently does
not anticipate paying any dividends in the foreseeable future. The Company is
restricted from declaring or paying any cash dividends on its common stock under
its bank loan agreement.
<TABLE>
<CAPTION>
NYSE (U.S. $) TSE (CDN $)
- ---------------------------------------------------------------------------------------------------------------
HIGH LOW HIGH LOW
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
2000
- ----
First quarter $ 4.56 $ 3.75 $ 7.00 $ 4.80
Second quarter 6.38 3.75 9.50 5.00
Third quarter 8.44 4.31 12.65 5.80
Fourth quarter 11.44 6.31 16.80 9.30
- ---------------------------------------------------------------------------------------------------------------
2000 annual $ 11.44 $ 3.75 $ 16.80 $ 4.80
- ---------------------------------------------------------------------------------------------------------------
1999
- ----
First quarter $ 6.69 $ 3.81 $ 10.00 $ 5.50
Second quarter 5.00 3.38 7.45 5.00
Third quarter 5.44 4.00 7.45 5.90
Fourth quarter 5.31 3.69 7.50 5.25
- ---------------------------------------------------------------------------------------------------------------
1999 annual $ 6.69 $ 3.38 $ 10.00 $ 5.00
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
-61-
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>4
<FILENAME>0004.txt
<DESCRIPTION>EXHIBIT 21 - LIST OF SUBSIDIARIES
<TEXT>
<TABLE>
<CAPTION>
EXHIBIT 21
LIST OF SUBSIDIARIES
JURISDICTION OF
NAME OF SUBSIDIARY INCORPORATION STATUS
- ------------------------------------ ----------------------------- ---------------------------------------------
<S> <C> <C>
Tallahatchie Resources, Inc. Texas Wholly owned subsidiary of Denbury
Resources Inc. - dormant
Denbury Marine, L.L.C. Louisiana Wholly owned subsidiary of Denbury
Resources Inc. - marine company
Denbury Energy Services, Inc. Texas Wholly owned subsidiary of Denbury
Resources Inc. - marketing company
Denbury Carbonics, L.L.C. Mississippi Wholly owned subsidiary of Denbury
Resources Inc. - CO2 production and
transportation
</TABLE>
EX 21 - 1
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>5
<FILENAME>0005.txt
<DESCRIPTION>EXHIBIT 23 - INDEPENDENT AUDITORS' CONSENT
<TEXT>
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
DENBURY RESOURCES INC.
We consent to the incorporation by reference in Registration Statement Nos.
333-1006, 333-27995, 333- 55999, 333-70485, 333-39172 and 333-39218 of Denbury
Resources Inc. on Forms S-8 of our report dated February 22, 2001, appearing in
this Annual Report on Form 10-K of Denbury Resources Inc. for the year ended
December 31, 2000.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 16, 2001
EX 23 - 1
</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----