DENBURY RESOURCES INC, 424B1, 1998-02-23

DENBURY RESOURCES INC
424B1, 1998-02-23
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

Filed Pursuant to Rule 424(b)(1)
Registration Number 333-43207

PROSPECTUS

4,557,200 Shares

DRI LOGO

Denbury Resources Inc.
COMMON SHARES
------------------------
All of the Common Shares offered hereby are being sold by Denbury Resources Inc.
The Common Shares are listed on the New York Stock Exchange and on The Toronto
Stock Exchange under the symbol "DNR." On February 19, 1998, the reported last
sale price of the Common Shares on the New York Stock Exchange and The Toronto
Stock Exchange was US$17.25 per share and C$24.25 per share, respectively.
Concurrently with the closing of this offering of Common Shares (the "Equity
Offering"), entities affiliated with the Texas Pacific Group ("TPG"), the
Company's largest shareholder, will purchase from the Company 313,400 Common
Shares (the "TPG Purchase") at $15.955 per share (equal to the price to public
per share set forth below less underwriting discounts and commissions). The
closing of the Equity Offering and the TPG Purchase are each conditioned upon
the closing of the other.
Concurrently with the Equity Offering, Denbury Management, Inc.("DMI"), a wholly
owned subsidiary of the Company, is offering $125 million in aggregate principal
amount of 9% Senior Subordinated Notes Due 2008 (the "Debt Offering" and,
together with the Equity Offering, the "Offerings"). The closing of the Equity
Offering is not conditioned upon the closing of the Debt Offering. The Common
Shares offered hereby are also being offered for sale in Canada.
------------------------

SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR INFORMATION THAT SHOULD BE
CONSIDERED BY PROSPECTIVE INVESTORS.
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
------------------------

PRICE $16 3/4 A SHARE
------------------------

<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS(1) COMPANY(2)
-------- -------------- -----------
<S> <C> <C> <C>
Per Share.................... $16.75 $.795 $15.955
Total(3)..................... $76,333,100 $3,622,974 $72,710,126
</TABLE>

- ------------
(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriters."
(2) Before deducting expenses, estimated at $600,000.
(3) The Company has granted to the Underwriters an option, exercisable
within 30 days of the date hereof, to purchase up to an aggregate of
683,580 additional Common Shares at the price to public less
underwriting discounts and commissions, for the purpose of covering
over-allotments, if any. If the Underwriters exercise such option in
full, the total price to public, underwriting discounts and commissions
and proceeds to the Company will be $87,783,065, $4,166,420 and
$83,616,645, respectively. See "Underwriters."
------------------------

The Common Shares are offered, subject to prior sale, when, as and if
accepted by the Underwriters named herein and subject to approval of certain
legal matters by Cravath, Swaine & Moore, counsel for the Underwriters. It is
expected that delivery of the Common Shares will be made on or about February
26, 1998 at the office of Morgan Stanley & Co. Incorporated, New York, N.Y.,
against payment therefor in immediately available funds.
------------------------

MORGAN STANLEY DEAN WITTER
GORDON CAPITAL, INC.
JOHNSON RICE & COMPANY L.L.C.
LOEWEN, ONDAATJE, MCCUTCHEON USA LIMITED
February 19, 1998
<PAGE> 2

CORE OPERATING AREAS

This page will contain a map of the Gulf Coast Region depicting the
geographical location of the Company's eight largest fields.

---------------------

CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON SHARES.
SPECIFICALLY, THE UNDERWRITERS MAY OVER-ALLOT IN CONNECTION WITH THIS OFFERING
AND MAY BID FOR AND PURCHASE THE COMMON SHARES IN THE OPEN MARKET. FOR A
DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITERS."

IN CONNECTION WITH THIS OFFERING, CERTAIN UNDERWRITERS AND SELLING GROUP
MEMBERS MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON SHARES ON
THE NEW YORK STOCK EXCHANGE AND THE TORONTO STOCK EXCHANGE IN ACCORDANCE WITH
REGULATION M OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. SEE
"UNDERWRITERS."
2
<PAGE> 3

IT IS EXPECTED THAT DELIVERY OF THE COMMON SHARES WILL BE MADE AGAINST
PAYMENT THEREFOR ON OR ABOUT THE DATE SPECIFIED IN THE LAST PARAGRAPH OF THE
COVER PAGE OF THIS PROSPECTUS, WHICH IS THE FIFTH BUSINESS DAY FOLLOWING THE
DATE HEREOF (SUCH SETTLEMENT CYCLE BEING HEREIN REFERRED TO AS "T+5").
PURCHASERS OF COMMON SHARES SHOULD NOTE THAT TRADING OF THE COMMON SHARES ON THE
DATE HEREOF OR THE DAY THEREAFTER MAY BE AFFECTED BY THE T+5 SETTLEMENT. SEE
"UNDERWRITING."

NO DEALER, SALESMAN, OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT
BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE
UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED BY THIS PROSPECTUS
BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT
AUTHORIZED, OR IN WHICH THE PERSON MAKING THE OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO SO OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY DISTRIBUTION OF
SECURITIES MADE HEREUNDER OR THEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE
AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE
THE DATE HEREOF OR THEREOF OR THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS
IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF.

---------------------

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Information Incorporated by
Reference........................... 3
Prospectus Summary.................... 5
Risk Factors.......................... 12
Forward-Looking Statements............ 18
Debt Offering......................... 18
Use of Proceeds....................... 18
Price Range of Common Shares.......... 19
Dividend Policy....................... 19
Capitalization........................ 20
Unaudited Pro Forma Consolidated
Financial Information............... 21
Selected Consolidated Financial
Data................................ 26
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 27
Business and Properties............... 36
Management............................ 52
</TABLE>

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Principal Shareholders................ 55
Interests of Management in Certain
Transactions........................ 57
Description of Capital Stock.......... 58
Description of Certain Indebtedness... 59
Canadian Taxation and the Investment
Canada Act.......................... 61
Service and Enforcement of Legal
Process............................. 62
Shares Eligible for Future Sale....... 62
Underwriters.......................... 64
Legal Matters......................... 65
Experts............................... 66
Available Information................. 66
Glossary.............................. 67
Index to Consolidated Financial
Statements.......................... F-1
Summary Reserve Report................ A-1
</TABLE>

INFORMATION INCORPORATED BY REFERENCE

The following documents of the Company which have been previously filed
with the Securities and Exchange Commission (the "Commission") are incorporated
in this Prospectus: (i) Annual Report on Form 10-K for the year ended December
31, 1996; (ii) Quarterly Reports on Form 10-Q for the quarters ended March 31,
1997, June 30, 1997 and September 30, 1997; (iii) proxy statement dated May 21,
1997; (iv) reports on Form 8-K dated September 12, 1997, December 8, 1997,
December 16, 1997, and January 20, 1998.

All documents filed by the Company pursuant to Section 13(a), 13(c), 14 and
15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"),
subsequent to the date of this Prospectus and prior to the termination of the
offering of securities to be made hereunder shall be deemed to be incorporated
herein by reference and made a part hereof from the date of filing of such
documents.

3
<PAGE> 4

Any statement contained herein or in a document incorporated or deemed to
be incorporated by reference herein shall be deemed to be modified or superseded
for purposes of this Prospectus to the extent that a statement contained herein,
therein or in any other subsequently filed document that also is or is deemed to
be incorporated by reference herein modifies or supersedes such statement. Any
statement so modified or superseded shall not be deemed, except as so modified
or superseded, to constitute a part of this Prospectus.

Any person receiving a copy of this Prospectus may obtain from the Company
without charge a copy of any and all documents or part thereof incorporated
herein by reference (other than exhibits and schedules to such documents unless
such exhibits or schedules are specifically incorporated by reference into the
information the Prospectus incorporates), upon written or oral request. Requests
should be directed to Phil Rykhoek, Chief Financial Officer and Corporate
Secretary, Denbury Resources Inc., 17304 Preston Road, Suite 200, Dallas, Texas,
75252, telephone: (972) 673-2000.

4
<PAGE> 5

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by reference to, and
should be read in conjunction with, the more detailed information and
Consolidated Financial Statements included elsewhere in this Prospectus. All
dollar amounts in this Prospectus, unless otherwise indicated, are expressed in
United States dollars and all financial data is presented in accordance with
Canadian generally accepted accounting principles. The December 31, 1997
estimated proved reserve data included throughout this Prospectus have been
prepared by Netherland, Sewell & Associates, Inc. ("Netherland & Sewell"),
independent petroleum engineers. Unless the context otherwise requires, the
terms "Denbury" and the "Company" refer to Denbury Resources Inc., a Canadian
corporation, and its wholly owned subsidiaries, the term "DRI" refers to Denbury
Resources Inc. only, the term "DMI" refers to the wholly owned subsidiary of
DRI, Denbury Management, Inc., a Texas corporation. The term "Transactions"
refers collectively to (i) the Chevron Acquisition (as defined herein) and (ii)
the Offerings and the TPG Purchase and the application of the estimated net
proceeds therefrom. Certain information contained in this summary and elsewhere
in this Prospectus, including information with respect to the Company's plans
and strategy for its business, are forward-looking statements. Prospective
investors should carefully consider the information set forth under "Risk
Factors" for a discussion of important factors that could cause actual results
to differ materially from the forward-looking statements contained in this
Prospectus. Certain oil and gas industry terms used herein are defined in the
Glossary included elsewhere in this Prospectus. Unless otherwise indicated
herein, the information contained in this Prospectus assumes that the
Underwriters' over-allotment option will not be exercised.

THE COMPANY

OVERVIEW

Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. The Company believes the Gulf Coast
represents one of the most attractive regions in North America given the
region's prolific production history, complex geology (with multiple producing
horizons) and the opportunities that have been created by advanced technologies
such as 3-D seismic and various drilling, completion and recovery techniques. As
of December 31, 1997, the Company had proved reserves of 52.0 MMBbls and 77.2
Bcf or 64.9 MMBOE, including 27.6 MMBOE attributable to the Chevron Acquisition.
At such date, the PV10 Value of these reserves was $361.3 million, of which
$276.5 million was attributable to proved developed reserves. Denbury operates
wells comprising approximately 83% of its PV10 Value. The eight largest fields
in which the Company has an interest constitute approximately 82% of its
estimated proved reserves and, within these eight fields, Denbury owns an
average working interest of 91%.

Over the last four years, the Company has achieved rapid growth in proved
reserves, production and cash flow by concentrating on the acquisition of
properties which it believes have significant upside potential and through the
efficient development, enhancement and operation of its properties. For the
four-year period ended December 31, 1997, the Company increased its proved
reserves at a compound annual growth rate of 83%, from 5.8 MMBOE to 64.9 MMBOE.
Over the four-year period ended December 31, 1996, the Company also increased
its average net daily production at a compound annual growth rate of 90%, from
1,193 BOE/d to 8,167 BOE/d, with a further increase to 14,195 BOE/d for the
third quarter of 1997. For the same four-year period, EBITDA increased at a
compound annual growth rate of 126%, from $3.0 million to $34.9 million. EBITDA
for the twelve months ended September 30, 1997 was $51.9 million.

Since 1993, when the Company began to focus its operations exclusively in
the United States, through December 31, 1995, the Company spent a total of $43.4
million on acquisitions. In May 1996, the Company acquired properties in its
core areas of Mississippi and Louisiana from Amerada Hess Corporation ("Amerada
Hess") for approximately $37.2 million (the "Hess Acquisition"). As of June 30,
1996, these acquired properties were producing approximately 2,945 BOE/d and had
proved reserves of approximately 5.9 MMBOE. Since that date, the Company's
extensive development and exploitation on these properties has resulted in an
82% increase in their production to 5,373 BOE/d for the third quarter of 1997
and a 141% increase in their proved reserves to 14.2 MMBOE as of December 31,
1997.
5
<PAGE> 6

On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, which is adjacent to the Company's other primary oil properties in
Mississippi, from Chevron U.S.A. Inc. ("Chevron") for approximately $202.0
million (the "Chevron Acquisition"). These properties are located approximately
nine miles from the Eucutta Field, the property with the highest PV10 Value of
those acquired by the Company in the Hess Acquisition. The estimated proved
reserves as of December 31, 1997 for the Chevron Acquisition properties are
approximately 27.6 MMBOE (43% of the Company's total proved reserves at December
31,1997), with average net daily production of approximately 2,940 BOE/d for the
third quarter of 1997. As a result of the significant amount of future
development and exploitation to be performed on these properties and the
increase in future reserves and production that the Company expects to result
from such development and exploitation, the Company has attributed approximately
$75.0 million of the purchase price to unevaluated properties. The Company
believes that the properties acquired in the Chevron Acquisition provide
exploitation opportunities similar to those of the Mississippi properties
acquired in the Hess Acquisition. The Company's estimated 1998 development
budget for the Heidelberg Field is approximately $30.0 million. See
"-- Acquisition of Chevron Properties."

BUSINESS STRATEGY

The Company seeks to: (i) achieve attractive returns on capital through
prudent acquisitions, development and exploratory drilling and efficient
operations; (ii) maintain a conservative balance sheet to preserve maximum
financial and operational flexibility; and (iii) create strong employee
incentives through equity ownership. The Company believes that its growth to
date in proved reserves, production and cash flow is a direct result of its
adherence to the following fundamental principles which are at the core of the
Company's long-term growth strategy:

REGIONAL FOCUS. The Company intends to continue the regional focus of its
operations. By focusing its efforts in the Gulf Coast region, primarily
Louisiana and Mississippi, the Company has been able to accumulate substantial
geological and reservoir data and operating experience which it believes
provides it with significant competitive advantages. For example, the Company
believes it is better able to identify, evaluate and negotiate potential
acquisitions, and develop and operate its properties in an efficient and low-
cost manner. The Company believes the Gulf Coast represents one of the most
attractive regions in North America given the region's prolific production
history, complex geology (with multiple producing horizons) and the
opportunities that have been created by advanced technologies such as 3-D
seismic and various drilling, completion and recovery techniques. Moreover,
because of the region's proximity to major pipeline networks serving important
northeastern U.S. markets, the Company typically realizes natural gas prices in
excess of those realized in many other producing regions.

DISCIPLINED ACQUISITION STRATEGY. The Company intends to continue to
acquire properties where it believes significant additional value can be
created. Such properties are typically characterized by: (i) long production
histories; (ii) complex geological formations with multiple producing horizons
and substantial exploitation potential; (iii) a history of limited operational
focus and capital investment, often due to their relatively small size and
limited strategic importance to the previous owner; and (iv) the potential for
the Company to gain control of operations. The Company believes that due to
continuing rationalization of properties, primarily by major integrated and
independent energy companies, future acquisition opportunities should continue
to be available. In addition, the Company seeks to maintain a well-balanced
portfolio of oil and natural gas development, exploitation and exploration
projects in order to minimize the overall risk profile of its investment
opportunities while still providing significant upside potential. The recent
Hess and Chevron Acquisitions are examples of the types of opportunities the
Company seeks.

acquisitions available in competitive situations. The consolidation of ownership
allows the Company to: (i) enhance the effectiveness of its technical staff by
concentrating on relatively few wells; (ii) increase production while adding
virtually no additional personnel; and (iii) increase ownership in a property so
that the potential benefits of value enhancement activities justify the
allocation of Company resources.

EXPLOITATION OF PROPERTIES. The Company intends to maximize the value of
its properties through a combination of increasing production, increasing
recoverable reserves or reducing operating costs. During 1997, the Company's
primary methodology for achieving these objectives was the use of horizontal
drilling, which it also intends to emphasize in 1998. Horizontal drilling has
historically produced oil at faster rates and with lower operating costs on a
BOE basis than traditional vertical drilling. The Company also utilizes a
variety of other techniques to maximize property values, including: (i)
undertaking surface improvements such as rationalizing, upgrading or redesigning
production facilities; (ii) making downhole improvements such as resizing
downhole pumps or reperforating existing production zones; (iii) reworking
existing wells into new production zones with additional potential; and (iv)
utilizing exploratory drilling, which is frequently based on various advanced
technologies such as 3-D seismic.

EXPERIENCED AND INCENTIVIZED PERSONNEL. The Company intends to maintain a
highly competitive team of experienced and technically proficient employees and
motivate them through a positive work environment and stock ownership in the
Company. The Company's 29 geological and engineering professionals have an
average of over 15 years of experience in the Gulf Coast region. The Company
believes that employee ownership, which is encouraged through the Company's
stock option and stock purchase plans, is essential for attracting, retaining
and motivating quality personnel. As of January 1, 1998, approximately 86% of
the Company's employees were participating in the Company's stock purchase plan.
The Company believes that all employees are important to the success of the
Company and as such grants bonuses and stock options to both management and
employees on a basis roughly proportional to salaries.

ACQUISITION OF CHEVRON PROPERTIES

On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202.0
million. The Chevron Acquisition represents the largest acquisition by the
Company to date. The Heidelberg Field is adjacent to the Company's other primary
oil properties in Mississippi and includes 122 producing wells, 96 of which the
Company will operate. The Company purchased an average working interest of 94%
and an average net revenue interest of 81% in these 96 wells, which wells
account for approximately 99% of the field's average net daily production. The
average net daily production from these properties during the third quarter of
1997 was approximately 2,840 Bbls/d and 600 Mcf/d.

The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75 million of the purchase price to unevaluated
properties.

The Company has identified several potential development projects during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 15 wells and recompleting 30
wells in new zones. In addition, the Company has identified over 40 potential
drilling locations in addition to other potential secondary and tertiary
recovery projects. Horizontal wells drilled by the Company in 1997 at nearby
Davis, Quitman and Eucutta Fields improved daily production rates significantly
as compared to vertical wells drilled in the same fields. Consequently, the
Company anticipates that 30 of the 40 proposed future wells in the Heidelberg
Field will be horizontal wells. The Company's total 1998 development budget for
the Heidelberg Field is approximately $30.0 million.

TPG PURCHASE

In December 1995, the Texas Pacific Group initially invested in the Company
through a $40.0 million private placement of securities followed by a $9.6
million purchase of Common Shares in October 1996. TPG
7
<PAGE> 8

currently owns approximately 40% of the outstanding Common Shares. In connection
with the Offerings, TPG is purchasing an additional 313,400 Common Shares (the
"TPG Purchase"). See "Interests of Management in Certain Transactions." After
giving effect to the Equity Offering and the TPG Purchase, TPG will own
approximately 34% of the outstanding Common Shares.

TPG was founded by David Bonderman, James G. Coulter and William S. Price
III in 1993 to pursue private and public investment opportunities. The
principals of TPG operate limited partnerships with committed capital of over
$3.2 billion. TPG has several investments in its portfolio, including America
West Airlines, Beringer Wine Estates, Belden & Blake Corporation, Continental
Airlines, Del Monte Foods, Ducati Motor, Favorite Brands International, J. Crew
Group Inc., Paradyne, St. Joe Communications and Virgin Cinemas.

THE EQUITY OFFERING

Common Shares offered
by DRI................... 4,557,200 shares(a)

Common Shares to be
outstanding after the
Equity Offering.......... 25,885,783 shares(b)

Concurrent Debt Offering... Concurrently with the Equity Offering, DMI is
offering $125.0 million aggregate principal amount
of its 9% Senior Subordinated Notes Due 2008 by a
separate prospectus. The closing of the Equity
Offering is not conditioned on the closing of the
Debt Offering.

Use of Proceeds............ The net proceeds from the Equity Offering, together
with the net proceeds from the Debt Offering and
the TPG Purchase, will be used to reduce the
Company's outstanding indebtedness under the Credit
Facility incurred primarily in connection with the
Chevron Acquisition. Following such repayment, the
Company will continue to have borrowing
availability under the Credit Facility to fund
future acquisitions, development activities and
working capital. See "Use of Proceeds."

New York Stock Exchange and
The Toronto Stock
Exchange symbol.......... DNR
- ---------------

(a) Excludes 313,400 Common Shares to be purchased by TPG in the TPG Purchase.

(b) Includes 21,015,183 Common Shares outstanding as of February 19, 1998 and
313,400 Common Shares to be purchased by TPG in the TPG Purchase. This total
does not include 2,043,753 shares issuable pursuant to outstanding warrants
and stock options, of which 466,372 were exercisable as of February 19,
1998.

RISK FACTORS

Prior to making an investment decision, prospective investors should
consider carefully, together with other information contained in this
Prospectus, the risk factors discussed under the caption "Risk Factors" herein.

8
<PAGE> 9

SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

The summary historical consolidated financial data of the Company set forth
below as of and for the years ended December 31, 1994, 1995 and 1996 have been
derived from the audited consolidated financial statements of the Company. The
summary historical consolidated financial data for the nine-month periods ended
September 30, 1996 and 1997, and as of September 30, 1997, have been derived
from unaudited consolidated financial statements of the Company which, in
management's opinion include all adjustments (consisting of only normal
recurring adjustments) necessary to present fairly the results for such periods.
The operating results for such periods are not necessarily indicative of the
operating results to be expected for a full fiscal year. The summary unaudited
pro forma consolidated financial data for the Company set forth below have been
derived from the Pro Forma Financial Statements (as defined herein) included
elsewhere in this Prospectus. The summary historical and pro forma consolidated
financial data are qualified in their entirety by, and should be read in
conjunction with, "Unaudited Pro Forma Consolidated Financial Information,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Company's consolidated financial statements included
elsewhere in this Prospectus (the "Consolidated Financial Statements").

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------- ----------------------------
PRO PRO
FORMA FORMA
1994 1995 1996 1996(a) 1996 1997 1997(a)
------- ------- ------- -------- ------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil, natural gas and related
product sales............... $12,692 $20,032 $52,880 $ 76,542 $34,709 $60,083 $ 74,117
Interest income............... 23 77 769 769 425 986 986
------- ------- ------- -------- ------- ------- --------
Total revenues........... 12,715 20,109 53,649 77,311 35,134 61,069 75,103
------- ------- ------- -------- ------- ------- --------
Expenses:
Production.................... 4,309 6,789 13,495 20,145 9,197 15,737 20,974
General and administrative.... 1,105 1,832 4,267 4,954 2,825 4,535 5,049
Interest...................... 1,146 2,085 1,993 13,809 1,530 387 9,193
Imputed preferred dividends... -- -- 1,281 1,281 1,153 -- --
Loss on early extinguishment
of debt..................... -- 200 440 440 440 -- --
Depletion and depreciation.... 4,209 8,022 17,904 24,601 12,557 23,224 27,166
Franchise taxes............... 65 100 213 213 160 308 308
------- ------- ------- -------- ------- ------- --------
Total expenses........... 10,834 19,028 39,593 65,443 27,862 44,191 62,690
------- ------- ------- -------- ------- ------- --------
Income before income taxes...... 1,881 1,081 14,056 11,868 7,272 16,878 12,413
Provision for federal income
taxes......................... (718) (367) (5,312) (4,502) (2,932) (6,245) (4,593)
------- ------- ------- -------- ------- ------- --------
Net income...................... $ 1,163 $ 714 $ 8,744 $ 7,366 $ 4,340 $10,633 $ 7,820
======= ======= ======= ======== ======= ======= ========
Net income per common share
Primary....................... $ 0.19 $ 0.10 $ 0.67 $ 0.41 $ 0.37 $ 0.53 $ 0.31
Fully diluted................. 0.19 0.10 0.62 0.40 0.36 0.50 0.31
Weighted average common shares
outstanding................... 6,240 6,870 13,104 17,975 11,616 20,175 25,046
OTHER FINANCIAL DATA:
Operating cash flow(b).......... $ 6,185 $ 9,394 $34,140 $ 38,649 $21,767 $40,166 $ 39,643
Capital expenditures............ 16,903 28,524 86,857 288,857 73,320 70,773 272,773
EBITDA(c)....................... 7,213 11,311 34,905 51,230 22,527 39,503 47,786
SELECTED RATIOS:
Ratio of earnings to fixed
charges(d).................... 2.6x 1.5x 4.4x 1.7x 3.1x 34.9x 2.3x
Ratio of EBITDA to interest
expense....................... 6.3 5.4 17.5 3.7 14.7 102.1 5.2
Ratio of long-term debt to
EBITDA........................ 2.3 0.3 0.1 2.5 1.6(e) 0.4(e) 2.3(e)
</TABLE>

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<PAGE> 10

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30,
1997
AS OF DECEMBER 31, -------------------
---------------------------- PRO
1994 1995 1996 ACTUAL FORMA(a)
------- ------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)......................... $(1,620) $ 6,862 $ 12,482 $ 2,899 $ 2,899
Total assets...................................... 48,964 77,641 166,505 210,424 415,634
Long-term debt, net of current maturities......... 16,536 3,474 125 20,005 148,105
Convertible preferred stock....................... -- 15,000 -- -- --
Shareholders' equity.............................. 25,962 53,501 142,504 155,558 232,668
</TABLE>

- ---------------

(a) Gives effect to the Transactions as if the Transactions had been consummated
as of the beginning of the period presented. See "Unaudited Pro Forma
Consolidated Financial Information."

(b) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.

(c) EBITDA represents earnings before interest income, interest expense, income
taxes, depletion and depreciation, imputed preferred dividends and losses on
early extinguishment of debt. The Company has included information
concerning EBITDA because it believes that EBITDA is used by certain
investors as one measure of an issuer's historical ability to service its
debt. EBITDA is not a measurement determined in accordance with generally
accepted accounting principles and should not be considered in isolation or
as a substitute for measures of performance prepared in accordance with
generally accepted accounting principles.

(d) For purposes of determining the ratio of earnings to fixed charges, earnings
are defined as earnings from continuing operations before income taxes, plus
fixed charges. Fixed charges consist of interest expense, amortization of
debt expense, and imputed preferred stock dividends.

(e) EBITDA used to calculate the ratio of long-term debt to EBITDA for these
periods has been annualized.

10
<PAGE> 11

SUMMARY OIL AND NATURAL GAS RESERVE DATA

The following table summarizes the estimates of the Company's net proved
oil and natural gas reserves as of the dates indicated and the present value
attributable to the reserves at such dates. The proved reserve and present value
data as of December 31, 1995, 1996 and 1997 have been prepared by Netherland &
Sewell, independent petroleum engineers. A summary of the Netherland & Sewell
report as of December 31, 1997 is included as Annex A to this Prospectus. See
"Risk Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves,"
"Business and Properties -- Oil and Natural Gas Operations," and Note 11 to the
Consolidated Financial Statements.

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------
1995 1996 1997
------- -------- --------
<S> <C> <C> <C>
PROVED RESERVES:
Oil (MBbls)............................................... 6,292 15,052 52,018
Natural Gas (MMcf)........................................ 48,116 74,102 77,191
Oil Equivalent (MBOE)..................................... 14,311 27,403 64,883
Proved developed as a percent of total proved reserves.... 78% 84% 66%
PRESENT VALUES:
PV10 Value (before income taxes, in thousands)............ $96,965 $316,098(d) $361,329(e)
Standardized measure of discounted estimated future net
cash flow after net
income taxes (in thousands)............................. 81,164 241,872 336,755
REPRESENTATIVE OIL AND GAS PRICES:(a)
West Texas Intermediate (per Bbl)......................... $ 18.00 $ 23.39 $ 16.18
NYMEX Henry Hub (per MMBtu)............................... 2.24 3.90 2.58
OTHER RESERVE DATA:
Reserve replacement percent(b)............................ 300% 500% 844%
Reserve to production ratio (years)(c).................... 9.3 9.2 10.9(f)
</TABLE>

- ---------------

(a) The oil prices as of each respective year-end were based on West Texas
Intermediate ("WTI") posted prices per barrel and NYMEX Henry Hub ("NYMEX")
prices per MMBtu, with these representative prices adjusted by field to
arrive at the appropriate corporate net price.

(b) Equals current period reserve additions through acquisition of reserves,
extensions and discoveries, and revisions of prior estimates divided by the
production for such period.

(d) For comparative purposes, the Company also prepared a reserve report as of
December 31, 1996 using a 1996 WTI price of $21.00 per Bbl and a NYMEX price
of $2.40 per MMBtu, with these prices also adjusted by field. The PV10 Value
in this report was $213.7 million with 27.0 MMBOE of proved reserves. For
the nine months ended September 30, 1997, the average WTI price was
approximately $18.90 per Bbl and the average NYMEX price was approximately
$2.39 per MMBtu.

(e) For comparative purposes, the Company also prepared a reserve report as of
December 31, 1997 using the prices used in the December 31, 1996 reserve
report. The PV10 Value in this report was $633.4 million with 67.8 MMBOE of
proved reserves. Of this PV10 Value, $206.7 million was attributable to the
Chevron Acquisition, as opposed to its PV10 Value of $109.4 million using
December 31, 1997 prices.

(f) Calculated by dividing year-end proved reserves by the pro forma annualized
production for the nine months ended September 30, 1997.

SUMMARY OPERATING DATA

The following table sets forth summary data with respect to the production
and sales of oil and natural gas by the Company for the periods indicated.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------- -----------------------------
PRO FORMA PRO FORMA
1994 1995 1996 1996(A) 1996 1997 1997(A)
------ ------- ------- --------- ------- ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
AVERAGE NET DAILY PRODUCTION VOLUMES:
Oil (Bbls)................................ 1,340 1,995 4,099 7,520 3,529 7,615 10,522
Natural gas (Mcf)......................... 9,113 13,271 24,406 25,076 23,867 34,061 34,648
Oil equivalent (BOE) ..................... 2,859 4,207 8,167 11,699 7,507 13,292 16,297
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)............................. $13.84 $ 14.90 $ 18.98 $ 18.75 $ 18.05 $ 17.53 $ 17.45
Natural gas (per Mcf)..................... 1.78 1.90 2.73 2.72 2.64 2.54 2.54
PER BOE DATA:
Revenue................................... $12.17 $ 13.05 $ 17.69 $ 17.88 $ 16.87 $ 16.56 $ 16.65
Production expenses....................... (4.13) (4.42) (4.51) (4.70) (4.47) (4.34) (4.71)
------ ------- ------- ------- ------- ------- -------
Production netback........................ 8.04 8.63 13.18 13.18 12.40 12.22 11.94
General and administrative................ (1.12) (1.25) (1.50) (1.21) (1.45) (1.33) (1.20)
Interest, net............................. (0.99) (1.26) (0.26) (2.94) (0.37) 0.18 (1.83)
------ ------- ------- ------- ------- ------- -------
Operating cash flow(b).................... $ 5.93 $ 6.12 $ 11.42 $ 9.03 $ 10.58 $ 11.07 $ 8.91
====== ======= ======= ======= ======= ======= =======
</TABLE>

- ---------------

(a) Adjusted to give effect to the Transactions as if the Transactions had been
completed as of the beginning of the periods presented.

(b) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
11
<PAGE> 12

RISK FACTORS

Prospective purchasers of the securities offered hereby should carefully
consider the following factors in addition to the other information in this
Prospectus. See "Forward-Looking Statements."

SUBSTANTIAL CAPITAL REQUIREMENTS

In the future, the Company will require additional funds to develop,
maintain and acquire additional interests in existing or newly acquired
properties. During the last three years, the Company's total capital
expenditures, including acquisitions, have averaged significantly more than its
cash flow from operations. The Company made capital expenditures of $28.5
million, $86.9 million and $272.8 million in the years ended December 31, 1995
and 1996, and the nine-month period ended September 30, 1997 (including the pro
forma effect of the Chevron Acquisition), respectively. Historically, the
Company has funded these expenditures principally through internally-generated
cash flows, bank debt and the issuance of equity. The Company intends to use the
net proceeds from the Offerings and the TPG Purchase to substantially reduce its
outstanding bank debt. As of September 30, 1997, after giving pro forma effect
to the Transactions, the Company would have had $141.9 million ($123.9 million
as of December 31, 1997) available under its Credit Facility. See "Use of
Proceeds." The borrowing base on the Credit Facility will be redetermined semi-
annually by the lenders thereunder in their sole discretion and there can be no
assurance that the borrowing base will be maintained at its present level. If
the Company's borrowing base under the Credit Facility is decreased, the
Company's ability to obtain the funds necessary to carry out its business
strategy may be limited. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Restated Credit Facility" and
"Description of Certain Indebtedness."

Although the Company carefully monitors its capital requirements and plans
its expenditures accordingly, and believes that it will be able to meet all of
its obligations in the future, there can be no assurance that additional capital
will always be available to the Company in the future or that it will be
available on terms that are acceptable to the Company. Numerous factors affect
the cost and availability of capital, including market conditions, the Company's
results of operations and the rate of the Company's drilling successes. Should
outside capital resources be limited, the rate of the Company's growth would
substantially decline, and there can also be no assurance that the Company would
be able to continue to increase its oil and natural gas production or reserves.

PRICE FLUCTUATIONS AND MARKETS

The Company's revenue, profitability and future rate of growth are
dependent upon the price of, and demand for, oil, natural gas and natural gas
liquids. Historically, the markets for oil and natural gas have been volatile
and are likely to continue to be volatile in the future. The prices for oil and
natural gas are subject to wide fluctuations in response to relatively minor
changes in the supply of and demand for oil and natural gas, market uncertainty
and a variety of additional factors that are beyond the control of the Company.
These factors include the level of consumer product demand, weather conditions,
domestic and foreign governmental relations, governmental regulations and taxes,
the price and availability of alternative fuels, political conditions in the
Middle East and other petroleum producing areas, the foreign supply of oil and
natural gas, the price of foreign imports and overall economic conditions. These
factors and the volatility of the energy markets make it extremely difficult to
predict future oil and natural gas price movements with any certainty. Declines
in oil and natural gas prices would not only reduce revenue, but could reduce
the amount of oil and natural gas that can be produced economically by the
Company and, as a result, could have a material adverse effect on the Company's
financial condition, results of operations and reserves. In an effort to
minimize the effect of price volatility, the Company has from time to time
entered into hedging arrangements. The Company currently does not have any
financial hedging contracts in place, although it may enter into such contracts
in the future.

The availability of a ready market for the Company's oil and natural gas
production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to, and the capacity
of, oil and natural gas gathering systems, pipelines or trucking and terminal
facilities. Wells may be temporarily shut-in for lack of a market, or due to the
inadequacy or unavailability of pipeline or
12
<PAGE> 13

gathering system capacity. If any of these market factors were to dramatically
change, the impact on the Company's financial condition would be substantial.

ACQUISITION RISKS

The Company's rapid growth in recent years has been attributable in
significant part to acquisitions of producing properties. After the consummation
of the Offerings, the Company expects to continue to evaluate and, where
appropriate, pursue acquisition opportunities. There can be no assurance that
suitable acquisition opportunities will be identified in the future, or that
they will be integrated successfully into the Company's operations or be
successful in achieving desired profitability objectives. In addition, the
Company competes against other companies for acquisitions, and there can be no
assurance that the Company will be successful in the acquisition of any material
property interests.

The successful acquisition of producing properties requires an assessment
of recoverable reserves, exploration potential, future oil and natural gas
prices, operating costs, potential environmental and other liabilities and other
factors beyond the Company's control. In connection with such an assessment, the
Company performs a review of the subject properties that it believes to be
generally consistent with industry practices. Nonetheless, the resulting
assessments are necessarily inexact and their accuracy inherently uncertain, and
such a review may not accurately assess a property's value or reveal all
existing or potential problems, nor will it necessarily permit a buyer to become
sufficiently familiar with the property to fully assess its merits and
deficiencies. Inspections may not always be performed on every platform or well,
and structural and environmental problems are not necessarily observable even
when an inspection is undertaken.

Additionally, significant acquisitions can change the nature of the
operations and business of the Company depending upon the character of the
acquired properties, which may have substantially different operating and
geological characteristics or geographic location than existing properties.
While it is the Company's current intention to continue to concentrate on
acquiring producing properties with development and exploration potential
located in the Gulf Coast region, there can be no assurance that the Company
will not pursue acquisitions or properties located in other geographic regions.
To the extent that such acquired properties are substantially different than the
Company's Gulf Coast properties, the Company's ability to efficiently realize
the economic benefits of such transactions may be limited.

DRILLING AND OPERATING RISKS

Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be discovered. There can be no assurance
that new wells drilled by the Company will be productive or that the Company
will recover all or any portion of its investment in such wells. Drilling for
oil and natural gas may involve unprofitable efforts, not only from dry wells
but also from wells that are productive but do not produce sufficient net
revenues to return a profit after deducting drilling, operating and other costs.
The cost of drilling, completing and operating wells is often uncertain. The
Company's drilling operations may be curtailed, delayed or canceled as a result
of numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.

The Company's operations are subject to all of the risks normally incident
to the operation and development of oil and natural gas properties and the
drilling of oil and natural gas wells, including encountering unexpected
formations or pressures, blow-outs, the release of contaminants into the
environment, cratering and fires, all of which could result in personal
injuries, loss of life, pollution damage, damage to property of the Company and
others, including the inability to control such risk when wells are being
drilled by third party contractors and the imposition of fines and penalties
pursuant to environmental legislation. See "-- Governmental and Environmental
Regulation" and "Business and Properties -- Legal Proceedings." The Company is
not fully insured against all of these risks, nor are all such risks insurable.
Although the Company maintains liability insurance in an amount which it
considers adequate, the nature of these risks is such that liabilities could
exceed policy limits, or, as in the case of environmental fines and penalties,
be uninsurable, in which event the Company could incur significant costs that
could have a material adverse effect upon its
13
<PAGE> 14

financial condition. The Company believes that it has proper procedures in place
and that its operating staff carries out their work in a manner designed to
mitigate these risks. There can be no assurance, however, that such procedures
will be effective in deterring these costs.

The Company has focused its oil and natural gas operations in certain key
areas and currently receives approximately 80% of its production from 11 fields.
Any interruption of operations in these key areas could materially adversely
affect the profitability of the Company. In the majority of the Company's
Mississippi fields, significant amounts of saltwater are produced which require
disposal. Currently, the Company is able to dispose of such saltwater
economically, but should it be unable to do so in the future, production from
these fields would become uneconomical.

NEED TO REPLACE RESERVES

The Company's future success depends on its ability to find, develop or
acquire additional oil and natural gas reserves that are recoverable on an
attractive economic basis. Unless the Company successfully replaces the reserves
that it produces (through development, exploration or acquisitions), the
Company's proved reserves will decline. Furthermore, approximately 21% of the
Company's proved developed reserves at December 31, 1997 are located in the
lower Gulf Coast geosyncline in southern Louisiana, which is characterized by
relatively rapid decline rates. Approximately 60% of the Company's total proved
reserves at December 31, 1997 were either proved undeveloped or proved developed
non-producing. Recovery of such reserves will require significant capital
expenditures and successful drilling operations. There can be no assurance that
the Company will continue to be successful in its effort to develop or replace
its proved reserves on terms economically beneficial to the Company, if at all.

UNCERTAINTY OF ESTIMATES OF OIL AND NATURAL GAS RESERVES

Estimates of the Company's proved developed oil and natural gas reserves
and future net revenues therefrom appearing elsewhere herein are based on
reserve reports prepared by independent petroleum engineers. There are numerous
uncertainties inherent in estimating the quantity of proved reserves, including
many factors which are beyond the Company's control. The estimates contained in
this Prospectus are based on several assumptions, all of which are speculative
to a certain degree. Actual future production, revenues, taxes, operating
expenses, development expenditures and quantities of recoverable oil and natural
gas reserves could vary substantially from those assumed in the estimates and
any significant variance in these assumptions could materially affect the
estimated quantity of reserves. The estimation of reserves requires substantial
judgment on the part of the petroleum engineers, resulting in imprecise
determinations, particularly with respect to new discoveries. Different reserve
engineers may make different estimates of reserve quantities and revenues
attributable thereto based on the same data. The accuracy of any reserve
estimate depends on the quality of available data, as well as engineering and
geological interpretation and judgment. The Company's reserves are primarily
water-drive reservoirs which can increase the uncertainty of the estimates that
have been prepared. Results of drilling, testing and production or price changes
subsequent to the date of the estimate may result in revisions to such
estimates. The estimates of future net revenues reflect oil and natural gas
prices as of the date of estimation, without escalation. There can be no
assurance, however, that such prices will be realized or that the estimated
production volumes will be produced during the periods indicated. Future
performance that deviates significantly from that found in the reserve reports
could have a material adverse effect on the Company.

EFFECTS OF LEVERAGE AND RESTRICTIVE DEBT COVENANTS

As of September 30, 1997, after giving pro forma effect to the
Transactions, the Company would have had total consolidated indebtedness of
approximately $148.1 million and a debt-to-capitalization ratio of 38.9%. In
addition, the Company may incur additional indebtedness in the future under the
Credit Facility in connection with its acquisition, development, exploitation
and exploration of oil and natural gas producing properties. As of September 30,
1997, after giving pro forma effect to the Transactions, the Company would have
had $141.9 million ($123.9 million as of December 31, 1997) of availability
under the Credit Facility.

14
<PAGE> 15

The degree to which the Company will be leveraged following the
Transactions could have important consequences to holders of the Common Shares,
including but not limited to, the following: (i) a substantial portion of the
Company's cash flow from operations will be dedicated to debt service and will
not be available for other purposes; (ii) the Company's ability to obtain
additional financing in the future could be limited; (iii) certain of the
Company's borrowings are at variable rates of interest, which could result in
higher interest expense in the event of increases in interest rates; (iv) the
Company may be more vulnerable to downturns in its business or in the general
economy and may be restricted from making acquisitions, introducing new
technologies or exploiting business opportunities; and (v) the Indenture and the
Credit Agreement (as defined herein) contain financial and restrictive covenants
that limit the ability of the Company to, among other things, borrow additional
funds, dispose of assets or pay cash dividends. Failure by the Company to comply
with such covenants could result in an event of default under such debt
instruments which, if not cured or waived, could have a material adverse effect
on the Company. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Restated Credit Facility" and "Description of
Certain Indebtedness."

If the Company is unable to generate sufficient cash flow or otherwise
obtain funds necessary to make required payments on its indebtedness or, if the
Company otherwise fails to comply with the various covenants in such
indebtedness (including covenants in the Credit Facility), it would be in
default under the terms thereof, which would permit the holders of such
indebtedness to accelerate the maturity of such indebtedness and could cause
defaults under other indebtedness of the Company, including the Notes, or result
in its bankruptcy. The ability of the Company to meet its obligations will be
dependent upon the future performance of the Company, which will be subject to
prevailing economic conditions and to financial, business and other factors,
including factors beyond the control of the Company.

CONTROLLING SHAREHOLDER

In December 1995, the Company completed a $40.0 million private placement
of securities to TPG consisting of Convertible Preferred (as defined herein),
Common Shares and warrants to purchase Common Shares. After giving pro forma
effect to the Equity Offering and the TPG Purchase, TPG will own approximately
34% of the Common Shares outstanding. TPG is entitled to nominate a minimum of
three of the seven members of the Company's Board of Directors so long as TPG
maintains certain ownership levels. In addition, certain transactions, including
changes to the number of board members, amendments to the Company's Articles of
Continuance, certain issuances of debt, certain acquisitions and dispositions,
and most issuances of equity, require the two-thirds majority of the Board of
Directors, which cannot be obtained without the approval of at least one TPG
nominee. Additionally, so long as TPG's equity interest is 20% or greater, it
has the right (which has been partially waived for the Equity Offering), but not
the obligation, to maintain its pro rata ownership interest in the equity
securities of the Company in the event the Company issues any additional equity
securities or securities convertible into Common Shares by purchasing additional
securities on the same terms and conditions. At the request of the New York
Stock Exchange, the Company has agreed to make the extension of this right
subject to shareholder ratification every five years with the first vote on the
matter expected to be at the Company's annual meeting in the year 2000. See
"Interests of Management in Certain Transactions."

DEPENDENCE ON KEY PERSONNEL

The Company believes that its continued success will depend to a
significant extent upon the abilities and continued efforts of its Board of
Directors and its senior management, particularly Gareth Roberts, its Chief
Executive Officer and President. The Company does not have any employment
agreements and does not maintain any key man life insurance policies. The loss
of the services of any of its key personnel could have a material adverse effect
on the Company's results of operations. The success of the Company will also
depend, in part, upon the Company's ability to find, hire and retain additional
key management personnel who are also being sought by other businesses. The
inability to find, hire and retain such personnel could have a material adverse
effect upon the Company's results of operations. See "Management."

15
<PAGE> 16

SHARES ELIGIBLE FOR FUTURE SALE

As of December 31, 1997, after giving pro forma effect to the Equity
Offering and the TPG Purchase, the Company would have had 25,257,283 Common
Shares outstanding (25,940,863 Common Shares assuming exercise of the
Underwriters' over-allotment option in full). The Common Shares sold in the
Equity Offering will be freely tradeable without restrictions or further
registration under the Securities Act of 1933, as amended (the "Securities
Act"). All of the Common Shares beneficially owned by TPG as of the close of the
Equity Offering and the TPG Purchase will be "restricted" securities within the
meaning of the Securities Act as a result of TPG being deemed an "affiliate" of
the Company under such act. The Company believes that such "restricted" Common
Shares are eligible for sale on the open market pursuant to Rule 144 under the
Securities Act from time to time. In connection with the Equity Offering and the
TPG Purchase, the Company, all of its directors and executive officers and TPG
have agreed not to sell or otherwise dispose of any Common Shares, including any
securities exercisable for or convertible into Common Shares, for a period of
120 days from the date of this Prospectus, without the prior written consent of
Morgan Stanley & Co. Incorporated. See "Underwriters."

In addition, the Company has granted certain registration rights to TPG.
Until December 21, 2000, TPG has the right, subject to certain conditions, to
demand that its Common Shares be registered under the Securities Act on one
occasion. See "Interests of Management in Certain Transactions" and "Shares
Eligible for Future Sale."

The sale of a substantial number of Common Shares or the availability of a
substantial number of shares for sale may adversely affect the market price of
the Common Shares and could impair the Company's ability to raise additional
capital through the sale of its equity securities.

COMPETITION

The Company operates in a highly competitive industry. The Company competes
with a large number of integrated and independent energy companies for the
acquisition of desirable oil and natural gas properties, as well as for the
equipment and labor required to develop and operate such properties. Many of
these competitors have financial and other resources substantially greater than
those of the Company. See "Business and Properties -- Competition."

The principal resources necessary for the exploration for, and the
acquisition, exploitation, production and sale of, oil and natural gas are
leaseholds under which oil and natural gas reserves may be discovered, drilling
rigs and related equipment to explore for and develop such reserves, capital
assets required for the exploitation and production of the reserves and
knowledgeable personnel to conduct all phases of oil and natural gas operations.
The Company must compete for such resources with major oil companies and
independent operators and also with other industries for certain personnel and
materials. Although the Company believes its current resources are adequate to
preclude any significant disruption of operations in the immediate future, the
continued availability of such materials and resources to the Company cannot be
assured.

GOVERNMENTAL AND ENVIRONMENTAL REGULATION

The production of oil and natural gas is subject to regulation under a wide
range of United States federal and state statutes, rules, orders and
regulations. Federal and state statutes and regulations require permits for
drilling, reworking and recompletion operations, drilling bonds and reports
concerning operations, and these permits are subject to modification, renewal
and revocation by the issuing governmental authority. Most states in which the
Company owns and operates properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment of
wells. Many states also restrict production to the market demand for oil and
natural gas, and several states have indicated interest in revising applicable
regulations in light of the persistent oversupply and low prices for oil and
natural gas production. These regulations may limit the rate at which oil and
natural gas could otherwise be produced from the Company's properties. Some
states have also enacted statutes prescribing ceiling prices for natural gas
sold within the state. See "Business and Properties -- Regulations."
16
<PAGE> 17

Various federal, state and local laws and regulations relating to the
protection of the environment may affect the Company's operations and costs. In
particular, the Company's production operations, its salt water disposal
operations and its use of facilities for treating, processing or otherwise
handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. The majority of the Company's Louisiana activity is
conducted in a marsh environment where environmental regulations are somewhat
greater. Although compliance with these regulations increases the cost of
Company operations, such compliance has not had a material effect on the
Company's capital expenditures, earnings or competitive position. There can be
no assurance, however, that future compliance with these regulations will not
have such a material adverse effect. Environmental regulations have historically
been subject to frequent change by regulatory authorities, and the Company is
unable to predict the ongoing cost of complying with these laws and regulations
or the future impact of such regulations on its operations. There can be no
assurance that present or future regulation will not adversely affect the
Company's exploration, development and production of its oil and natural gas
producing properties. A significant discharge of hydrocarbons into the
environment could, to the extent such event is not insured, subject the Company
to substantial expense. See "Business and Properties -- Regulations."

AUTHORIZATION AND DISCRETIONARY ISSUANCE OF PREFERRED SHARES; ANTI-TAKEOVER
PROVISIONS

DRI's Articles of Continuance authorize the future issuance of an unlimited
number of First Preferred Shares and Second Preferred Shares (collectively, the
"Preferred Shares"), with such designations, rights, privileges, restrictions
and conditions as may be determined from time to time by the Board of Directors.
Accordingly, the Board of Directors is empowered, without shareholder approval,
to issue Preferred Shares with dividend, liquidation, conversion, voting or
other rights that could adversely affect the voting power or other rights of
holders of the Common Shares. The issuance of the Preferred Shares could be
utilized, under certain circumstances, as a method of discouraging, delaying or
preventing a change in control of the Company. Such actions could have the
effect of discouraging bids for the Company, thereby preventing shareholders
from receiving the maximum value for their shares. Although the Company has no
present intention to issue any additional Preferred Shares, there can be no
assurance that the Company will not do so in the future. After giving effect to
the Offerings, no Preferred Shares will be outstanding. See "Interests of
Management in Certain Transactions."

The Investment Canada Act includes provisions that are intended to
encourage persons considering unsolicited tender offers or other unilateral
takeover proposals to negotiate with DRI's Board of Directors rather than pursue
non-negotiated takeover attempts. These provisions apply to DRI and may have a
significant effect on the ability of a shareholder to benefit from certain kinds
of transactions that may be opposed by the incumbent Board of Directors. See
"Description of Capital Stock" and "Canadian Taxation and the Investment Canada
Act."

ABSENCE OF DIVIDENDS

During the last five fiscal years, the Company has not paid any dividends
on its outstanding Common Shares, and the Company does not intend to pay any
dividends in the foreseeable future. DRI is a holding company with no
independent operations. Accordingly, any amounts available for dividends will be
dependent on the prior declaration of dividends by DMI to DRI. In addition, the
terms of the Credit Facility restrict, and the terms of the Notes will restrict,
the payment of dividends by DMI. The Company currently intends to retain its
cash for the continued expansion of its business, including exploration,
development and acquisition activities.

CONCENTRATION OF CUSTOMERS

During 1996, the Company sold 10% or more of its net production of oil and
natural gas to the following purchasers: Natural Gas Clearinghouse (20%); Penn
Union Energy Services (19%); Enron Trading & Transportation (13%); and Hunt
Refining (15%). In addition, the Company is currently selling a majority of its
oil to Hunt Refining under a two-year contract which expires in April 1998 and
is currently receiving a premium to the posted price in this contract. The
Company may not be able to renew this contract in the
17
<PAGE> 18

future or may not be able to obtain terms as favorable as those in the existing
contract. While the Company believes that its relationships with these
purchasers are good, any loss of revenue from these purchasers could have a
material adverse effect on the Company's results of operations.

FORWARD-LOOKING STATEMENTS

The statements contained in this Prospectus that are not historical facts,
including, but not limited to, statements found in the "Prospectus Summary,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business and Properties," are "forward-looking statements," as
that term is defined in Section 21E of the Exchange Act, 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, dispositions, development activities, cost
savings, production efforts and 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 statements are based upon management's current plans,
expectations, estimates and assumptions and are 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 Prospectus, 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.

DEBT OFFERING

Concurrently with the Equity Offering, the Company is offering $125.0
million of 9% Senior Subordinated Notes Due 2008 to the public. The Indenture to
be executed in conjunction with the Debt Offering will contain certain
covenants, including covenants that limit (i) indebtedness, (ii) restricted
payments, (iii) issuances and sale of capital stock of restricted subsidiaries,
(iv) sale/leaseback transactions, (v) transactions with affiliates, (vi) liens,
(vii) asset sales, (viii) dividend and other payment restrictions affecting
restricted subsidiaries and (ix) mergers and consolidations. The closing of the
Equity Offering is not conditioned upon the closing of the Debt Offering;
however, the closing of the Debt Offering is conditioned upon the closing of the
Equity Offering. See "Description of Certain Indebtedness -- Senior Subordinated
Notes."

USE OF PROCEEDS

The net proceeds to the Company from the Equity Offering are estimated to
be approximately $72.1 million ($83.0 million if the Underwriters'
over-allotment option is exercised in full). Concurrently with the Equity
Offering, the Company is offering $125.0 million aggregate principal amount of
9% Senior Subordinated Notes Due 2008 in the Debt Offering. The closing of the
Equity Offering is not conditioned upon the closing of the Debt Offering;
however, the closing of the Debt Offering is conditioned upon the closing of the
Equity Offering.

The Company intends to use the total net proceeds of the Offerings and the
TPG Purchase (estimated to be $198.9 million in the aggregate) to reduce
outstanding borrowings under the Credit Facility. The undrawn balance under the
Credit Facility will then be available for capital expenditures and general
corporate purposes, including the acquisition of additional producing oil and
natural gas properties. As of December 31, 1997, the Credit Facility had an
outstanding balance of $240.0 million and an average interest rate of 7.5% per
18
<PAGE> 19

annum. After the application of the net proceeds from the Offerings and the TPG
Purchase to reduce amounts outstanding under the Credit Facility, the Credit
Facility will consist of a five-year revolving credit facility with a borrowing
base of $165.0 million. The Company borrowed $220.0 million under the Credit
Facility during the fourth quarter of 1997, primarily to fund the Chevron
Acquisition. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Restated Credit Facility," "Business and
Properties -- Acquisitions of Oil and Natural Gas Properties" and "Description
of Certain Indebtedness -- Credit Facility."

PRICE RANGE OF COMMON SHARES

The Common Shares have been listed on the New York Stock Exchange ("NYSE")
since May 8, 1997 and were listed on the Nasdaq National Market ("NASDAQ") from
August 25, 1995 through May 8, 1997. The Common Shares have also been listed on
The Toronto Stock Exchange ("TSE") in Toronto, Canada, since February 14, 1984.
The Common Shares currently trade under the symbol "DNR" on both the NYSE and
TSE. The following table summarizes the high and low last reported sale prices
(adjusted for the one-for-two reverse stock split in October 1996) as reported
by each exchange for each quarterly period during the last two fiscal years and
to date during 1998.

<TABLE>
<CAPTION>
NYSE/NASDAQ TSE
--------------- ---------------
HIGH LOW HIGH LOW
------ ------ ------ ------
(US$) (C$)
<S> <C> <C> <C> <C>
1996
First Quarter................................... $ 7.88 $ 6.26 $10.80 $ 8.30
Second Quarter.................................. 10.62 8.50 14.50 12.00
Third Quarter................................... 13.50 10.00 18.60 12.70
Fourth Quarter.................................. 15.25 12.50 20.95 17.00
1997
First Quarter................................... 16.00 12.00 21.75 16.40
Second Quarter.................................. 17.63 13.13 24.50 18.00
Third Quarter................................... 23.75 16.13 33.00 22.20
Fourth Quarter.................................. 24.63 17.88 33.50 25.50
1998
First Quarter (through February 19, 1998)....... 20.25 16.38 29.00 23.50
</TABLE>

A recent reported last sale price per share for the Common Shares on the
NYSE and the TSE is set forth on the cover page of this Prospectus. As of
December 31, 1997, to the best of the Company's knowledge, there were
approximately 1,200 holders of record of Common Shares.

DIVIDEND POLICY

The Company has not paid any dividends in the last five fiscal years on its
Common Shares and does not intend to pay any dividends on its Common Shares in
the foreseeable future. In the past, the Company has used its available cash
flow to conduct exploration and development activities or to make acquisitions,
and expects to continue to do so in the future. DRI is a holding company with no
independent operations. Accordingly, any amounts available for dividends will be
dependent on the prior declaration of dividends by DMI to DRI. In addition, the
terms of the Credit Facility restrict, and the terms of the Notes will restrict,
the payment of dividends by DMI.

19
<PAGE> 20

CAPITALIZATION

The following table sets forth as of September 30, 1997 (i) the actual
capitalization of the Company, (ii) the capitalization of the Company as
adjusted for the Chevron Acquisition, (iii) the capitalization of the Company as
further adjusted to give effect to the Equity Offering, the TPG Purchase and the
application of the net proceeds therefrom and (iv) the capitalization of the
Company as further adjusted to give effect to the Debt Offering and the
application of the net proceeds therefrom. See "Use of Proceeds." This table
should be read in conjunction with "Unaudited Pro Forma Consolidated Financial
Information," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the Consolidated Financial Statements.

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997
------------------------------------------------------
AS FURTHER
ADJUSTED FOR
AS ADJUSTED THE EQUITY
FOR THE OFFERING AS ADJUSTED
COMPANY CHEVRON AND TPG FOR THE
HISTORICAL ACQUISITION PURCHASE TRANSACTIONS
---------- ----------- ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents....................... $ 2,236 $ 2,236 $ 2,236 $ 2,236
======== ======== ======== ========
Short-term debt:
Credit Facility (a)........................... $ -- $ 47,000 $ -- $ --
-------- -------- -------- --------
Long-term debt:
Credit Facility (a)........................... 20,000 175,000 144,890 23,100
9% Senior Subordinated Notes Due 2008......... -- -- -- 125,000
Other notes payable........................... 5 5 5 5
-------- -------- -------- --------
Total long-term debt.................. 20,005 175,005 144,895 148,105
-------- -------- -------- --------
Shareholders' equity (b):
Common Shares, no par value; unlimited shares
authorized; 20,364,799 outstanding;
25,235,399 outstanding as adjusted for the
Transactions............................... 132,744 132,744 209,854 209,854
Retained earnings............................. 22,814 22,814 22,814 22,814
-------- -------- -------- --------
Total shareholders' equity................. 155,558 155,558 232,668 232,668
-------- -------- -------- --------
Total capitalization.................. $175,563 $377,563 $377,563 $380,773
======== ======== ======== ========
</TABLE>

- ---------------

(a) The Credit Facility was revised and restated in December 1997 in order to
fund the Chevron Acquisition. After repayment of the acquisition tranche and
other borrowings thereunder with the net proceeds from the Offerings and the
TPG Purchase, the Credit Facility will consist of a five year revolving
credit facility with a borrowing base of $165.0 million.

(b) Excludes 1,512,206 outstanding stock options as of September 30, 1997
exercisable at various prices ranging from $5.55 to $17.29 per share with a
weighted average price of $10.69 (of which 395,222 were currently
exercisable), and 700,000 Common Shares reserved for issuance upon exercise
of the two series of Common Share purchase warrants. Also excludes 406,620
stock options that were granted on January 2, 1998, none of which are
currently exercisable.

20
<PAGE> 21

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

The following unaudited pro forma consolidated statements of income for the
year ended December 31, 1996 and the nine months ended September 30, 1997 and
the unaudited pro forma consolidated balance sheet as of September 30, 1997
(collectively, the "Pro Forma Financial Statements") are based on the historical
consolidated financial statements of the Company and the historical financial
statements of the properties acquired by the Company (the "Chevron Properties")
in the Chevron Acquisition, adjusted to give effect to the Transactions.
Additional property acquisitions were made in 1997 that have not been included
in the pro forma adjustments since they are immaterial individually and in the
aggregate. These acquisitions are included in the Company's historical
statements from the date of their respective acquisition.

The Unaudited Pro Forma Consolidated Statement of Income for the year ended
December 31, 1996 gives effect to the Transactions as if they had occurred as of
January 1, 1996, and the Unaudited Pro Forma Consolidated Statement of Income
for the nine months ended September 30, 1997 gives effect to the Transactions as
if they had occurred as of January 1, 1997. The Unaudited Pro Forma Consolidated
Balance Sheet gives effect to the Transactions as if they had occurred as of
September 30, 1997. The pro forma adjustments are described in the accompanying
notes and are based upon available information and certain assumptions that
management believes are reasonable.

The Pro Forma Financial Statements do not purport to represent what the
Company's results of operations or financial condition would actually have been
had the Transactions in fact occurred on such dates or to project the Company's
results of operations or financial condition for any future date or period. The
Pro Forma Financial Statements should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements.

21
<PAGE> 22

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
-----------------------------------------------------------------
HISTORICAL ADJUSTMENTS
------------------------ ------------------------
OFFERINGS
COMPANY CHEVRON CHEVRON AND TPG
HISTORICAL PROPERTIES ACQUISITION PURCHASE PRO FORMA
---------- ---------- ----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and related
product........................ $52,880 $23,662 $ -- $ -- $76,542
Interest and other................ 769 -- -- -- 769
------- ------- -------- ------- -------
Total revenues............ 53,649 23,662 -- -- 77,311
------- ------- -------- ------- -------
Expenses:
Production........................ 13,495 6,650 -- -- 20,145
General and administrative........ 4,267 -- 687(b) -- 4,954
Interest.......................... 1,993 -- 15,716(c) (3,900)(e) 13,809
Imputed preferred dividend........ 1,281 -- -- -- 1,281
Loss on early extinguishment of
debt........................... 440 -- -- -- 440
Depletion and depreciation........ 17,904 -- 6,697(d) -- 24,601
Franchise taxes................... 213 -- -- -- 213
------- ------- -------- ------- -------
Total expenses............ 39,593 6,650 23,100 (3,900) 65,443
------- ------- -------- ------- -------
Income before income taxes.......... 14,056 17,012 (23,100) 3,900 11,868
Provision for income taxes.......... (5,312) (6,294)(a) 8,547(a) (1,443)(a) (4,502)
------- ------- -------- ------- -------
Net income.......................... $ 8,744 $10,718 $(14,553) $ 2,457 $ 7,366
======= ======= ======== ======= =======
Net income per common share
Primary........................... $ 0.67 $ 0.41
Fully diluted..................... 0.62 0.40
Average common shares outstanding... 13,104 17,975
</TABLE>

See Notes to Unaudited Pro Forma Consolidated Financial Information
22
<PAGE> 23

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1997
----------------------------------------------------------------
HISTORICAL ADJUSTMENTS
----------------------- ------------------------
OFFERINGS
COMPANY CHEVRON CHEVRON AND TPG
HISTORICAL PROPERTIES ACQUISITION PURCHASE PRO FORMA
---------- ---------- ----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and related
product........................... $60,083 $14,034 $ -- $ -- $74,117
Interest and other................... 986 -- -- -- 986
------- ------- ------- ------- -------
Total revenues............... 61,069 14,034 -- -- 75,103
------- ------- ------- ------- -------
Expenses:
Production........................... 15,737 5,237 -- -- 20,974
General and administrative........... 4,535 -- 514(b) -- 5,049
Interest............................. 387 -- 10,289(c) (1,483)(e) 9,193
Depletion and depreciation........... 23,224 -- 3,942(d) -- 27,166
Franchise taxes...................... 308 -- -- -- 308
------- ------- ------- ------- -------
Total expenses............... 44,191 5,237 14,745 (1,483) 62,690
------- ------- ------- ------- -------
Income before income taxes............. 16,878 8,797 (14,745) 1,483 12,413
Provision for income taxes............. (6,245) (3,255)(a) 5,456(a) (549)(a) (4,593)
------- ------- ------- ------- -------
Net income............................. $10,633 $ 5,542 $(9,289) $ 934 $ 7,820
======= ======= ======= ======= =======
Net income per common share
Primary.............................. $ 0.53 $ 0.31
Fully diluted........................ 0.50 0.31
Average common shares outstanding...... 20,175 25,046
</TABLE>

See Notes to Unaudited Pro Forma Consolidated Financial Information
23
<PAGE> 24

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997
----------------------------------------------------------------
ADJUSTMENTS
------------------------------------
EQUITY
OFFERING
COMPANY CHEVRON AND TPG DEBT
HISTORICAL ACQUISITION PURCHASE OFFERING PRO FORMA
---------- ----------- -------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
ASSETS:
Current assets
Cash and cash equivalents........ $ 2,236 $ -- $ -- $ -- $ 2,236
Accrued production receivable.... 7,097 -- -- -- 7,097
Trade and other receivables...... 14,507 -- -- -- 14,507
-------- -------- -------- -------- --------
Total current assets..... 23,840 -- -- -- 23,840
-------- -------- -------- -------- --------
Property and equipment (using full
cost accounting)
Oil and gas properties........... 230,521 127,000(f) -- -- 357,521
Unevaluated oil and gas
properties.................... 6,389 75,000(f) -- -- 81,389
Less accumulated depreciation and
depletion..................... (53,527) -- -- -- (53,527)
-------- -------- -------- -------- --------
Net property and equipment.... 183,383 202,000 -- -- 385,383
-------- -------- -------- -------- --------
Other assets....................... 3,201 -- -- 3,210(k) 6,411
-------- -------- -------- -------- --------
Total assets............. $210,424 $202,000 $ -- $ 3,210 $415,634
======== ======== ======== ======== ========
LIABILITIES AND SHAREHOLDERS'
EQUITY:
Current liabilities
Accounts payable and accrued
liabilities................... $ 16,858 $ -- $ -- $ -- $ 16,858
Oil and gas production payable... 4,060 -- -- -- 4,060
Current portion of long-term
debt.......................... 23 47,000(g) (47,000)(i) -- 23
-------- -------- -------- -------- --------
Total current
liabilities............ 20,941 47,000 (47,000) -- 20,941
-------- -------- -------- -------- --------
Long-term liabilities
Long-term debt................... 20,005 155,000(h) (30,110)(i)(121,790)(l) 23,105
Senior subordinated debt......... -- -- -- 125,000 (m) 125,000
Provision for site reclamation
costs......................... 938 -- -- -- 938
Deferred income taxes and
other......................... 12,982 -- -- -- 12,982
-------- -------- -------- -------- --------
Total long-term
liabilities............ 33,925 155,000 (36,081) 3,210 162,025
-------- -------- -------- -------- --------
Shareholders' equity
Common shares, no par value;
unlimited shares authorized;
20,364,799 outstanding;
25,235,399 outstanding pro
forma......................... 132,744 -- 77,110(j) -- 209,854
Retained earnings................ 22,814 -- -- -- 22,814
-------- -------- -------- -------- --------
Total shareholders'
equity................. 155,558 -- 77,110 -- 232,668
-------- -------- -------- -------- --------
Total liabilities and
shareholders' equity... $210,424 $202,000 $ -- $ 3,210 $415,634
======== ======== ======== ======== ========
</TABLE>

See Notes to Unaudited Pro Forma Consolidated Financial Information
24
<PAGE> 25

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

(a) Income taxes were computed using the federal statutory rate of 35% plus a 2%
provision for state income taxes.

(b) Reflects an increase of $687,000 and $514,000 for the year ended December
31, 1996 and the nine months ended September 30, 1997, respectively, in
general and administrative expense for additional personnel and associated
costs relating to the properties acquired in the Chevron Acquisition, net of
anticipated allocations to operations and capitalization of exploration
costs.

(c) Reflects an increase in interest expense for the period presented to reflect
the $202.0 million of borrowing under the Credit Facility (at an assumed
annual interest rate of 7.8% and 6.8% for the year ended December 31, 1996
and the nine months ended September 30, 1997, respectively) that would have
been required to fund the Chevron Acquisition had it occurred as of the
beginning of each respective period.

(d) Depreciation, depletion and amortization ("DD&A") and site reclamation
expenses have been computed using the unit of production method and reflects
the Company's increased investment in oil and natural gas properties, which
investment excludes $75.0 million of the Chevron Acquisition purchase price
as the Company intends to classify this amount as unevaluated properties at
December 31, 1997. The December 31, 1997 estimated proved reserves prepared
by Netherland & Sewell were used in the DD&A computation for the Chevron
Acquisition.

(e) Reflects a decrease in interest expense for the period presented resulting
from (i) the receipt of $77.1 million in estimated net proceeds from the
Equity Offering and the TPG Purchase and the application of such net
proceeds to reduce borrowings under the Credit Facility and (ii) the receipt
of $121.8 million in estimated net proceeds from the Debt Offering and the
application of such net proceeds to reduce borrowings under the Credit
Facility. Interest expense also includes the amortization of deferred debt
issuance costs.

(f) Reflects the purchase price paid in the Chevron Acquisition, of which the
Company intends to classify $75.0 million as unevaluated properties.

(g) Reflects the incurrence of indebtedness under the Acquisition Tranche (as
defined herein) of the Credit Facility to finance a portion of the Chevron
Acquisition.

(h) Reflects the incurrence of indebtedness under the revolving portion of the
Credit Facility to finance a portion of the Chevron Acquisition.

(i) Reflects the repayment of indebtedness outstanding under the Credit Facility
with the net proceeds of the Equity Offering and the TPG Purchase.

(j) Reflects the issuance and sale of Common Shares in the Equity Offering and
the TPG Purchase, net of underwriting discounts and commissions and
estimated expenses.

(k) Reflects deferred financing costs incurred in connection with the Debt
Offering.

(l) Reflects the repayment of indebtedness outstanding under the Credit Facility
with the net proceeds of the Debt Offering.

(m) Reflects the issuance of the Notes in the Debt Offering.

25
<PAGE> 26

SELECTED CONSOLIDATED FINANCIAL DATA

The selected historical consolidated financial data for the Company set
forth below as of and for the years ended December 31, 1992, 1993, 1994, 1995
and 1996, have been derived from the audited consolidated financial statements
of the Company. The selected historical consolidated financial data for the
nine-month periods ended September 30, 1996 and 1997, and as of September 30,
1997, have been derived from unaudited consolidated financial statements of the
Company which, in management's opinion, include all adjustments (consisting of
only normal recurring adjustments) necessary to present fairly the results for
such periods. The operating results for such periods are not necessarily
indicative of the operating results to be expected for a full fiscal year. The
information set forth below should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------------------- -----------------
1992 1993 1994 1995 1996 1996 1997
------ ------- ------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil, natural gas and related product.................... $1,912 $ 5,868 $12,692 $20,032 $52,880 $34,709 $60,083
Interest income......................................... 40 76 23 77 769 425 986
------ ------- ------- ------- ------- ------- -------
Total revenues...................................... 1,952 5,944 12,715 20,109 53,649 35,134 61,069
------ ------- ------- ------- ------- ------- -------
Expenses:
Production.............................................. 634 2,067 4,309 6,789 13,495 9,197 15,737
General and administrative.............................. 955 782 1,105 1,832 4,267 2,825 4,535
Interest................................................ 8 83 1,146 2,085 1,993 1,530 387
Imputed preferred dividends............................. -- -- -- -- 1,281 1,153 --
Loss on early extinguishment of debt.................... -- -- -- 200 440 440 --
Depletion and depreciation.............................. 690 1,898 4,209 8,022 17,904 12,557 23,224
Franchise taxes......................................... -- -- 65 100 213 160 308
------ ------- ------- ------- ------- ------- -------
Total expenses...................................... 2,287 4,830 10,834 19,028 39,593 27,862 44,191
------ ------- ------- ------- ------- ------- -------
Income (loss) before the following:....................... (335) 1,114 1,881 1,081 14,056 7,272 16,878
Gain on sale of Canadian properties..................... -- 966 -- -- -- -- --
------ ------- ------- ------- ------- ------- -------
Income (loss) before income taxes......................... (335) 2,080 1,881 1,081 14,056 7,272 16,878
Provision for federal income taxes........................ -- (345) (718) (367) (5,312) (2,932) (6,245)
------ ------- ------- ------- ------- ------- -------
Net income (loss)......................................... $ (335) $ 1,735 $ 1,163 $ 714 $ 8,744 $ 4,340 $10,633
====== ======= ======= ======= ======= ======= =======
Net income (loss) per common share:
Primary................................................. $(0.11) $ 0.35 $ 0.19 $ 0.10 $ 0.67 $ 0.37 $ 0.53
Fully diluted........................................... (0.11) 0.35 0.19 0.10 0.62 0.36 0.50
Weighted average common shares outstanding................ 2,949 4,990 6,240 6,870 13,104 11,616 20,175
OTHER FINANCIAL DATA:
Operating cash flow(a).................................... $ 354 $ 3,030 $ 6,185 $ 9,394 $34,140 $21,767 $40,166
Capital expenditures...................................... 6,189 29,855 16,903 28,524 86,857 73,320 70,773
EBITDA(b)................................................. 323 3,019 7,213 11,311 34,905 22,527 39,503
SELECTED RATIOS:
Ratio of earnings to fixed charges(c)..................... (d) 12.3x 2.6x 1.5x 4.4x 3.1x 34.9x
Ratio of EBITDA to interest expense....................... 40.4 36.4 6.3 5.4 17.5 14.7 102.1
Ratio of long-term debt to EBITDA......................... -- 2.0 2.3 0.3 0.1 1.6(e) 0.4(e)
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
----------------------------------------------- SEPTEMBER 30,
1992 1993 1994 1995 1996 1997
------ ------- ------- ------- -------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)................................. $1,369 $(1,410) $(1,620) $ 6,862 $ 12,482 $ 2,899
Total assets.............................................. 8,225 35,978 48,964 77,641 166,505 210,424
Long-term debt, net of current maturities................. -- 6,177 16,536 3,474 125 20,005
Convertible preferred stock............................... -- -- -- 15,000 -- --
Shareholders' equity...................................... 7,548 24,431 25,962 53,501 142,504 155,558
</TABLE>

- ---------------

(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.

(b) EBITDA represents earnings before interest income, interest expense, income
taxes, depletion and depreciation, gain on sale of oil and gas properties,
imputed preferred dividends and losses on early extinguishment of debt. The
Company has included information concerning EBITDA because it believes that
EBITDA is used by certain investors as one measure of an issuer's historical
ability to service its debt. EBITDA is not a measurement determined in
accordance with generally accepted accounting principles and should not be
considered in isolation or as a substitute for measures of performance
prepared in accordance with generally accepted accounting principles.

(c) For purposes of determining the ratio of earnings to fixed charges, earnings
are defined as earnings from continuing operations before income taxes, plus
fixed charges. Fixed charges consist of interest expense, amortization of
debt expense, and imputed preferred stock dividends.

(d) Earnings were inadequate to cover fixed charges as there was a $317,000
deficiency.

(e) EBITDA for these periods has been annualized.

26
<PAGE> 27

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. Over the last four years, the Company has
achieved rapid growth in proved reserves, production and cash flow by
concentrating on the acquisition of properties which it believes have
significant upside potential and through the efficient development, enhancement
and operation of its properties.

ACQUISITION OF CHEVRON PROPERTIES

On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202.0
million. The Chevron Acquisition represents the largest acquisition by the
Company to date. The Heidelberg Field is adjacent to the Company's other primary
oil properties in Mississippi and includes 122 producing wells, 96 of which the
Company will operate. The Company purchased an average working interest of 94%
and an average net revenue interest of 81% in these 96 wells, which wells
currently account for approximately 99% of the field's average net daily
production. The average net daily production from these properties during the
third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d.

The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75.0 million of the purchase price to unevaluated
properties.

ACQUISITION OF HESS PROPERTIES

The Company completed several property acquisitions during 1996, the
largest of which was the acquisition of producing oil and natural gas properties
in Mississippi, Louisiana and Alabama, plus certain overriding royalty interests
in Ohio, for approximately $37.2 million from Amerada Hess, effective May 1,
1996. The average daily production from the properties included in the Hess
Acquisition during May and June 1996, the first two months of ownership, was
approximately 2,945 BOE/d. The average daily production on these properties had
increased to 5,373 BOE/d by the third quarter of 1997. As of December 31, 1997,
in the Company's independent reserve report (the "December Report"), the
properties acquired in the Hess Acquisition had estimated net proved reserves of
approximately 14.2 MMBOE with a PV10 Value of $95.0 million. This compares to
approximately 5.9 MMBOE of net proved reserves and a $43.1 million PV10 Value on
these same properties as reported in the Company's independent reserve report
dated July 1, 1996 (the "July Report"). The December Report was calculated using
year-end prices which were based on a WTI price of $16.18 per Bbl and a NYMEX
price of $2.58 per MMBtu, with these representative prices adjusted by field to
arrive at the appropriate corporate net price, as compared to oil and gas prices
of $20.00 and $2.65, respectively, in the July Report. In addition to the
increase in proved reserves, the Company produced approximately 1.9 MMBOE from
July 1, 1996 through September 30, 1997 with total net operating income of $23.8
million.

27
<PAGE> 28

RESTATED CREDIT FACILITY

The Company has a credit facility (the "Credit Facility") with NationsBank
of Texas, N.A., as agent for a group of banks. The Credit Facility was increased
in size from $150.0 million to $300.0 million in December 1997 and the borrowing
base was increased to $260.0 million in order to fund the Chevron Acquisition.
After application of the net proceeds from the Offerings and the TPG Purchase to
reduce amounts outstanding under the Credit Facility, the Credit Facility will
consist of a five-year revolving credit facility with a borrowing base of $165.0
million with $123.9 million available on a pro forma basis as of December 31,
1997. The borrowing base is subject to review every six months. The Credit
Facility is secured by substantially all of the Company's oil and natural gas
properties, except for those acquired in the Chevron Acquisition. Interest is
payable on the revolving credit facility at either the prime rate or, depending
on the percentage of the borrowing base that is outstanding, at rates ranging
from LIBOR plus 7/8% to LIBOR plus 1 3/8%; provided that interest is payable at
LIBOR plus 1 5/8% as long as the Acquisition Tranche is outstanding with the
rate escalating 0.25% each quarter, beginning on March 1, 1998 through March 31,
1999, unless the Acquisition Tranche is repaid. The 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 in the Credit Agreement); (iv)
a minimum interest coverage test; and (v) a prohibition on most debt, lien and
corporate guarantees.

THE NOTES

The Notes to be issued by DMI are to be fully and unconditionally
guaranteed by DMI's parent company, DRI, pursuant to the terms and conditions of
the Indenture. In addition, under certain circumstances, certain subsidiaries
may in the future guarantee the Notes. The Indenture will contain certain
covenants for the benefit of the holders of the Notes, including, among others,
covenants limiting the payment of dividends, including dividends payable from
DMI to DRI.

CAPITAL RESOURCES AND LIQUIDITY

As discussed below, in each of the last three years, the Company's capital
expenditures required additional debt and equity capital to supplement cash flow
from operations.

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
----------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------- ------- ------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Acquisitions of oil and natural gas
properties............................ $ 6,606 $16,763 $48,407 $16,073
Oil and natural gas expenditures........ 10,297 11,761 38,450 54,700
------- ------- ------- -------
Total......................... $16,903 $28,524 $86,857 $70,773
======= ======= ======= =======
</TABLE>

From January 1, 1994 through September 30, 1997, including the pro forma
adjustments for the Chevron Acquisition, the Company has made total capital
expenditures of $405.1 million. These capital expenditures were funded by the
issuance of equity ($105.3 million), bank debt ($209.9 million) and cash
generated by operations ($89.9 million). During 1996, the Company's funds were
provided by operating cash flow and equity, although the Company did use bank
debt during the year. The Company began 1996 with $100,000 of outstanding bank
debt, borrowed $47.9 million during the year, paid off the debt with the
proceeds from a public offering of Common Shares in October 1996 and ended the
year with $100,000 of bank debt outstanding. For the nine months ended September
30, 1997, the Company's average debt outstanding was $3.6 million.

As of December 31, 1997, the Company had minimal working capital and
approximately $240.0 million of debt outstanding. A portion of this debt also
relates to an acquisition tranche on which the interest rate increases 0.25%
each quarter beginning on March 1, 1998. Although the Company is still reviewing
its budget, particularly in light of the recent Chevron Acquisition, the Company
is currently budgeting capital expenditures for 1998 of approximately $95.0
million, of which approximately $30.0 million is allocated for the
28
<PAGE> 29

properties included in the Chevron Acquisition. Although the Company's projected
cash flow is highly variable and difficult to predict as it is dependent on
product prices, drilling success and other factors, these projected expenditures
are expected to exceed the Company's cash flow during 1998. As of December 31,
1997, after giving pro forma effect to the Transactions, the Company would have
had an unused borrowing base of $123.9 million under the Credit Facility to fund
any potential cash flow deficits. If external capital resources are limited or
reduced in the future, the Company can also adjust its capital expenditure
program accordingly. However, such adjustments could limit, or even eliminate,
the Company's future growth. See "Risk Factors -- Substantial Capital
Requirements."

In addition to its internal capital expenditure program, the Company has
historically required capital for the acquisition of producing properties, which
have been a major factor in the Company's rapid growth during recent years.
There can be no assurance that suitable acquisitions will be identified in the
future or that any such acquisitions will be successful in achieving desired
profitability objectives. Without suitable acquisitions or the capital to fund
such acquisitions, the Company's future growth could be limited or even
eliminated. As such, the Company is seeking additional financing from the
Offerings and the TPG Purchase in order to reduce amounts outstanding under the
Credit Facility and to better position the Company for future opportunities.

SOURCES AND USES OF FUNDS. During the first nine months of 1997, the
Company spent approximately $54.7 million on exploration and development
expenditures and approximately $16.1 million on acquisitions. The exploration
and development expenditures included approximately $38.2 million spent on
drilling, $6.7 million on geological, geophysical and acreage expenditures and
$9.8 million on workover costs. These expenditures were funded by available
cash, bank debt and cash flow from operations. The Company anticipates that a
total of approximately $10 million will be spent during 1997 on exploration
expenditures $65 million on development expenditures, and $225 million on
acquisitions.

During 1996, the Company spent approximately $33.4 million on oil and
natural gas development expenditures, $37.2 million on the Hess Acquisition,
$7.5 million on properties acquired in April 1996 (the "Ottawa Acquisition"),
$3.7 million on other minor oil and natural gas acquisitions, and approximately
$5.1 million on geological, geophysical and acreage expenditures. The
development expenditures included $15.5 million spent on drilling and $17.9
million spent on workover costs. These expenditures were funded during the year
by bank debt, available cash and cash flow from operations, although the bank
debt was retired with the proceeds from a public offering of Common Shares in
October 1996.

During 1995, the Company made $28.5 million in capital expenditures, with
the single largest component being a $10.0 million acquisition of seven
producing wells in the Gibson and Humphreys Fields located near the Company's
other properties in southern Louisiana (the "Gibson Acquisition"). The balance
of 1995 acquisition expenditures were for additional interests in the Company's
Lirette Field in Louisiana ($2.9 million), interests in the Bully Camp Field,
also in Louisiana ($2.1 million), and a few smaller acquisitions in both
Mississippi and Louisiana. During 1995, the Company also spent $1.9 million
drilling four wells in Mississippi, $1.1 million for acreage, geological and
geophysical and delay rentals, and $8.1 million for workovers of existing
properties. The 1995 expenditures were funded on an interim basis with cash flow
from operations ($9.4 million) and bank debt ($19.4 million), which was repaid
in December 1995 with a portion of the $39.5 million of net proceeds from a
private placement of equity with TPG.

Capital expenditures for 1994 were $16.9 million and included $10.3 million
of development costs, primarily expended on natural gas properties in Louisiana,
with the balance of $6.6 million expended on acquisitions of properties
primarily in Louisiana, of which $5.5 million was spent on acquiring additional
working interests in existing Company-operated properties. Expenditures in 1994
were principally funded by $6.2 million of cash provided by operations and net
incremental debt of $8.8 million, of which $1.5 million came from the issuance
of unsecured convertible debentures and the balance from bank debt.

29
<PAGE> 30

RESULTS OF OPERATIONS

OPERATING INCOME

During the last three years, operating income has increased significantly
as outlined in the following chart. Oil and gas revenue increased as a result of
the increased oil and gas production and increases in oil and gas product
prices.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------- ------------------
1994 1995 1996 1996 1997
------- ------- -------- ------- --------
<S> <C> <C> <C> <C> <C>
Operating income (in thousands)
Oil sales............................ $ 6,767 $10,852 $ 28,475 $17,455 $ 36,436
Natural gas sales.................... 5,925 9,180 24,405 17,254 23,647
Less production expenses............. (4,309) (6,789) (13,495) (9,197) (15,737)
------- ------- -------- ------- --------
Operating income.................. $ 8,383 $13,243 $ 39,385 $25,512 $ 44,346
======= ======= ======== ======= ========
Unit prices
Oil price per Bbl.................... $ 13.84 $ 14.90 $ 18.98 $ 18.05 $ 17.53
Gas price per Mcf.................... 1.78 1.90 2.73 2.64 2.54
Netback per BOE
Sales price.......................... $ 12.17 $ 13.05 $ 17.69 $ 16.87 $ 16.56
Production expenses.................. (4.13) (4.42) (4.51) (4.47) (4.34)
------- ------- -------- ------- --------
$ 8.04 $ 8.63 $ 13.18 $ 12.40 $ 12.22
======= ======= ======== ======= ========
Average net daily production volume
Bbls................................. 1,340 1,995 4,099 3,529 7,615
Mcf.................................. 9,113 13,271 24,406 23,867 34,061
BOE.................................. 2,858 4,207 8,167 7,507 13,292
</TABLE>

COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. Production
increases have been fueled by both internal growth from the Company's
development and exploration programs and from the acquisition of producing
properties. Production on a BOE/d basis increased 47% between 1994 and 1995 with
approximately 240 BOE/d attributable to the Gibson Acquisition and the balance
of approximately 1,109 BOE/d primarily attributable to internal growth. Between
1995 and 1996, production increased 94% with approximately 2,550 BOE/d
attributable to the properties acquired in the Hess and Ottawa Acquisitions and
750 BOE/d attributable to properties acquired in the Gibson Acquisition. The
balance of approximately 660 BOE/d was attributable to internal growth on other
properties.

Oil and gas revenue has increased not only because of the large increase in
production, but also due to improved product prices for these periods. Between
1994 and 1995, product price increases were relatively modest with an 8%
increase in oil prices and a 7% increase in natural gas prices. The Company also
realized an $800,000 gas hedging gain during 1995 which added $.17 per Mcf to
its average natural gas price. The Company did not have any oil or natural gas
hedges in place during 1996, nor does it have any currently in place due to the
relatively strong commodity prices and the reduced debt levels of the Company.
During 1996, product prices increased substantially with a 27% increase in the
average oil price and a 44% increase in the average natural gas price. Coupled
with the production increases, the Company's oil and natural gas revenue
increased 164%, or $32.8 million, from 1995 to 1996. Approximately $16.5 million
of the increase was related to properties acquired in the Hess and Ottawa
Acquisitions, approximately $5.4 million to properties acquired in the Gibson
Acquisition, approximately $7.7 million due to the increase in product prices
and the balance of approximately $3.2 million due to increased production from
internal growth on other properties.

Production expenses increased each year along with the increases in
production. On a BOE basis, production expenses increased 7% from 1994 to 1995
and increased 2% from 1995 to 1996. The increases were largely attributable to
the changes in the mix of properties as the Mississippi oil properties tend to
have a higher operating cost per BOE than the Louisiana gas properties. During
the first two months of ownership
30
<PAGE> 31

(May and June 1996), the production expenses averaged $6.27 per BOE on the Hess
Acquisition properties which were more heavily weighted toward Mississippi oil
than Louisiana gas. After assuming operations, these averages were brought more
in line with the Company averages through cost savings and increased production
levels. For the remainder of the year (July through December 1996) production
expenses on these properties averaged $5.05 per BOE.

COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. Production
increases have been fueled by both internal growth from the Company's
development and exploration programs and from the acquisition of producing
properties during 1996, particularly the Hess Acquisition. During May and June
of 1996, the first two months of ownership, the properties acquired in the Hess
Acquisition averaged approximately 2,945 BOE/d. During the first, second and
third quarters of 1997, the production from these same properties averaged
approximately 4,385 BOE/d, 4,613 BOE/d and 5,373 BOE/d, respectively, a 49%, 57%
and 82% increase, respectively, from initial production levels. Total corporate
production on a BOE/d basis increased 21% from the fourth quarter of 1996
average of 10,132 BOE/d to the first quarter of 1997 average of 12,256 BOE/d,
increased an additional 9% to 13,405 BOE/d for the second quarter of 1997 and an
additional increase of 6% to 14,195 BOE/d for the third quarter of 1997. Since
the Company has had only limited acquisitions since the Hess Acquisition, the
production increases since June 30, 1996 were almost solely as a result of
internal development. On a quarter to quarter comparison, production on a BOE
basis increased 54% between the respective third quarters. When comparing the
nine month periods, production on a BOE basis has increased 77%, reflecting the
effect of the Hess Acquisition effective in May 1996.

Oil and gas revenue has increased primarily because of the large increase
in production. Oil product prices decreased by 3% and natural gas product prices
declined 4% or an overall decline of 2% when measured on a BOE basis when
comparing the nine months ended September 30, 1997 to the comparable period in
1996. During the first nine months of 1996, approximately 47% of the Company's
production on a BOE basis was oil while during the first nine months of 1997,
approximately 57% of the Company's production on a BOE basis was oil.

Production expenses on an absolute basis increased between the relative
periods of 1996 and 1997 along with the increases in production. On a BOE basis,
production expenses decreased 3% when comparing the first nine months of 1996 to
the first nine months of 1997. This improvement was a result of efficiencies
achieved from higher production volumes (on both an absolute basis and per well
basis) despite the Company having a higher percentage of oil production in 1997
as compared to 1996, which typically has a higher operating cost per BOE.

GENERAL AND ADMINISTRATIVE EXPENSES

As outlined below, general and administrative ("G&A") expenses have
increased along with the Company's growth.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------- -----------------
1994 1995 1996 1996 1997
------ ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Net G&A expenses (in thousands)
Gross expenses.......................... $2,475 $ 3,900 $ 8,407 $ 5,583 $ 9,999
State franchise taxes................... 65 100 213 159 308
Operator overhead charges............... (890) (1,438) (2,916) (1,906) (3,789)
Capitalized exploration expenses........ (480) (630) (1,224) (851) (1,675)
------ ------- ------- ------- -------
Net expenses............................ $1,170 $ 1,932 $ 4,480 $ 2,985 $ 4,843
====== ======= ======= ======= =======
Average G&A cost per BOE.................. $ 1.12 $ 1.25 $ 1.50 $ 1.45 $ 1.33
Employees as of end of period............. 27 51 122 109 141
</TABLE>

COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. On a BOE basis,
these costs increased 12% from 1994 to 1995 and increased 20% from 1995 to 1996.
Part of the increase in 1995 was attributable to $190,000 of costs ($0.12 per
BOE) related to non-recurring personnel changes. As a result of improved
31
<PAGE> 32

financial results during the first quarter of 1996 and other factors, the
Company conducted a review of salaries and awarded increases and bonuses in
February 1996 to its employees. Bonuses, including related payroll taxes,
amounted to approximately $225,000 ($0.08 per BOE). During 1996, the Company
also accrued $545,000 ($0.18 per BOE) for bonuses which were awarded in February
1997. In addition, the Company began to increase its staff levels during the
second quarter of 1996 to handle the Hess Acquisition, but was not entitled to
any operator's overhead recovery on these properties until July 15, 1996,
resulting in a further increase in general and administrative cost per BOE, as
Amerada Hess remained the operator of record until that date.

COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. On a BOE
basis, G&A expenses declined 8% when comparing the first nine months of 1996 to
the comparable period in 1997. The decrease is partially attributable to the
increased production on both an absolute and per well basis. Furthermore, the
respective well operating agreements allow the Company, when it is the operator,
to charge a well with a specified overhead rate during the drilling phase. As a
result of the increased drilling activity in 1997, the percentage of gross G&A
recovered through these types of allocations (listed in the above table as
"Operator overhead charges") increased when compared to the corresponding
periods of 1996. During the first nine months of 1996, approximately 34% was
recovered by operator overhead charges, while during the comparable period of
1997 this increased to 38%. This trend is even more pronounced in the third
quarter of 1997 with 42% of the gross G&A recovered as compared to 35% for the
third quarter of 1996.

INTEREST AND FINANCING EXPENSES

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- ------------------
1994 1995 1996 1996 1997
------- ------- ------- -------- -------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
Interest expense....................... $ 1,146 $ 2,085 $ 1,993 $ 1,530 $ 387
Non-cash interest expense.............. (86) (90) (459) (345) (64)
------- ------- ------- ------- ------
Cash interest expense.................. 1,060 1,995 1,534 1,185 323
Interest and other income.............. (23) (77) (769) (425) (986)
------- ------- ------- ------- ------
Net interest expense................. $ 1,037 $ 1,918 $ 765 $ 760 $ (663)
======= ======= ======= ======= ======
Average interest cost per BOE.......... $ 0.99 $ 1.26 $ 0.26 $ 0.37 $(0.18)
Average debt outstanding............... 12,200 21,400 19,500 20,673 3,610
Ratio of earnings to fixed charges..... 2.6x 1.5x 4.4x 3.1x 34.9x
Imputed preferred dividend............. $ -- $ -- $ 1,281 $ 1,153 $ --
Loss on early extinguishment of debt... -- 200 440 440 --
</TABLE>

During the first half of 1996 and 1997, the Company had minimal debt
outstanding as virtually all of the bank debt had been retired during the
previous fourth quarter. In 1995, the bank debt was repaid with proceeds from
the December 1995 private placement of equity with TPG and in 1996, the debt was
repaid with proceeds from a public offering of Common Shares completed in
October 1996. However, in 1996, the Company did incur debt late in the second
quarter in order to fund property acquisitions and, during the third quarter of
1997, the Company borrowed approximately $20 million to fund $12.5 million of
property acquisitions and $7.5 million of development expenditures.

The private placement of equity in December 1995 with TPG included 1.5
million shares of Convertible Preferred. During 1996, the Company recognized
$1.3 million of charges representing the imputed preferred dividend until
October 30, 1996 when the Convertible Preferred were converted into 2.8 million
Common Shares. Under Canadian generally accepted accounting principles, this
dividend was reported as an operating expense, while under U.S. generally
accepted accounting principles this would not be an expense but it would be
deducted from net income to arrive at net income attributable to the common
shareholders. In addition to paying off its bank debt and converting the
Convertible Preferred into common equity during 1996, the Company also converted
its remaining subordinated debt into common equity, leaving the Company
essentially debt-free as of December 31, 1996.
32
<PAGE> 33

During 1996, the Company had a $440,000 charge relating to a loss on early
extinguishment of debt. These costs related to the remaining unamortized debt
issue costs of the Company's prior credit facility which was replaced in May
1996, as previously discussed. The Company also had a charge of $200,000 during
the first half of 1995 for the same type of expense relating to a previous bank
debt refinancing. Under U.S. generally accepted accounting principles, a loss on
early extinguishment of debt would be an extraordinary item rather than a normal
operating expense as required by Canadian generally accepted accounting
principles.

DEPLETION, DEPRECIATION AND SITE RESTORATION

COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. DD&A has
increased along with the additional capitalized cost and increased production.
DD&A per BOE has increased 30% from 1994 to 1995 and 15% from 1995 to 1996
primarily due to 59% of the 1995 capital expenditures and 56% of the 1996
expenditures relating to property acquisitions, which had a higher per unit cost
for the Company than those reserves added by development expenditures.

COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. The Company's
DD&A rate per BOE for the first half of 1997 increased to $6.50 per BOE to
provide for the estimated effect of reduced oil prices on reserve quantities,
the estimated effect of rising drilling costs on certain proved undeveloped
locations, and higher than anticipated costs on wells drilled in Louisiana that
were proved undeveloped locations at December 31, 1996. In comparison, the
Company's DD&A rate was $5.99 per BOE for the year ended December 31, 1996. The
oil prices used in the December 31, 1996 reserve report were based on a WTI
posting price of $23.39 per Bbl in accordance with the rules of the Commission
while the comparable WTI price at June 30, 1997 was $17.15 per Bbl. This
reduction in oil prices reduced the June 30, 1997 estimated reserves by
approximately 1.3 MMBbls.

As a result of two oil and natural gas discoveries announced in September,
1997, the Company's third quarter DD&A rate decreased to $6.22 per BOE ($6.40
per BOE for the nine months ended September 30, 1997). During the third quarter
of 1997, the Company also transferred approximately $4.6 million from the
unevaluated properties to the full cost pool reflecting activity on these
properties, leaving a balance of approximately $6.4 million in unevaluated
properties as of September 30, 1997. The DD&A effect of this transfer was
approximately $440,000 for the quarter.

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 the DD&A expense and has
increased each year along with an increase in the number of properties owned by
the Company.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -----------------
1994 1995 1996 1996 1997
------ ------ ------- ------- -------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
Depletion and depreciation............... $4,177 $7,918 $17,533 $12,430 $22,899
Site restoration provision............... 32 104 371 127 325
------ ------ ------- ------- -------
Total amortization....................... $4,209 $8,022 $17,904 $12,557 $23,224
====== ====== ======= ======= =======
Average DD&A cost per BOE................ $ 4.03 $ 5.22 $ 5.99 $ 6.10 $ 6.40
</TABLE>

33
<PAGE> 34

INCOME TAXES

Due to net operating losses by its U.S. subsidiary each year for tax
purposes, the Company does not have any current tax provision. The deferred tax
provision as a percentage of net income has varied depending on the mix of
Canadian and U.S. expenses. The rate declined from 1994 to 1995 as there were
less Canadian expenses, but increased again slightly in 1996 due to the
non-deductible imputed preferred dividend and interest on the subordinated debt.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -----------------
1994 1995 1996 1996 1997
------ ------ ------- ------- -------
<S> <C> <C> <C> <C> <C>
Deferred income taxes (thousands)........ $ 718 $ 367 $ 5,312 $ 2,932 $ 6,245
Average income tax costs per BOE......... 0.69 0.24 1.78 1.43 1.72
Effective tax rate....................... 38% 34% 38% 40% 37%
</TABLE>

NET INCOME

Primarily as a result of increased production and improved product prices,
net income and cash flow from operations increased substantially between 1995
and 1996 as outlined below. Between 1994 and 1995, net income decreased 39% as a
result of certain nonrecurring charges and a disproportionate increase in DD&A
as compared to the increase in revenue. Net income and cash flow from operations
increased substantially on both a gross and per share basis between the first
nine months of 1996 and the first nine months of 1997 as outlined below.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -----------------
1994 1995 1996 1996 1997
------ ------ ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Net income............................... $1,163 $ 714 $ 8,744 $ 4,340 $10,633
Net income per common share:
Primary................................ 0.19 0.10 0.67 0.37 0.53
Fully diluted.......................... 0.19 0.10 0.62 0.36 0.50
Cash flow from operations(a)............. 6,185 9,394 34,140 21,767 40,166
</TABLE>

- ---------------

(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.

34
<PAGE> 35

The following table summarizes the cash flow, DD&A and net income on a BOE
basis for the comparative periods. Each of the individual components are
discussed above.

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------ ---------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Per BOE data
Revenue................................... $12.17 $13.05 $17.69 $16.87 $16.56
Production expenses....................... (4.13) (4.42) (4.51) (4.47) (4.34)
------ ------ ------ ------ ------
Production netback........................ 8.04 8.63 13.18 12.40 12.22
General and administrative................ (1.12) (1.25) (1.50) (1.45) (1.33)
Interest.................................. (0.99) (1.26) (0.26) (0.37) 0.18
------ ------ ------ ------ ------
Cash flow from operations(a)........... 5.93 6.12 11.42 10.58 11.07
DD&A...................................... (4.03) (5.22) (5.99) (6.10) (6.40)
Deferred income taxes..................... (0.69) (0.24) (1.78) (1.43) (1.72)
Other non-cash items...................... (0.10) (0.19) (0.72) (0.94) (0.02)
------ ------ ------ ------ ------
Net income............................. $ 1.11 $ 0.47 $ 2.93 $ 2.11 $ 2.93
====== ====== ====== ====== ======
</TABLE>

- ---------------

(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.

YEAR 2000 MODIFICATIONS

The Company is currently reviewing its computer systems in order to
evaluate necessary modifications for the year 2000. The Company does not
currently anticipate that it will incur material expenditures to complete any
such modifications.

RECENTLY ISSUED ACCOUNTING STANDARDS

See discussion of Recently Issued Accounting Standards in Note 7 of the
Consolidated Financial Statements.

35
<PAGE> 36

BUSINESS AND PROPERTIES

THE COMPANY

Since 1993, when the Company began to focus its operations exclusively in
the United States, through December 31, 1995, the Company spent a total of $43.4
million on acquisitions. In May 1996, the Company acquired properties in its
core areas of Mississippi and Louisiana from Amerada Hess for approximately
$37.2 million. As of June 30, 1996, these acquired properties were producing
approximately 2,945 BOE/d and had proved reserves of approximately 5.9 MMBOE.
Since that date, the Company's extensive development and exploitation on these
properties has resulted in an 82% increase in their production to 5,373 BOE/d
for the third quarter of 1997 and a 141% increase in their proved reserves to
14.2 MMBOE as of December 31, 1997.

On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, which is adjacent to the Company's other primary oil properties in
Mississippi, from Chevron for approximately $202.0 million. These properties are
located approximately nine miles from the Eucutta Field, the property with the
highest PV10 Value of those acquired by the Company in the Hess Acquisition. The
estimated proved reserves as of January 1, 1998 for the Chevron Acquisition
properties are approximately 27.6 MMBOE, with average net daily production of
approximately 2,940 BOE/d for the third quarter of 1997. As a result of the
significant amount of future development and exploitation to be performed on
these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75.0 million of the purchase price to unevaluated
properties. The Company believes that the properties acquired in the Chevron
Acquisition provide exploitation opportunities similar to those of the
Mississippi properties acquired in the Hess Acquisition and the Company intends
to apply the same technologies to the Heidelberg Field. The Company's estimated
1998 development budget for the Heidelberg Field is approximately $30.0 million.
See "-- Acquisition of Chevron Properties."

BUSINESS STRATEGY

The Company seeks to: (i) achieve attractive returns on capital through
prudent acquisitions, development and exploratory drilling and efficient
operations; (ii) maintain a conservative balance sheet to preserve maximum
financial and operational flexibility; and (iii) create strong employee
incentives through equity ownership. The Company believes that its growth to
date in proved reserves, production and cash flow is a direct result of its
adherence to several fundamental principles which are at the core of the
Company's long-
36
<PAGE> 37

term growth strategy. The Company's long-term growth strategy includes the
following fundamental principles:

OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company intends to
continue to acquire working interest positions that give it operational control
or that the Company believes may lead to operational control. As the operator of
properties comprising approximately 83% of its total PV10 Value, the Company
believes it is better able to manage and monitor production and more effectively
control expenses, the allocation of capital and the timing of field development.
Once a property is acquired, the Company employs its technical and operational
expertise to fully evaluate a field's future potential. If favorable, it will
consolidate its working interest positions, primarily through negotiated
transactions, which tend to be attractively priced compared to acquisitions
available in competitive situations. The consolidation of ownership allows the
Company to: (i) enhance the effectiveness of its technical staff by
concentrating on relatively few wells; (ii) increase production while adding
virtually no additional personnel; and (iii) increase ownership in a property so
that the potential benefits of value enhancement activities justify the
allocation of Company resources.

retaining and motivating quality personnel. As of January 1, 1998, approximately
86% of the Company's employees were participating in the Company's stock
purchase plan. The Company believes that all employees are important to the
success of the Company and as such grants bonuses and stock options to both
management and employees on a basis roughly proportional to salaries.

OIL AND NATURAL GAS OPERATIONS

Denbury operates in two core areas, Louisiana and Mississippi. The Company
operates 67 wells in Louisiana from an office in Houma and 161 wells in
Mississippi from an office in Laurel. The eight largest oil and natural gas
fields owned by the Company constitute approximately 85% and 82%, respectively,
of its total proved reserves on a BOE and PV10 Value basis. Within these eight
fields, Denbury owns an average 91% working interest and operates 85% of the
wells, which comprise 71% of the Company's PV10 Value. The Company's eight
largest fields are located in three adjacent counties in Mississippi and one
parish in Louisiana. This concentration of value in a relatively small number of
fields allows the Company to benefit substantially from any operating cost
reductions or production enhancements and allows the Company to effectively
manage the properties from its two field offices.

These two core areas are similar in that the major trapping mechanisms for
oil and natural gas accumulations are structural features usually related to
deep-seated salt or shale movement. Both areas typically feature fields with
mostly multiple sandstone reservoirs supported by strong waterdrives. However,
the two areas differ significantly in drilling costs, risks and the size of
potential reserves. In Mississippi, the producing zones are generally shallower
than in Louisiana and therefore drilling and workover costs are lower. However,
the geological complexity of southern Louisiana, which is more expensive to
exploit, creates the potential for larger discoveries, particularly of natural
gas. The Company's production in Louisiana is predominately natural gas, while
Mississippi is predominately oil.

The following table sets forth information with respect to Denbury's
properties, reserves and drilling and production activities. The information
included in this table about the Company's proved oil and natural gas reserve
estimates as of December 31, 1997 were prepared by Netherland & Sewell. See
"Risks Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves."

<TABLE>
<CAPTION>
AVERAGE NET PRODUCTION AS OF
PROVED RESERVES THIRD QUARTER OF SEPTEMBER 30,
AS OF DECEMBER 31, 1997 1997(A) 1997
--------------------------------------- ----------------------- ---------------------
PV10 AVERAGE
NATURAL PV10 VALUE NATURAL GROSS NET
OIL GAS VALUE % OF OIL GAS PRODUCTIVE REVENUE
(MBBLS) (MMCF) (000'S)(B) TOTAL (BBLS/D) (MCF/D) WELLS(C) INTEREST
-------- ------- ---------- ----- ---------- --------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LOUISIANA
Lirette..................... 289 27,746 44,668 12.4% 161 11,983 18 63.0%
Gibson...................... 302 6,631 12,658 3.5% 196 4,602 3 57.8%
South Chauvin............... 135 7,333 9,734 2.7% 48 3,029 4 73.4%
Bayou Rambio................ 69 11,353 18,205 5.0% 45 3,254 3 59.1%
Other Louisiana............. 1,423 15,048 33,192 9.2% 1,186 10,232 82 48.7%
------ ------ ------- ----- ----- ------ ---
Total Louisiana........... 2,218 68,111 118,457 32.8% 1,636 33,100 110 51.5%
------ ------ ------- ----- ----- ------ ---
MISSISSIPPI
Heidelberg(d)............... 30,171 2,517 118,973 32.9% -- -- -- --
Eucutta..................... 8,967 -- 58,657 16.2% 1,895 -- 45 75.3%
Davis....................... 2,660 -- 13,348 3.7% 1,033 -- 25 90.5%
Quitman..................... 3,032 -- 19,064 5.3% 1,914 -- 18 60.7%
Other Mississippi........... 4,834 5,597 29,667 8.2% 1,594 2,716 87 53.1%
------ ------ ------- ----- ----- ------ ---
Total Mississippi........... 49,664 8,114 239,709 66.3% 6,436 2,716 175 66.5%
------ ------ ------- ----- ----- ------ ---
Other......................... 136 966 3,163 0.9% 76 466 -- --
------ ------ ------- ----- ----- ------ ---
Company Total................. 52,018 77,191 361,329 100.0% 8,148 36,282 285 60.7%
====== ====== ======= ===== ===== ====== ===
</TABLE>

- ---------------

38
<PAGE> 39

(a) This table does not include production on the properties acquired in the
Chevron Acquisition. See "-- Production Volumes, Sales Prices and Production
Costs" for pro forma production data.

(b) The reserves were prepared using constant prices and costs in accordance
with the guidelines of the Commission, based on the prices received on a
field by field basis as of December 31, 1997. The oil price at that date was
WTI $16.18 per Bbl adjusted by field and a NYMEX natural gas price average
of $2.58 per MMBtu, also adjusted by field.

(d) Includes properties acquired in the Chevron Acquisition, as well as
properties acquired in three other minor acquisitions in the same field. The
average net production on the properties acquired in the Chevron Acquisition
from July 1, 1997 through September 30, 1997 was 2,840 Bbls/d and 600 Mcf/d
from 122 gross productive wells with an average net revenue interest of 81%.

MISSISSIPPI OPERATING AREA

In Mississippi, most of the Company's production is oil, produced largely
from depths of less than 10,000 feet. Fields in this region are characterized by
relatively small geographic areas which generate prolific production from
multiple pay sands. The Company's Mississippi production is usually associated
with large amounts of saltwater, which must be disposed of in saltwater disposal
wells, and almost all wells require pumping. These factors increase the
operating costs on a per barrel basis as compared to Louisiana. The Company
places considerable emphasis on reducing these costs in order to maximize the
cash flow from this area. The Company has increased its emphasis in horizontal
drilling based on its apparent success during the past year. These horizontal
wells have contributed to the reduction of operating costs on a BOE basis during
the last twelve months, as these wells typically produce oil more efficiently,
resulting in higher production rates and better recovery efficiency.

The Company drilled its first horizontal well in 1995 at the South Thompson
Creek Field in Mississippi and drilled a subsequent horizontal well in this
field during 1996. Both of these wells were completed as producers. During the
last quarter of 1996 and through the end of 1997, the Company completed twelve
horizontal wells at an average cost of $1,050,000. These wells produced at an
average production rate of 420 Bbls/d in their initial month of production.
Although horizontal wells typically decline rapidly from their initial
production rates, these twelve wells had an average production rate of 280
Bbls/d for the month of December 1997 and have been producing for an average of
seven months. These horizontal wells typically have a higher internal rate of
return than a comparable vertical well, reduce operating costs per BOE and
reduce the number of wells required to drain the reservoir. The Company plans to
drill over 50 horizontal wells in 1998 in Mississippi.

HEIDELBERG FIELD. Heidelberg field was discovered in 1944 and has produced
an estimated 191 MMBbls and 36 Bcf since its discovery. This Field is a large
salt-cored anticline which is divided by faulting into a western and eastern
half. Production is from a series of normally pressured Cretaceous and Jurassic
sandstone horizons situated between 4,500 feet and 11,500 feet. There are 11
producing formations in the Heidelberg Field containing 44 individual reservoir
intervals, with the majority of the current production coming from the Eutaw and
Christmas sands at depths of approximately 5,000 feet.

The West Heidelberg Eutaw sands have been unitized and water injection
began late in 1996 in order to increase the bottom hole pressure and improve
recoveries from the formation. A production response to the injection is
expected during 1998. The Eutaw East One Fault Block Oil Pool Unit (Eutaw
formation in East Heidelberg) was unitized in October 1997 and injection is
projected to commence in March 1998. These waterflood projects, particularly the
East Unit, comprise a significant portion of the potential reserves at
Heidelberg. The Company has a 78% working interest in the East Unit, 59% of
which was acquired in the Chevron Acquisition and the remaining 19% of which was
acquired over a three-month period from three other entities. The Company
operates a similar Eutaw unit at its East Eucutta Field, located approximately
nine miles to the southeast, with production from sands with similar porosity,
permeability, thickness and drive mechanisms.

39
<PAGE> 40

The Company has identified several potential development projects during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 15 wells and recompleting 30
wells in new zones. In addition, the Company has identified over 40 potential
drilling locations in addition to other potential secondary and tertiary
recovery projects. Horizontal wells drilled by the Company in 1997 at nearby
Davis, Quitman and Eucutta Fields improved daily production rates significantly
as compared to vertical wells drilled in the same fields. Consequently, the
Company anticipates that 30 of the 40 proposed future wells will be horizontal
wells. The Company's total 1998 development budget for the Heidelberg Field is
approximately $30 million.

Based on its experience in other fields in the same area, the Company
believes that significant additional reserve potential may exist beyond the
identified proven reserves. The development budget in 1998 and ensuing years is
expected, in part, to be used to evaluate this potential which is summarized
below:

Higher Oil Recovery in the Eutaw Sand Waterfloods. Since discovery of the
Heidelberg Field, total cumulative production in the Eutaw formation through
December 1997 has been 80 MMBbls, which, based upon geological and engineering
analysis, the Company estimates has recovered 22% of the original oil in place.
Based upon a similar analysis, the Company estimates that historical cumulative
production from the Eutaw formation under waterflood at nearby East Eucutta
Field has recovered an estimated 34% of the oil in place. The Company believes
that similar recovery factors may be achievable at Heidelberg Field based on the
geological conditions that appear to be analogous. The Company will also attempt
to improve the recovery factors through the use of horizontal drilling and may
also employ tertiary recovery methods such as carbon dioxide injection. The
Company currently is evaluating the feasibility of such methods.

Higher Oil Recovery in the Christmas Sands. Because of the success of the
Company's horizontal drilling program in other fields in the area, the Company
intends to develop the Christmas sands primarily through horizontal drilling.
Since its discovery, the Christmas sands have produced approximately 67 MMBbls
through December 1997. The Company believes these sands are ideal for horizontal
development due to the strong natural water drive of these reservoirs. Recent
horizontal drilling by the Company has produced oil at faster rates and reduced
operating costs on a BOE basis as compared to vertical drilling. Although
Denbury believes that horizontal drilling should ultimately increase the amount
of oil recovered from the Christmas sands, to date the Company does not have
enough production history to determine if, and to the extent, oil recoveries
will increase.

Further Drilling in Deeper Zones. The zones below the Christmas formation
including the Tuscaloosa, Paluxy, Rodessa, Hosston, Cotton Valley and Smackover
formations, have produced on a cumulative basis a combined 44 MMBbls and 14 Bcf
through December 1997. The Company believes that additional reserve potential
may exist for extensions of existing reservoirs and potential new reservoirs in
these zones within the Heidelberg Field area. A 36-square mile 3-D seismic
program over the field was shot by Chevron in 1993 and will be acquired under
license by Denbury. The Company intends to reprocess the 3-D seismic data to
evaluate this potential.

EUCUTTA FIELD. The Eucutta Field is located about 18 miles east of Laurel,
Mississippi. Since its discovery in 1943, this field has produced 63 MMBbls and
4.7 Bcf. Denbury acquired the majority of its interests in this field as part of
the Hess Acquisition and currently operates 45 producing oil wells and 3
saltwater injection wells. Most of the wells produce oil with large amounts of
saltwater, which requires pumping and disposal.

The Eucutta Field is divided into a shallow Eutaw sand unit in which the
Company has a 78% working interest and the deeper Tuscaloosa, Wash-Fred, Paluxy,
Rodessa, Sligo and Hosston sand zones in which the Company has a 100% working
interest. The Eucutta Field traps oil in multiple sandstone reservoirs from the
Eutaw to the Hosston Formations in this highly faulted anticline from depths of
5,000 to 11,000 feet. Denbury recently established new production in the Paluxy
interval in a series of six stacked sands. Two additional delineation wells have
been drilled and completed for this interval and the Company currently plans to
drill six horizontal wells to fully develop this new area. The deeper intervals
of the Cotton Valley and Smackover formations have yet to be tested in crestal
positions on this structure although these two horizons have proved to be highly
productive throughout the Mississippi Salt Basin.
40
<PAGE> 41

Since its acquisition in May 1996, the Company has implemented a capital
expenditure program at Eucutta Field which included upgrading production
facilities, recompletions and drilling wells. At the time of acquisition,
production from this field was approximately 1,100 Bbls/d. All seven wells
drilled in 1997 were successful, two of which were horizontal wells. As a result
of these wells and other development work, during December 1997 the net
production increased to an average of 2,976 Bbls/d. The Company plans to shoot a
3-D seismic survey over the field and have it processed by late 1998. During
1998, the Company also plans to drill 16 wells, of which nine will be horizontal
wells.

DAVIS FIELD. The Davis Field is located 42 miles northeast of Laurel in the
northern part of the Mississippi salt basin. Denbury operates 36 producing wells
within the area. Davis is a compact anticline that has produced over 21 MMBbls
since its discovery by Conoco in 1969. Over 30 sands have produced oil between
the intervals of 5,000 feet and 8,000 feet. At the time of acquisition in 1993,
the gross production from this field was approximately 700 Bbls/d. During the
month of December 1997, the gross production was approximately 960 Bbls/d with
net production of 870 Bbls/d.

The Davis Field is a relatively mature field and produces large amounts of
saltwater. During December 1997, the field produced an average of approximately
53,000 barrels of saltwater per day, all of which were re-injected into the
ground. The Company places considerable emphasis on controlling operating costs
in this field by minimizing the cost of saltwater disposal and pumping
equipment.

Since acquiring the majority of the Davis Field in 1993, Denbury has
undertaken an active redevelopment program including numerous workovers and five
development wells. As a result of this work and continued reductions in
operating costs, the Company has been able to steadily increase the proven
reserves every year. During 1996, the Company drilled two successful horizontal
wells to improve withdrawal efficiency and drilled an additional three
horizontal wells in 1997, with one additional well in progress as of December
31, 1997. The Company plans to drill five wells in this field in 1998 of which
four will be horizontal wells.

QUITMAN FIELD. The Quitman Field is located in Clarke County, Mississippi,
31 miles northeast of Laurel and near the Davis Field. The Company acquired the
field as part of the Hess Acquisition and now operates 18 producing wells. The
Company owns an average working interest of 93%. The Quitman Field was
discovered in 1966 and has since produced approximately 21 MMBbls from 18
separate reservoirs between 7,500 feet and 12,000 feet. The principal producing
zones at Quitman Field are the Smackover formation and several sands in the
Cotton Valley formation.

Since its acquisition in May, 1996, the Company has implemented a capital
expenditure program at Quitman Field which has included upgrading production
facilities and drilling wells. At the time of acquisition, the net production
from this field was approximately 200 Bbls/d. During December 1997, the net
production averaged 1,676 Bbls/d. All five wells drilled in 1997 were
successful, of which two were horizontal wells. During 1998, the Company plans
to drill four wells, of which three will be horizontal wells.

OTHER MISSISSIPPI FIELDS. In addition to the above fields, Denbury owns an
interest in wells in 35 other fields in Mississippi, which in the aggregate
averaged approximately 1,728 Bbls/d and 2.5 MMcf/d of net production during
December 1997.

LOUISIANA OPERATING AREA

The Company's southern Louisiana producing fields are typically large
structural features containing multiple sandstone reservoirs. Current production
depths range from 7,000 feet to 16,000 feet with potential throughout the area
for even deeper production. The region produces predominantly natural gas, with
most reservoirs producing with a water-drive mechanism.

The majority of the Company's southern Louisiana fields lie in the Houma
embayment area of Terrebonne and LaFourche Parishes. The area is characterized
by complex geological structures which have produced prolific reserves, typical
of the lower Gulf Coast geosyncline. Given the swampy conditions of southern
Louisiana, 3-D seismic has only recently become feasible for this area as
improvements in field recording techniques have made the process more
economical. 3-D seismic has become a valuable tool in exploration and
development throughout the onshore Gulf Coast and has been pivotal in
discovering
41
<PAGE> 42

significant reserves. The Company currently owns or has license to work on over
300 square miles of 3-D seismic data and plans to continue to expand its data
ownership. The Company believes that this 3-D seismic data, some of which is the
first 3-D shot in these swampy areas, has the potential to identify significant
exploration prospects, particularly in the deeper geopressured sections below
12,000 feet.

During 1995, the Company acquired approximately 46 square miles of 3-D
seismic data over five of its existing fields in Southern Louisiana, namely
Bayou Rambio, De Large, North Deep Lake, Gibson and Humphreys. During 1996, the
Company entered into a joint venture agreement with two industry partners and
shot approximately 158 square miles of 3-D seismic data in the Terrebonne Parish
area, which includes three of the Company's existing fields, Lirette, Lapeyrouse
and North Lapeyrouse. The Company's existing productive zones are excluded from
the joint venture. Denbury owns a one-third interest in any new prospects
discovered through this joint venture that currently owns rights to over 35,000
acres within the survey area. The 3-D seismic survey is complete and two wells
have been drilled to date based on the results of the survey. One was a dry hole
and the other a successful well in the Lirette Field area. There are currently
10 identified prospect areas which have been generated as a result of the
survey, of which three should be drilled during the first half of 1998. The 3-D
seismic survey is still being reviewed for additional drilling opportunities.

LIRETTE FIELD. The Lirette structure is a large salt-cored anticline
located about 10 miles south of Houma, Louisiana, which has produced over one
Tcf of natural gas from multiple reservoirs. The field is located in six to ten
feet of inland water and produces from depths of 8,000 feet to 16,000 feet. The
field was discovered in 1937, but in 1993, when the Company first acquired a 23%
working interest in the field, gross production had declined to less than 3
MMcf/d. By January 1995, following a series of workovers of existing wells,
gross production had grown to approximately 13.2 MMcf/d and 360 Bbls/d (6.5
MMcf/d and 150 Bbls/d net). Additional interests were acquired in 1995 and 1997
to increase the Company's ownership to its current average 82% working interest.
During December 1997 the net production from this field averaged approximately
10.6 MMcf/d and 179 Bbls/d from 18 wells.

During the latter half of 1996, the Lirette Field was covered by a 3-D
seismic survey which is currently being evaluated. One well was drilled in the
Lirette area in 1997, the Scana No. 1 Laterre, as a result of this 3-D seismic
survey. This well established two pay sands in the prolific Tex W interval a
southern untested fault block. Two additional untested fault blocks have been
identified on the Lirette structure and are scheduled for drilling during 1998.

GIBSON FIELD. In late 1994, Denbury acquired minor working interests in
five wells in the Gibson and adjacent Humphreys Fields located in Terrebonne
Parish, 20 miles northwest of the Lirette Field, in the northern part of the
Houma embayment. The Gibson Field, since its discovery in 1937, has produced
over 813 Bcf and 14 MMBbls. During 1995, the Company acquired and processed 38
square miles of 3-D seismic data covering these fields and in November 1995
acquired a additional working interest in these fields. By December 1995,
Denbury's acreage position had grown to 3,165 net acres with interests in three
active wells and five inactive wells. During December 1997, the net production
in this field averaged approximately 5.4 MMcf/d and 105 Bbls/d. Denbury drilled
two wells in this area in 1997, one of which was successful. This well, the
Pelican A-12, found two productive intervals and was completed in the lower most
formation. This well produced at an average rate of 442 Mcf/d, net to the
Company, during the month of December 1997. No wells are currently planned in
this field for 1998.

SOUTH CHAUVIN FIELD. In February 1996, the Company purchased interests in
two producing wells and four non-producing wells in South Chauvin Field located
in the Houma embayment area, about four miles south of Houma and six miles
northwest of Lirette Field. Of the four currently producing wells at Chauvin,
the Company owns an average 94% working interest. During December 1997, the net
production from this field averaged 4.2 MMcf/d and 85 Bbls/d. In late 1996, the
Company acquired 13.7 square miles of 3-D seismic data covering the field and is
currently evaluating the data. The Company drilled one well in this area in 1997
which produced at an average rate of 2.9 MMcf/d and 72 Bbls/d, net to the
Company, during the month of December 1997. One well, a sidetrack of an existing
well, is currently planned in this field for 1998.

BAYOU RAMBIO FIELD. Production at the Bayou Rambio Field was established in
1955 and has exceeded 150 Bcf and 920 MBbls to date. The Company operates three
producing wells in the field, which is located in
42
<PAGE> 43

Terrebonne Parish about 15 miles west of Lirette Field. During December 1997,
the net production from this field averaged 7.0 MMcf/d and 53 Bbls/d. Two of
these producing wells were drilled in 1997 based on a review of 3-D seismic
data. The Company has one additional well planned for the first half of 1998
which will attempt to accelerate the production of the established reserves
increasing the field's PV10 Value, while drilling a deeper sand interval which
may establish additional pay sands.

OTHER LOUISIANA FIELDS. In addition to the above fields, the Company owns
an interest in wells at 39 other fields in Louisiana, which in the aggregate
averaged approximately 14.2 MMcf/d and 959 Bbls/d of net production during
December 1997.

ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES

The Company regularly seeks to acquire properties that complement its
operations, provide exploitation, exploration and development opportunities and
have cost reduction potential. The Company has purchased the majority of its
current producing wells and has increased production by a variety of techniques,
including development drilling, increasing fluid withdrawal and reworking
existing wells. These acquisitions have also balanced the Company's reserve mix
between oil and natural gas, increased the scale of its operations in the
onshore Gulf Coast area and provided the Company with a significant base of
operations within its area of geographic focus. Since 1993, aggregate
expenditures to acquire producing properties are approximately $310 million
through September 30, 1997 adjusted for the Chevron Acquisition. The properties
included in the Company's five largest acquisitions make up approximately 84% of
its total proved reserves on a BOE basis as of December 31, 1997. These five
acquisitions are discussed below in the order of their acquisition by the
Company.

MISSISSIPPI ACQUISITION (1993). Effective May 1, 1993, the Company acquired
interests in the Davis, Frances Creek and Lake Utopia Fields in the Mississippi
salt basin for approximately $9.0 million. At the date of acquisition, the
estimated net proved reserves included 2,170 MBbls and 217 MMcf, aggregating to
2.2 MMBOE. From the date of acquisition through September 30, 1997, the Company
produced 1,377 MBOE from the acquired properties and has successfully increased
its ownership in the Davis Field through approximately $4.3 million of
incremental acquisitions. As of December 31, 1997, the estimated net proved
reserves of the properties totaled 3.1 MMBOE, with a PV10 Value of $15.8
million.

LOUISIANA ACQUISITION (1993). Effective October 1, 1993, Denbury acquired
interests in the Lirette, Bayou Rambio, Delarge, Lapeyrouse, Lake Boeuf, North
Deep Lake and Bay Baptiste Fields in southern Louisiana for approximately $9.8
million. Six of the seven fields are situated in the prolific Houma Embayment,
which is located south of Houma and approximately 40 miles south of New Orleans,
Louisiana. This basin contains fields which have produced more than 2 Tcf of gas
since 1930. These fields have established productive sand intervals as shallow
as 1,000 feet to depths in excess of 17,000 feet, with individual well
production rates exceeding 10 MMcf/d.

At the date of acquisition, the net proved reserves included 155 MBbls and
9,137 MMcf, aggregating to 1.7 MMBOE. From the date of acquisition through
September 30, 1997, the Company produced 2,898 MBOE from the acquired
properties. Subsequent to the acquisition, Denbury has successfully completed
approximately $12.7 million in acquisitions of incremental interests in the
Lirette and Bayou Rambio Fields. As of December 31, 1997, the estimated net
proved reserves of the properties were 7.4 MMBOE, with a PV10 Value of $68.7
million.

GIBSON ACQUISITION (1995). In October 1995, Denbury acquired additional
interests in the Gibson and Humphreys Fields in Southern Louisiana for
approximately $10.2 million. At the date of acquisition, the net proved reserves
included approximately 412 MBbls and 9,435 MMcf, aggregating to 2.0 MMBOE. From
the date of acquisition through September 30, 1997, the Company produced 1,285
MBOE from the acquired properties. As of December 31, 1997, the estimated net
proved reserves of the properties were 1.5 MMBOE, with a PV10 Value of $13.9
million.

HESS ACQUISITION (1996). The Company completed several property
acquisitions during 1996, the largest of which was the acquisition of producing
oil and natural gas properties in Mississippi, Louisiana and
43
<PAGE> 44

Alabama, plus certain overriding royalty interests in Ohio, for approximately
$37.2 million from Amerada Hess, effective May 1, 1996. The average daily
production from the properties included in the Hess Acquisition during May and
June 1996, the first two months of ownership, was approximately 2,945 BOE/d. The
average daily production on these properties had increased to 5,373 BOE/d by the
third quarter of 1997. As of December 31, 1997, in the Company's December
Report, the properties acquired in the Hess Acquisition had estimated net proved
reserves of approximately 14.2 MMBOE with a PV10 Value of $95.0 million. This
compares to approximately 5.9 MMBOE of net proved reserves and a $43.1 million
PV10 Value on these same properties as reported in the July Report. The December
Report was calculated using year-end prices which were based on a WTI price of
$16.18 per Bbl and a NYMEX price of $2.58 per Mcf, with these representative
prices adjusted by field to arrive at the appropriate corporate net price, as
compared to oil and gas prices of $20.00 and $2.65, respectively, in the July
Report. In addition to the increase in proved reserves, the Company produced
approximately 1.9 MMBOE from July 1, 1996 through September 30, 1997 with total
net operating income of $23.8 million.

The two largest fields acquired in the Hess Acquisition are the Eucutta and
Quitman Fields which make up approximately 82% of the total Hess Acquisition
PV10 Value. Both fields are in the same vicinity as the Company's previously
existing Mississippi core properties.

CHEVRON ACQUISITION (1997). On December 30, 1997, the Company acquired oil
properties in the Heidelberg Field, Jasper County, Mississippi, from Chevron for
approximately $202.0 million. The Chevron Acquisition represents the largest
acquisition by the Company to date. The Heidelberg Field is adjacent to the
Company's other primary oil properties in Mississippi and includes 122 producing
wells, 96 of which the Company will operate. The Company purchased an average
working interest of 94% and an average net revenue interest of 81% in these 96
wells, which wells account for approximately 99% of the field's current average
net daily production. The average net daily production from these properties
during the third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d.

The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75.0 million of the purchase price to unevaluated
properties.

44
<PAGE> 45

PRODUCTION VOLUMES, SALES PRICES AND PRODUCTION COSTS

The following table summarizes the Company's net oil and natural gas
production volumes, average sales prices and production costs for each of the
years in the three-year period ended December 31, 1996 and for the nine month
periods ended September 30, 1996 and 1997.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------ ---------------------------------
PRO FORMA PRO FORMA
1994 1995 1996 1996(A) 1996 1997 1997(A)
------ ------ ------ --------- -------- -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
NET PRODUCTION VOLUME:
Oil (MBbls)............ 489 728 1,500 2,752 967 2,079 2,873
Natural gas (MMcf)..... 3,326 4,844 8,933 9,178 6,540 9,299 9,459
Oil equivalent (MBOE).. 1,043 1,535 2,989 4,282 2,057 3,629 4,449
AVERAGE SALE PRICES:
Oil ($/Bbl)............ $13.84 $14.90 $18.98 $18.75 $18.05 $17.53 $17.45
Natural gas ($/Mcf).... 1.78 1.90 2.73 2.72 2.64 2.54 2.54
Oil equivalent
($/BOE)............. 12.17 13.05 17.69 17.88 16.87 16.56 16.65
AVERAGE PRODUCTION COSTS:
Per BOE................ $ 4.13 $ 4.42 $ 4.51 $ 4.70 $ 4.47 $ 4.34 $ 4.71
</TABLE>

- ---------------

(a) Pro forma for the Chevron Acquisition. See "-- Acquisitions of Oil and
Natural Gas Properties" and "Unaudited Pro Forma Consolidated Financial
Information."

OIL AND NATURAL GAS ACREAGE

The following table sets forth the Company's acreage position as of
December 31, 1996:

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
--------------- ---------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Louisiana........................................... 29,328 20,374 10,137 7,812
Mississippi......................................... 17,511 11,138 19,180 8,002
Other............................................... 1,710 1,260 1,709 722
------ ------ ------ ------
Total..................................... 48,549 32,772 31,026 16,536
====== ====== ====== ======
</TABLE>

The following table sets forth the Company's acreage position as of
September 30, 1997:

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
--------------- ---------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Louisiana........................................... 28,519 19,870 20,542 10,668
Mississippi......................................... 17,102 12,655 27,185 10,970
------ ------ ------ ------
Total..................................... 45,621 32,525 47,727 21,638
====== ====== ====== ======
</TABLE>

PRODUCTIVE WELLS

The following table sets forth the Company's gross and net productive wells
as of December 31, 1996:

<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS WELLS TOTAL
------------- ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Louisiana................................... 44 24.8 66 38.1 110 62.9
Mississippi................................. 142 106.0 28 14.8 170 120.8
Other....................................... 4 2.0 12 5.3 16 7.3
--- ----- --- ---- --- -----
Total............................. 190 132.8 106 58.2 296 191.0
=== ===== === ==== === =====
</TABLE>

45
<PAGE> 46

The following table sets forth the Company's gross and net productive wells
as of September 30, 1997:

<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS WELLS TOTAL
------------- ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Louisiana................................... 40 25.7 70 43.2 110 68.9
Mississippi................................. 154 132.5 21 7.2 175 139.7
--- ----- --- ---- --- -----
Total............................. 194 158.2 91 50.4 285 208.6
=== ===== === ==== === =====
</TABLE>

DRILLING ACTIVITY

The following table sets forth the results of drilling activities during
each of the three years in the period ended December 31, 1996 and the nine
months ended September 30, 1997. No wells were in the process of drilling at
September 30, 1997.

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
----------------------------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------------- ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EXPLORATORY WELLS:
Productive..................... -- -- -- -- -- -- 2 0.8
Nonproductive.................. 3 0.8 2 1.0 1 1.0 5 2.4
DEVELOPMENT WELLS:
Productive..................... 4 2.9 2 1.5 9 7.9 26 22.7
Nonproductive.................. 1 1.0 -- -- -- -- 2 1.1
---- ---- ---- ---- ---- ---- ---- ----
Total.................. 8 4.7 4 2.5 10 8.9 35 27.0
==== ==== ==== ==== ==== ==== ==== ====
</TABLE>

PRODUCT MARKETING

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 in finding a market for its product as it becomes
available or in transporting its product to these markets.

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. 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 73% of the Company's oil production in 1996, is
primarily light sour crude and sells at a discount to the published WTI posting.
The balance of the oil production, Louisiana oil, is primarily light sweet
crude, which typically sells at a slight premium to the WTI posting.

The Company is currently selling a majority of its oil under a two-year
contract to Hunt Refining which expires on April 1998 and is currently receiving
a premium to the posted price in this contract. The Company may not be able to
renew this contract in the future or may not be able to obtain terms as
favorable as those in the existing contract.

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. For 1995, the Company entered into financial
contracts to hedge 75% of the Company's net natural gas production and 43% of
the Company's net oil production. The net effect of these hedges was to increase
oil and natural gas revenues by approximately $750,000 during 1995. The Company
does not currently have any hedging contracts in place, although it may enter
into such contracts in the future.
46
<PAGE> 47

SIGNIFICANT OIL AND NATURAL GAS PURCHASERS

Oil and natural 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's operations. For
the period ended December 31, 1996, the Company sold 10% or more of its net
production of oil and natural gas to the following purchasers: Natural Gas
Clearinghouse (20%), Penn Union Energy Services (19%), Enron Trading &
Transportation (13%) and Hunt Refining (15%).

TITLE TO PROPERTIES

Customarily in the oil and natural 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.

COMPETITION

The oil and natural gas industry is highly competitive in all its phases.
The Company encounters strong competition from many other energy companies in
acquiring economically desirable producing properties and drilling prospects and
in obtaining equipment and labor to operate and maintain its properties. In
addition, many energy companies possess greater resources than the Company. See
"Risk Factors -- Competition."

GEOGRAPHIC SEGMENTS

All of the Company's operations are in the United States.

OFFICE AND FIELD FACILITIES

The Company leases its executive and administrative offices in Dallas,
Texas, consisting of approximately 25,000 square feet, under a lease that
continues through May 1999. On August 6, 1997, the Company entered into a ten
year office lease for approximately 50,000 square feet to replace its current
corporate headquarters. This new lease is expected to commence late in 1998.

EMPLOYEES

At January 15, 1998, the Company had 183 employees associated with its
operations, including 69 field personnel in Mississippi and 35 field personnel
in Louisiana. None of the Company's employees is represented by a union. The
Company considers its employee relations to be satisfactory.

LEGAL PROCEEDINGS

From time to time, the Company is a party to legal proceedings in the
ordinary course of its business, including actions for personal injury and
property damage occurring as a result of the operation of wells, and claims for
environmental damage. In June of 1997, a well blow-out occurred at the Lake
Chicot Field, for which the Company is operator, in St. Martin Parish, Louisiana
in which four individuals that were employees of other third party entities were
killed, none of whom were employees or contractors of the Company. In connection
with this blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al
.v. Mallard Bay Drilling L.L.C., Parker Drilling Company and Denbury Management,
Inc., Case No. 58226-G in the 16th Judicial District Court in St. Martin Parish,
Louisiana alleging various defective and dangerous conditions violation of
certain rules and regulations and acts of negligence. The Company believes that
all litigation to which it is a party is covered by insurance and none of such
legal proceedings can be reasonably expected to have a material adverse effect
on the Company's financial condition or results of operations. See "Risk
Factors -- Drilling and Operating Risks."
47
<PAGE> 48

REGULATIONS

The availability of a ready market for oil and gas production depends upon
numerous factors beyond the Company's control. These factors include regulation
of natural gas and oil production, federal and state regulations governing
environmental quality and pollution control, state limits on allowable rates of
production by well or proration unit, the amount of natural gas and oil
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
State and federal regulations generally are intended to prevent waste of natural
gas and oil, protect rights to produce natural gas and oil between owners in a
common reservoir, control the amount of natural gas and oil produced by
assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies. The following discussion summarizes the regulation of the
United States oil and gas industry and is not intended to constitute a complete
discussion of the various statutes, rules, regulations and governmental orders
to which the Company's operations may be subject.

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. Each state generally imposes a production or severance tax with
respect to production and sale of crude oil, natural gas and natural gas liquids
within their respective jurisdictions. 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 AND TRANSPORTATION OF NATURAL GAS. Federal
legislation and regulatory controls in the U.S. have historically affected the
price of the natural gas produced by the Company and the manner in which such
production is marketed. The Federal Energy Regulatory Commission (the "FERC")
regulates the interstate transportation and sale for resale of natural gas by
interstate and intrastate pipelines. The FERC previously regulated the maximum
selling prices of certain categories of gas sold in "first sales" in interstate
and intrastate commerce under the Natural Gas Policy Act. Effective January 1,
1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas, which
includes all sales by the Company of its own production. As a result, all sales
of the Company's domestically produced natural gas may be sold at market prices,
unless otherwise committed by contract. The FERC's jurisdiction over natural gas
transportation and gas sales other than first sales was unaffected by the
Decontrol Act.

The Company's natural gas sales are affected by the regulation of
intrastate and interstate gas transportation. In an attempt to restructure the
interstate pipeline industry with the goal of providing enhanced access to, and
competition among, alternative natural gas supplies, the FERC, commencing in
April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have
altered significantly the interstate transportation and sale of natural gas.
Among other things, Order No. 636 required interstate pipelines to unbundle the
various services that they had provided in the past, such as sales, transmission
and storage, and to offer these services individually to their customers. By
requiring interstate pipelines to "unbundle" their services and to provide their
customers with direct access to pipeline capacity held by them, Order No. 636
has enabled pipeline customers to choose the levels of transportation and
storage service they require, as well as to purchase natural gas directly from
third-party merchants other than the pipelines and obtain

48
<PAGE> 49

transportation of such gas on a non-discriminatory basis. The effect of Order
No. 636 has been to enable the Company to market its natural gas production to a
wider variety of potential purchasers. The Company believes that these changes
generally have improved the Company's access to transportation and have enhanced
the marketability of its natural gas production. To date, Order No. 636 has not
had any material adverse effect on the Company's ability to market and transport
its natural gas production. However, the Company cannot predict what new
regulations may be adopted by the FERC and other regulatory authorities, or what
effect subsequent regulations may have on the Company's activities. In addition,
Order No. 636 and a number of related orders were appealed. Recently, the United
States Court of Appeals for the District of Columbia Circuit issued an opinion
largely upholding the basic features and provision of Order No. 636. However,
even though Order No. 636 itself has been judicially approved, several related
FERC orders remain subject to pending appellate review and further changes could
occur as a result of court order or at the FERC's own initiative.

In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate natural gas
pipeline-owned gathering facilities to pipeline affiliates, (ii) the completion
of a rulemaking involving the regulation of interstate natural gas pipelines
with marketing affiliates under Order No. 497, (iii) FERC's on-going efforts to
promulgate standards for pipeline electronic bulletin boards and electronic data
exchange, (iv) a generic inquiry into the pricing of interstate pipeline
capacity, (v) efforts to refine FERC's regulations controlling the operation of
the secondary market for released interstate natural gas pipeline capacity, and
(vi) a policy statement regarding market-based rates and other non-cost-based
rates for interstate pipeline transmission and storage capacity. Several of
these initiatives are intended to enhance competition in natural gas markets.
While any resulting FERC action would affect the Company only indirectly, the
ongoing, or, in some instances, preliminary evolving nature of these regulatory
initiatives makes it impossible at this time to predict their ultimate impact
upon the Company's activities.

OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. Commencing in October 1993, the FERC has modified its regulation
of oil pipeline rates and services in order to comply with the Energy Policy Act
of 1992. That Act mandated that FERC streamline oil pipeline ratemaking by
abandoning its old, cumbersome procedures and issue new procedures to be
effective January 1, 1995. In response, the FERC issued a series of rules (Order
Nos. 561 and 561-A) establishing an indexing system under which oil pipelines
will be able to change their transportation rates, subject to prescribed ceiling
levels. The FERC's new oil pipeline ratemaking methodology was recently affirmed
by the Court. The Company is not able at this time to predict the effects of
Order Nos. 561 and 561-A, if any, on the transportation costs associated with
oil production from the Company's oil producing operations.

GATHERING REGULATIONS. Under the Natural Gas Act (the "NGA"), facilities
used for and operations involving the production and gathering of natural gas
are exempt from FERC jurisdiction, while facilities used for and operations
involving interstate transmission are not. Under current law even facilities
which otherwise would have been classified as gathering may be subject to the
FERC's rate and service jurisdiction when owned by an interstate pipeline
company and when such regulation is necessary in order to effectuate FERC's
Order No. 636 open-access initiatives. FERC has reaffirmed that it does not have
jurisdiction over natural gas gathering facilities and services and that such
facilities and services are properly regulated by state authorities. As a
result, natural gas gathering may receive greater regulatory scrutiny by state
agencies. In addition, the FERC has approved several transfers by interstate
pipelines of gathering facilities to unregulated gathering companies, including
affiliates. This could allow such companies to compete more effectively with
independent gatherers.

State regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements.
While some states provide for the rate regulation of pipelines engaged in the
intrastate transportation of natural gas, such regulation has not generally been
applied against gatherers of natural gas. Natural gas gathering may receive
greater regulatory scrutiny following the pipeline industry restructuring under
Order No. 636. Thus the Company's gathering operations could be

49
<PAGE> 50

adversely affected should they be subject in the future to the application of
state or federal regulation of rates and services. See "Risk
Factors -- Governmental and Environmental Regulation."

ENVIRONMENTAL REGULATIONS. The Company's operations are subject to numerous
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. 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 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.

The EPA and various state agencies have limited the approved methods of
disposal for certain hazardous and nonhazardous wastes. Certain wastes generated
by the Company's oil and natural gas operations that are currently exempt from
treatment as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.

The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Most of
these properties have been operated by prior owners, operators and third parties
whose treatment and disposal or release of hydrocarbons or other wastes was not
under the Company's control. These properties and the wastes disposed thereon
may be subject to Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), Federal Resource Conservation and Recovery Act and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.

The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Certain provisions of CAA may result in
the gradual imposition of certain pollution control requirements with respect to
air emissions from the operations of the Company. The EPA and states have been
developing regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several years for air
pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues.
However, the Company does not believe its operations will be materially
adversely affected by any such requirements.

Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from a spill, including but not
limited to, the costs of responding to a release of oil to surface waters.
Regulations are currently being developed under the OPA and state laws
concerning oil pollution prevention and other matters that may impose additional
regulatory burdens on the Company.

The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as nonhazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or modification of this exemption by administrative, legislative or judicial
process, or through changes in applicable state statutes, would increase the
volume of hazardous waste to be managed and disposed of by the Company.
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Any such

50
<PAGE> 51

change in the applicable statues may require the Company to make additional
capital expenditures or incur increased operating expenses.

Some states have enacted statutes governing the handling, treatment,
storage and disposal of naturally occurring radioactive material ("NORM"). NORM
is present in varying concentrations in subsurface and hydrocarbon reservoirs
around the world and may be concentrated in scale, film and sludge in equipment
that comes in contact with crude oil and natural gas production and processing
streams. Mississippi legislation prohibits the transfer of property for
residential or other unrestricted use if the property contains NORM above
prescribed levels.

The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to the protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
the Company. See "Risk Factors -- Governmental and Environmental Regulation."

TAXATION

Since all of the Company's oil and natural gas operations are located in
the United States, the Company's primary tax concerns relate to U.S. tax laws,
rather than Canadian tax laws. Certain provisions of the United States Internal
Revenue Code of 1986, as amended, are applicable to the petroleum industry.
Current law permits the Company to deduct currently, rather than capitalize,
intangible drilling and development costs ("IDC") incurred or borne by it. The
Company, as an independent producer, is also entitled to a deduction for
percentage depletion with respect to the first 1,000 barrels per day of domestic
crude oil (and/or equivalent units of domestic natural gas) produced by the
Company (if such percentage of depletion exceeds cost depletion). Generally,
this deduction is 15% of gross income from an oil and natural gas property,
without reference to the taxpayer's basis in the property. Percentage depletion
can not exceed the taxable income from any property (computed without allowance
for depletion), and is limited in the aggregate to 65% of the Company's taxable
income. Any depletion disallowed under the 65% limitation, however, may be
carried over indefinitely. For additional tax disclosures, see Note 4 of the
Consolidated Financial Statements.

51
<PAGE> 52

MANAGEMENT

The names of the directors and officers of the Company, their ages, the
offices held by them with the Company and the periods during which such offices
have been held are set forth below. Each officer and director holds office for
one year or until his death, resignation or removal or until his successor is
duly elected and qualified. The officers set forth below hold the same position
in both DRI and DMI unless otherwise noted.

<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
Ronald G. Greene(a)(b)(c)(d)................ 48 Chairman of the Board of DRI
Wilmot L. Matthews(a)....................... 61 Director of DRI
William S. Price, III(b)(c)(d).............. 40 Director of DRI
David M. Stanton............................ 34 Director of DRI
Wieland F. Wettstein(a)..................... 47 Director of DRI
David Bonderman............................. 54 Director of DRI
Gareth Roberts.............................. 45 President, Chief Executive Officer and
Director of DRI and DMI
Matthew Deso................................ 44 Vice President, Exploration and Director
of DMI
Phil Rykhoek................................ 41 Chief Financial Officer and Secretary and
Director of DMI
Mark A. Worthey............................. 40 Vice President, Operations and Director of
DMI
Bobby J. Bishop............................. 37 Controller and Chief Accounting Officer
Ron Gramling................................ 52 President of DMI marketing subsidiary
Lynda Perrard............................... 54 Vice President, Land of DMI
</TABLE>

- ---------------

(a) Member of the Audit Committee.

(b) Member of the Compensation Committee.

(d) Member of the Stock Purchase Plan Committee.

Ronald G. Greene is the Chairman of the Board, and has been a director of
the Company since 1995. Mr. Greene is the founder and Chairman of the Board of
Renaissance Energy Ltd. and was Chief Executive Officer of Renaissance from its
inception in 1974 until May 1990. He is also the sole shareholder, officer and
director of Tortuga Investment Corp., a private investment company. Mr. Greene
also serves on the Board of Directors of a private Western Canadian airline.

Wilmot L. Matthews was first elected as director of the Company on December
9, 1997. Mr. Matthews, a Chartered Accountant, has been involved in all aspects
of investment banking by serving in various positions with Nesbitt Burns Inc.
and its predecessor companies from 1964 until his retirement in September 1996,
most recently as Vice Chairman and Director. Mr. Matthews is currently President
of Marjad Inc., a personal investment company, and also serves on the Board of
Directors of Renaissance Energy Ltd. and several private companies.

William S. Price, III has been a director of the Company since 1995. Mr.
Price is a co-founder and principal of TPG. Prior to forming TPG in 1992, Mr.
Price was vice-president of strategic planning and business development for G.E.
Capital, and from 1985 to 1991 was employed by the management consulting firm of
Bain & Company, attaining officer status and acting as co-head of the Financial
Services practice. Mr. Price is Chairman of the Board of Favorite Brands
International, Inc. and Co-Chairman of the Board of Beringer Wine Estates. Mr.
Price also serves on the Board of Directors of Continental Airlines, Inc.,
Continental Micronesia, Inc., VSP Holdings, Inc., Belden & Blake Corporation and
Del Monte Foods.

52
<PAGE> 53

David M. Stanton has been a director of the Company since 1995. Mr. Stanton
is a managing director of TPG. From 1991 until he joined TPG in 1994, Mr.
Stanton was a venture capitalist with Trinity Ventures where he specialized in
information technology, software and telecommunications investments. Mr. Stanton
also serves on the Board of Directors of TPG Communications, Inc., Paradyne
Partners, L.P. and Belden & Blake Corporation.

Wieland F. Wettstein has been a director of the Company since 1990. Mr.
Wettstein is the Executive Vice President of, and indirectly controls 50% of,
Finex Financial Corporation Ltd., a merchant banking company in Calgary,
Alberta, a position he has held for more than five years. Mr. Wettstein serves
on the Board of Directors of a public oil and natural gas company, BXL Energy,
and on the Board of Directors of a private technology firm.

David Bonderman has been a director of the Company since 1996. Mr.
Bonderman is a co-founder and principal of TPG. Prior to forming TPG in 1992,
Mr. Bonderman was the Chief Operating Officer of the Robert M. Bass Group, Inc.
(now doing business as Keystone, Inc.), joining them in 1983. Keystone, Inc. is
the personal investment vehicle of Fort Worth, Texas-based investor Robert M.
Bass. Mr. Bonderman serves on the boards of Continental Airlines; Inc.; Beringer
Wine Estates; Credicom Asia; Bell & Howell Company; Ryanair, Limited; Virgin
Cinemas, Limited; Ducati Motors S.P.A.; and Washington Mutual, Inc.

Gareth Roberts -- President, Chief Executive Officer and a Director, is the
founder of DMI, which was founded in April 1990. Mr. Roberts has more than 20
years of experience in the exploration and development of oil and natural gas
properties with Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc.
His expertise is particularly focused in the Gulf Coast region where he
specializes in the acquisition and development of old fields with low
productivity. Mr. Roberts holds honors and masters degrees in Geology and
Geophysics from St. Edmund Hall, Oxford University. Mr. Roberts also serves on
the Board of Directors of Belden & Blake Corporation.

Matthew Deso -- Vice President, Exploration, has been with the Company
since October 1990, first as a consultant then, when he moved to Dallas in
January 1994, as Vice President of Exploration, his current position. Mr. Deso
has twenty years of petroleum geology experience, and received a Bachelor of
Science in Geosciences from the University of Texas in 1976. Mr. Deso also
worked for Enserch Exploration (three years), Terra Resources (three years) and
TXO Production Corp. (eight years) in positions of varying responsibility.

Phil Rykhoek -- Chief Financial Officer, a Certified Public Accountant,
joined the Company and was appointed to the position of Chief Financial Officer
and Secretary in June 1995. Prior to joining the Company, Mr. Rykhoek was
Executive Vice President and co-founder of Petroleum Financial, Inc., a private
company formed in May 1991 to provide oil and natural gas accounting services on
a contract basis to other entities. From 1982 to 1991 (except for 1986), Mr.
Rykhoek was employed by Amerac Energy Corporation (formerly Wolverine
Exploration Company), most recently as Vice President and Chief Accounting
Officer. He retained his officer status during his tenure at Petroleum
Financial, Inc.

Mark A. Worthey -- Vice President, Operations, is a geologist and is
responsible for all aspects of operations in the field. He joined the Company in
September 1992. Previously, he was with Coho Resources, Inc. as an exploitation
manager, beginning his employment there in 1985. Mr. Worthey graduated from
Mississippi State University with a Bachelor of Science degree in petroleum
geology in 1984.

Bobby J. Bishop -- Controller and Chief Accounting Officer, a Certified
Public Accountant, joined the Company as Controller in August 1993 and was
appointed to the position of Chief Accounting Officer in December, 1997. Prior
to joining the Company, Mr. Bishop was the Chief Financial Officer for Arcadia
Exploration and Production Company, a private company. He also worked for Lake
Ronel Oil Company and TXO Production Corp. Mr. Bishop graduated from the
University of Oklahoma with a Bachelor of Business Administration in Accounting
in 1983.

Ron Gramling -- President of DRI's marketing subsidiary, joined the Company
in May 1996 when the Company purchased the subsidiary's assets. Prior to
becoming affiliated with the Company, he was employed by Hadson Gas Systems as
Vice President of term supply. Mr. Gramling has 27 years of marketing,
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<PAGE> 54

transportation and supply experience in the natural gas and crude oil industry.
He received his Bachelor of Business Administration degree from Central State
University, Edmond, Oklahoma in 1970.

Lynda Perrard -- Vice President, Land of DMI, joined the Company in April
1994. Ms. Perrard has over 30 years of experience in the oil and gas industry as
a petroleum landman. Prior to joining the Company, Ms. Perrard was the President
and Chief Executive Officer of Perrard Snyder, Inc., a corporation performing
contract land services. Ms. Perrard also served as Vice President, Land for
Snyder Exploration Company from 1986 to 1991.

As part of the Securities Purchase Agreement that governed the TPG's
initial investment in the Company, TPG has the right to designate three of seven
nominees to serve on the Board of Directors of the Company. It was also intended
by the parties to the agreement that Mr. Ronald G. Greene would be nominated to
serve as one of the seven directors and that the remaining three directors would
be nominated by the Company. TPG will forfeit its right to designate one of the
directors that it would otherwise be entitled to designate if at any time TPG
owns securities of the Company representing less than 30% of the outstanding
Common Shares, calculated on a fully-diluted basis. TPG shall forfeit its right
to designate any director if at any time TPG's share holdings represent less
than 20% of the outstanding Common Shares, calculated on a fully-diluted basis.
Currently, Messrs. Stanton, Bonderman and Price are the directors of the Company
nominated by TPG.

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<PAGE> 55

PRINCIPAL SHAREHOLDERS

The following table sets forth information, as of December 31, 1997,
concerning beneficial ownership of the Common Shares before and after giving
effect to the Transactions for: (i) any shareholders known to the Company to
beneficially own more than 5% of the issued and outstanding Common Shares; and
(ii) all executive officers and directors individually and as a group. Except as
otherwise indicated and except for those Common Shares that are listed as being
beneficially owned by more than one shareholder, each shareholder identified in
the table has sole voting and investment power with respect to their Common
Shares.

<TABLE>
<CAPTION>
BENEFICIAL
OWNERSHIP
BENEFICIAL OWNERSHIP AS OF AFTER THE
DECEMBER 31, 1997 TRANSACTIONS
-------------------------- ------------
NAME AND ADDRESS OF BENEFICIAL OWNER SHARES PERCENT PERCENT
------------------------------------ ------------ --------- ------------
<S> <C> <C> <C>
Ronald G. Greene................................. 900,900(a) 4.4%(a) 3.6%(a)
Suite 700, 407 -- 2nd Street
Calgary, Alberta T2P 2Y3
David Bonderman.................................. 8,658,038(b) 41.2%(b) 34.7%(b)
201 Main Street, Suite 2420
Ft. Worth, TX 76102
Wilmot L. Matthews............................... 156,250(c) * *
1 First Canadian Place, Suite 5101
Toronto, ON M5X 1E3
William S. Price, III............................ 8,411,038(d) 40.0%(d) 33.7%(d)
600 California Street, Suite 1850
San Francisco, CA 94108
David M. Stanton................................. 2,000(e) * *
Wieland F. Wettstein............................. 83,389(f) * *
Gareth Roberts................................... 498,302(g) 2.4%(g) 2.0%(g)
Phil Rykhoek..................................... 4,422(h) * *
Mark A. Worthey.................................. 79,001(h) * *
Matthew Deso..................................... 25,801(h) * *
Bobby J. Bishop.................................. 2,439 * *
All of the executive officers and directors as a
group (11 persons)............................. 10,413,542(i) 49.3%(i) 41.3%(i)
TPG Advisors, Inc................................ 8,408,038(j) 40.0%(j) 33.7%(j)
201 Main Street, Suite 2420
Ft. Worth, TX 76102
</TABLE>

- ---------------

* Less than 1%.

(a) Includes 30,150 Common Shares held by Mr. Greene's spouse in her retirement
plan, 900 shares held in trust for Mr. Greene's minor children and 520,833
Common Shares held by Tortuga Investment Corp., which is solely owned by
Mr. Greene.

(b) Includes 250,000 Common Shares in a family partnership 100% controlled by
Mr. Bonderman and 625,000 Common Share purchase warrants held by TPG which,
for purposes of this disclosure, are assumed to be exercised. These
warrants were exercised on January 20, 1998. Mr. Bonderman is a director,
executive officer and shareholder of TPG Advisors, Inc., which is the
general partner of TPG GenPar, L.P., which in turn is the general partner
of both TPG Partners, L.P., and TPG Parallel I, L.P., which are the direct
beneficial owners of the remaining securities attributed to Mr. Bonderman.
Mr. Bonderman's beneficial ownership after the Transactions includes the
Common Shares purchased by TPG in the TPG Purchase.

(c) Includes 52,300 Common Shares held by a subsidiary of Marjad Inc., which is
wholly owned by Mr. Matthews, 2,450 Common Shares held in various trusts of
which Mr. Matthews is a trustee and an
55
<PAGE> 56

income beneficiary and 1,500 Common Shares as to which Mr. Matthews holds a
power of attorney but no beneficial interest.

(d) Includes 1,000 Common Shares held by Mr. Price and 2,000 Common Shares held
by Mr. Price's spouse and 625,000 Common Share purchase warrants held by
TPG which, for purposes of this disclosure, are assumed to be exercised.
These warrants were exercised on January 20, 1998. Mr. Price is a director,
executive officer and shareholder of TPG Advisors, Inc., which is the
general partner of TPG GenPar, L.P., which in turn is the general partner
of both TPG Partners, L.P., and TPG Parallel I, L.P., which are the direct
beneficial owners of the remaining securities attributed to Mr. Price. Mr.
Price's beneficial ownership after the Transactions includes the Common
Shares purchased by TPG in the TPG Purchase.

(e) Although Mr. Stanton is not considered to be a "beneficial owner" as that
term is defined by the Commission, Mr. Stanton is a managing director of
TPG.

(f) Includes 76,439 Common Shares held by S.P. Hunt Holdings Ltd., which is
solely owned by a trust of which Mr. Wettstein is a trustee.

(g) Includes 138,330 Common Shares held by a corporation, which is solely owned
by Mr. Roberts, 38,000 Common Shares held in a private charitable
foundation which he and his wife control, and 2,228 Common Shares held by
his wife.

(h) Includes 1,875, 73,250 and 17,500 Common Shares which Mr. Rykhoek, Mr.
Worthey and Mr. Deso, respectively, have the right to acquire pursuant to
stock options which are currently vested or which vest within 60 days of
December 31, 1997.

(i) Includes 92,625 Common Shares which the officers and directors as a group
have the right to acquire pursuant to stock options which are currently
vested or which vest within 60 days of December 31, 1997 and 625,000 Common
Share purchase warrants held by TPG which, for purposes of this disclosure,
are assumed to be exercised. These warrants were exercised on January 20,
1998. Beneficial ownership does include the Common Shares held by
affiliates of TPG, although Mr. Price and Mr. Bonderman, who are directors
of the Company, are not the owners of record of these securities. Mr. Price
and Mr. Bonderman are directors, executive officers and shareholders of TPG
Advisors, Inc., which is the general partner of TPG GenPar, L.P., which in
turn is the general partner of both TPG Partners, L.P. and TPG Parallel I,
L.P., which are the direct beneficial owners of these securities. The
beneficial ownership after the Transactions of the directors and executive
officers as a group includes the Common Shares purchased by TPG in the TPG
Purchase.

(j) Includes 625,000 Common Share purchase warrants held by TPG which, for
purposes of this disclosure, are assumed to be exercised. These warrants
were exercised on January 20, 1998.

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<PAGE> 57

INTERESTS OF MANAGEMENT IN CERTAIN TRANSACTIONS

Other than as described in the paragraphs that follow, there are no
material interests, direct or indirect, of any director, officer or any
shareholder of the Company who beneficially owns, directly or indirectly, or
exercises control or direction over more than 5% of the outstanding Common
Shares, or any known family member, associate or affiliate of such persons,
participating in any transaction within the last three years or in any proposed
transaction that has materially affected or would materially affect the Company,
or any of its subsidiaries. The Company believes that the terms of the
transactions described below were as favorable to the Company as terms that
reasonably could have been obtained from non-affiliated third parties.

TPG INVESTMENTS

In December 1995, the Company closed a $40.0 million private placement of
securities with partnerships that are affiliated with TPG (the "TPG Placement").
The TPG Placement was comprised of: (i) 4.2 million Common Shares issued at
$5.85 per share; (ii) 625,000 warrants at a price of $1.00 per warrant,
entitling the holders thereof to purchase 625,000 Common Shares at $7.40 per
share; and (iii) 1.5 million shares of $10 stated value Convertible First
Preferred Shares, Series A (the "Convertible Preferred"). The shareholders of
the Company at a Special Meeting on October 9, 1996 approved a resolution to
amend the terms of the Convertible Preferred to allow the Company to require a
conversion of the Convertible Preferred at any time. All of the Convertible
Preferred shares were converted into 2,816,372 Common Shares on October 30,
1996. As per the terms of the warrants, the Company is allowed to force
conversion of the warrants after December 21, 1997 if the price of the Common
Shares exceeds $10.00 per share for a period of 40 consecutive trading days. As
of December 31, 1997, TPG is the beneficial owner of 7,783,038 Common Shares,
which represents 38% of the outstanding Common Shares (40% after the exercise of
the warrants on January 20, 1998).

In connection with the TPG Placement, TPG received the right to nominate
three of the directors of the Company out of a maximum of seven. Of the current
directors, Messrs. Bonderman, Price and Stanton were nominated by TPG. See
"Management." In addition, until December 21, 1997, TPG had certain "piggyback"
registration rights which allowed TPG to include all or part of the Common
Shares acquired by TPG in any registration statement of the Company during that
period. Commencing December 21, 1997 and until December 21, 2000, TPG may
request and receive one demand registration whereby TPG may make a written
request to the Company for registration under the Securities Act of the Common
Shares acquired by TPG. Finally, the agreement provides that TPG shall have the
right, but not the obligation, to maintain its pro rata ownership interest in
the equity securities of the Company, in the event that the Company issues any
additional equity securities or securities convertible into Common Shares of the
Company, by purchasing additional securities of the Company on the same terms
and conditions. This right, however, expires should TPG's share holdings
represent less than 20% of the outstanding Common Shares calculated on a
fully-diluted basis. At the request of the NYSE, the Company has agreed to make
the extension of this right subject to shareholder ratification every five years
with the first vote on the matter expected to be at the annual meeting in the
year 2000. TPG waived its right to maintain its pro rata ownership with regard
to the public offering by the Company in October 1996, but did purchase 800,000
Common Shares included in the offering directly from the Company. These Common
Shares were sold for 93.5% of the public offering price, or the same net price
that the remainder of the shares included in the offering were being sold to the
underwriters. TPG has waived its right to maintain its pro rata ownership with
regard to the Equity Offering but is planning to purchase 313,400 shares in the
TPG Purchase at 95.25% of the public offering price, or the same net price that
the remainder of the shares included in the Equity Offering are being sold to
the Underwriters. As of December 31, 1997, after giving pro forma effect to the
Transactions, TPG will be the beneficial owner of 8,721,438 Common Shares, which
represents 34% of the outstanding Common Shares.

In 1995, the Company issued 333,333 Common Shares to Tortuga Investment
Corp. as a financial advisory fee for its services in connection with the TPG
Placement. Tortuga Investment Corp. is a corporation wholly owned by Mr. Ronald
Greene, currently Chairman of the Board of Directors of the Company. Mr. Greene
was not a director of the Company, nor had he held any director or officer
position with the Company, prior to the time of the issuance of such Common
Shares.
57
<PAGE> 58

MODIFICATION OF DEBENTURES

In addition to modifying the terms of the Convertible Preferred at the
special meeting of the shareholders on October 9, 1996, the shareholders
approved the issuance of 7,948 Common Shares in lieu of interest, plus an
additional 308,642 Common Shares to redeem the principal amount of the
outstanding 9.5% Convertible Debentures (the "Debentures") in accordance with
their existing terms. Mr. Ronald G. Greene, Chairman of the Board of Directors,
owned 80% of the Debentures, which were purchased by him at market value prior
to his election to the Board of Directors. These Debentures were redeemed on
October 15, 1996. Mr. Greene also purchased C $1,500,000 of 6 3/4% Convertible
Debentures at market value prior to his election to the Board of Directors that
were converted into 187,500 Common Shares on July 31, 1996 in accordance with
the terms of the 6 3/4% Convertible Debentures.

PURCHASE OF WORKING INTERESTS

In May 1996, the Company purchased oil and natural gas working interests
from four employees for an aggregate consideration of $387,000, which included
$158,000 paid to Mr. Matthew Deso, Vice President of Exploration of the Company,
$133,000 paid to Mr. Mark Worthey, Vice President of Operations of the Company
and $26,000 paid to the spouse of Mr. Gareth Roberts, President and Chief
Executive Officer of the Company. The purchase prices were determined by the
Company based on the present value of the estimated future net revenue to be
generated from the estimated proved reserves of the properties (based on the
prior year's report thereon from Netherland & Sewell) using a 15% discount rate.
The acquisitions were for additional working interests in properties in which
the Company also holds an interest. To the best of the Company's knowledge, none
of the Company's officers or directors have any remaining interests in
properties owned by the Company.

DESCRIPTION OF CAPITAL STOCK

GENERAL

The authorized share capital of DRI consists of an unlimited number of
Common Shares, of which 20,386,683 were issued and outstanding as of December
31, 1997, and two classes of preferred shares, unlimited in number and issuable
in series, none of which is outstanding. In addition to the issued and
outstanding Common Shares, options to purchase 1,550,256 Common Shares and
700,000 warrants were outstanding as of December 31, 1997. An additional 406,620
stock options were granted on January 2, 1998.

There are no limitations imposed by Canadian legislation or regulations or
by the Articles of Continuance or Bylaws of DRI on the right of holders of
either the Common Shares or the Common Share Purchase Warrants who are not
residents of Canada to hold or vote the Common Shares or to hold the Common
Share Purchase Warrants.

COMMON SHARES

The holders of the Common Shares are entitled: (i) to one vote for each
Common Share held at all meetings of shareholders of DRI, other than meetings of
the holders of any other class of shares meeting as a class or the holders of
one or more series of any class of shares meeting as a series; (ii) to any
dividends that may be declared by the Board of Directors thereon; and (iii) in
the event of liquidation, dissolution or winding-up of DRI, are entitled,
subject to the rights of the holders of shares ranking prior to the Common
Shares, to share rateably in such assets of DRI as are available for
distribution. The holders of Common Shares have no pre-emptive rights under
Canadian law or the Articles of Continuance.

At December 31, 1997, 75,000 warrants were outstanding at an exercise price
of C$8.40 expiring on May 5, 2000 and 625,000 warrants were outstanding at an
exercise price of $7.40 expiring on December 21, 1999. The 625,000 warrants held
by TPG were exercised on January 20, 1998. Each warrant entitles the holder
thereof to purchase one Common Share at any time prior to the expiration date.

58
<PAGE> 59

DRI is also required to maintain a continuously effective registration
statement for a two-year period relating to the resale of 705,643 Common Shares,
including 75,000 Common Shares issuable upon the exercise of warrants, which
were issued in two private placements in April and May 1995. An effective
registration statement relating to this requirement is currently on file with
the Commission.

DRI has granted TPG certain demand registration rights and preemptive
rights in connection with the TPG Placement. For a description of these rights,
see "Interests of Management in Certain Transactions." TPG has waived its rights
to maintain its pro rata ownership in connection with the Equity Offering
although they intend to buy 313,400 Common Shares concurrently with the Equity
Offering directly from the Company. These Common Shares will be sold to TPG for
95.25% of the public offering price, the same net price at which the remainder
of the Common Shares included in the Equity Offering are being sold to the
Underwriters.

PREFERRED SHARES

DRI's Articles of Continuance authorize the future issuance of First
Preferred Shares and Second Preferred Shares (collectively, the "Preferred
Shares"), with such designations, rights, privileges, restrictions and
conditions as may be determined from time to time by the Board of Directors.
Accordingly, the Board of Directors is empowered, without shareholder approval,
to issue Preferred Shares with dividend, liquidation, conversion, voting or
other rights that could adversely affect the voting power or other rights of
holders of DRI's Common Shares. In the event of issuance, the Preferred Shares
could be utilized, under certain circumstances, as a method of discouraging,
delaying or preventing a change in control of the Company. Such actions could
have the effect of discouraging bids for DRI and, thereby, preventing
shareholders from receiving the maximum value for their shares. Although the
Company has no present intention to issue any additional Preferred Shares, there
can be no assurance that the Company will not do so in the future. There are no
Preferred Shares currently outstanding.

DESCRIPTION OF CERTAIN INDEBTEDNESS

CREDIT FACILITY

Effective December 29, 1997, the Company restated its Credit Facility with
NationsBank of Texas, N.A., as Administrative Agent, and a syndicate of lenders
pursuant to an agreement (the "Credit Agreement") under which DMI is the
borrower from such lenders. The following is a summary of certain terms of the
Credit Facility and is qualified in its entirety by reference to the Credit
Agreement and the various related documents entered into in connection with the
Credit Facility.

The total commitment under the Credit Facility is $300.0 million, subject
to borrowing base availability. The initial borrowing base under the Credit
Facility is $260.0 million, $95.0 million of which consists of an interim
acquisition financing commitment (the "Acquisition Tranche"). The initial
borrowing base of $260 million will be reduced simultaneously with the issuance
by the Company of any debt or equity securities by an amount equal to the net
proceeds from the issuance of such securities, until such time as the borrowing
base is reduced to the conforming borrowing base of $165.0 million. The interest
rate on the Credit Facility includes a premium so long as the Acquisition
Tranche is outstanding. Such premium is currently 0.25% and will increase 0.25%
each quarter, commencing March 31, 1998, through March 31, 1999 until the
Acquisition Tranche is repaid. The borrowing base in effect under the Credit
Agreement is subject to redetermination semi-annually, at the sole discretion of
the lenders. The borrowing base may be affected from time to time by the
performance of the Company's oil and natural gas properties and changes in oil
and natural gas prices, among other factors. The Company incurs a commitment fee
of up to 0.45% per year on the unused portion of the borrowing base.

Borrowings under the Credit Facility are payable in full on December 29,
2002 and bear interest at the option of the Company at the bank's prime rate or,
depending on the percentage of the borrowing base that is outstanding, at rates
ranging from LIBOR plus 7/8% to LIBOR plus 1 3/8% (plus the applicable premium
in effect when the Acquisition Tranche is outstanding). As of December 31, 1997,
after giving effect to the
59
<PAGE> 60

Transactions, the Company would have had a borrowing base of $165.0 million, of
which $123.9 million was available.

The obligations of DMI as borrower under the Credit Facility will be fully
and unconditionally guaranteed by DRI, DMI's direct corporate parent. In
addition, the Credit Facility will be secured by first priority security
interests in certain oil and natural gas properties which secured the Company's
prior credit facility entered into on May 31, 1996 (excluding the properties
acquired in the Chevron Acquisition) and a pledge of all of the stock of DMI;
provided, however, that if the borrowings outstanding under the Credit Facility
exceed the borrowing base after redetermination on July 1, 1998, the Credit
Facility will be secured by substantially all of the Company's oil and natural
gas properties (including those acquired in the Chevron Acquisition).

The Credit Facility contains certain covenants which, among other things,
restrict the Company's ability to pay dividends and other restricted payments,
incur additional indebtedness, create liens, enter into leases and investments
(including hedging investments), engage in mergers and consolidations or engage
in certain transactions with affiliates. In addition, the Company will be
required to comply with certain financial ratios and tests, including a minimum
tangible net worth test, a current ratio coverage test and an EBITDA to interest
ratio test.

SENIOR SUBORDINATED NOTES

Concurrently with the Equity Offering DMI is offering up to $125.0 million
aggregate principal amount of its 9% Senior Subordinated Notes Due 2008 pursuant
to the Debt Offering. The following is a summary of certain terms of the Notes
and is qualified in its entirely by reference to the Indenture (the "Indenture")
relating to the Notes. A copy of the proposed form of Indenture has been filed
with the Registration Statement of which this Prospectus forms a part.

The Notes will be unsecured senior subordinated obligations of DMI, and
will rank pari passu in right of payment with all existing and future senior
subordinated indebtedness of DMI and will be subordinated to future senior
indebtedness of the Company. The Notes mature on March 1, 2008. The Notes will
bear interest at the rate of 9% per annum and will be payable semi-annually,
commencing on September 1, 1998. The Notes will be fully and unconditionally
guaranteed (the "DRI Guaranty") on a senior subordinated basis by DRI. The
indebtedness represented by the DRI Guaranty will be unsecured senior
subordinated obligations of DRI, and will rank pari passu in right of payment
with all existing and future senior subordinated indebtedness of DRI. In
addition, under certain circumstances, the Notes will in the future be fully and
unconditionally guaranteed on a senior subordinated basis by certain
subsidiaries of DMI.

Except as stated below, the Notes will not be redeemable prior to March 1,
2003. Thereafter, the Notes will be redeemable at the option of DMI, in whole or
in part, at any time or from time to time, at a premium which will be at a fixed
percentage that declines to par on or after March 1, 2006, in each case together
with accrued and unpaid interest, if any, to the date of redemption. In the
event the Company consummates a Stock Offering prior to March 1, 2001, DMI may,
at its option, use all or a portion of the proceeds from such offering to redeem
up to 35% of the original aggregate principal amount of the Notes at a
redemption price equal to 109% of the aggregate principal amount of the Notes to
be redeemed, plus accrued and unpaid interest, if any, thereon to the redemption
date, provided at least $81.0 million aggregate principal amount of the Notes
remains outstanding after each such redemption.

Upon the occurrence of a Change of Control (as defined in the Indenture),
each holder of Notes will have the right to require the Company to purchase all
or a portion of such holder's Notes at a price equal to 101% of the aggregate
principal amount thereof, together with accrued and unpaid interest to the date
of purchase.

The Indenture will contain certain covenants, including covenants that
limit (i) indebtedness, (ii) restricted payments, (iii) distributions from
restricted subsidiaries, (iv) transactions with affiliates, (v) sales of assets
and subsidiary stock (including sale and leaseback transactions), (vi) dividend
and other payment restrictions affecting restricted subsidiaries, and (vii)
mergers or consolidations.
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<PAGE> 61

CANADIAN TAXATION AND THE INVESTMENT CANADA ACT

The following is a summary of the principal Canadian income tax
considerations generally applicable to nonresidents of Canada who hold the
Common Shares as capital property, deal at arm's length with the Company and do
not use or hold and are deemed not to use or hold their Common Shares in the
course of carrying on a business in Canada and do not carry on insurance
business in Canada. This summary has been prepared by reference to the existing
provisions of the Income Tax Act (Canada) (the "Act"), the Income Tax
Regulations (the "Regulations"), all published proposals for the amendment of
the Act and the Regulations to the date hereof and the published administrative
practices of Revenue Canada, the agency that administers the Act. Although this
summary does not specifically address the provincial income tax consequences of
an investment in Common Shares, generally speaking, provincial taxation does not
apply to persons who are not resident in Canada and who do not own or hold
property in the course of carrying on a business in Canada. Apart from changes
to the Act and the Regulations which have been publicly announced to the date
hereof, this summary does not consider the potential for any future alterations
to Canadian income tax legislation.

DISPOSITIONS OF COMMON SHARES

A nonresident of Canada will only be subject to taxation in Canada under
the Act in respect of a disposition of Common Shares if such shares constitute
"taxable Canadian property" to such nonresident. Provided that the Common Shares
are listed on a recognized stock exchange in Canada at the time of a
disposition, they will only constitute "taxable Canadian property" to a holder
if the holder, either alone or together with persons with whom the holder does
not deal at arm's length, owns or at any time in the five years prior to the
date of dispositions, has owned in excess of 25% of the issued and outstanding
shares of a class or series of the capital of the Company. Persons who are
related by blood or marriage, or are subject to common control are deemed to
deal otherwise than at arm's length; other persons may also be considered to be
dealing otherwise than at arm's length in certain circumstances. For the
purposes of determining the 25% threshold, rights or options to acquire Common
Shares will be treated as ownership thereof. Subject to the comments set out
below in respect of the application of the U.S.-Canada Income Tax Convention to
U.S. resident holders, nonresidents whose shares constitute "taxable Canadian
property" will be subject to taxation thereon on the same basis as Canadian
residents. Generally speaking, three-quarters of the excess of the holder's
proceeds of disposition, over the adjusted cost basis of the Common Shares, must
be included in income as a taxable capital gain, to be taxed at prevailing
federal Canadian rates.

Nonresidents whose shares are repurchased by the Company, except in respect
of certain purchases made by the Company in the open market, will give rise to
the deemed payment of a dividend by the Company to the former holder of Common
Shares in an amount equal to the excess paid over the paid-up capital of the
Common Shares so repurchased. Such deemed dividend will be excluded from the
former holders' proceeds of disposition of his Common Shares for the purposes of
computing any capital gain but will be subject to Canadian nonresident
withholding tax in the manner described below under "Dividends." In certain
limited circumstances, a sale by a holder of the Common Shares to a corporation
resident in Canada with which the holder does not deal at arm's length may give
rise to the deemed payment of a dividend, to the extent the amount received in
consideration therefor exceeds the paid-up capital of the Common Shares disposed
thereof.

Pursuant to the U.S.-Canada Income Tax Convention (the "Convention"),
shareholders of the Company who are residents of the U.S. for the purposes of
the Convention and whose shares would otherwise be "taxable Canadian property"
may be exempt from Canadian taxation in respect of any gains on the Common
Shares provided the principal value of the Company is not derived from real
property located in Canada at the time of the disposition. The Company owns no
Canadian real property and the Company has no present intention to acquire
Canadian real property.

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<PAGE> 62

DIVIDENDS

Under the Act, a withholding tax is imposed at the rate of 25% on the
amount of any dividends paid or credited on the Common Shares to a person not
resident in Canada. Pursuant to the Canada U.S.-Canada Income Tax Convention,
the rate of tax on such dividends is reduced to 5% for dividends received by any
U.S. resident corporation who owns in excess of 10% of the voting shares of the
corporation, and to 15% in all other instances.

INVESTMENT CANADA ACT

The Investment Canada Act (the "ICA") prohibits the acquisition of control
of a Canadian business by non-Canadians without review and approval of the
Investment Review Division of Industry Canada, the agency that administers the
ICA, unless such acquisition is exempt from review under the provisions of the
ICA. Investment Review Division of Industry Canada must be notified of such
exempt acquisitions. The ICA covers acquisitions of control of corporate
enterprises, whether by purchase of assets, shares or "voting interests" of an
entity that controls, directly or indirectly, another entity carrying on a
Canadian business. The ICA will have no effect on the acquisition of shares
covered by this Prospectus.

Apart from the ICA, there are no other limitations on the right of
nonresident or foreign owners to hold or vote securities imposed by Canadian law
or the Certificate of Continuance of the Company. There are no other decrees or
regulations in Canada which restrict the export or import of capital, including
foreign exchange controls, or that affect the remittance of dividends, interest
or other payments to nonresident holders of the Company's Common Shares except
as discussed above.

THE FOREGOING DISCUSSION IS A SUMMARY OF THE PRINCIPAL CANADIAN FEDERAL
INCOME AND ESTATE TAX CONSEQUENCES OF THE OWNERSHIP, SALE OR OTHER DISPOSITION
OF THE COMMON SHARES. ACCORDINGLY, INVESTORS ARE URGES TO CONSULT THEIR TAX
ADVISORS WITH RESPECT TO THE CANADIAN INCOME AND ESTATE TAX CONSEQUENCES OF THE
OWNERSHIP AND DISPOSITION OF THE COMMON SHARES, INCLUDING THE APPLICATION AND
EFFECT OF THE LAWS OF ANY STATE, LOCAL, FOREIGN OR OTHER TAXING JURISDICTION.

SERVICE AND ENFORCEMENT OF LEGAL PROCESS

DRI is incorporated under the laws of Canada. Some of the directors,
controlling persons and officers of DRI, as well as the experts named herein,
are residents of Canada and all or substantially all of such persons' assets are
located outside of the United States. As a result, it may be difficult for
holders of Common Shares to effect service within the United States upon the
directors, controlling persons, officers and experts who are not residents of
the United States or to realize in the United States upon judgments of courts of
the United States against such persons and DRI predicated upon civil liability
under the United States federal securities laws. DRI has been advised by its
counsel, Burnet, Duckworth & Palmer, Calgary, Alberta, that there is doubt as to
the enforceability in Canada against DRI or against any of its directors,
controlling persons, officers or experts who are not residents of the United
States, in original actions for enforcement of judgments of United States
courts, of liabilities predicated solely upon United States federal securities
laws.

SHARES ELIGIBLE FOR FUTURE SALE

After giving effect to the Transactions, the Company would have had
25,257,283 Common Shares outstanding as of December 31, 1997 (25,940,863 Common
Shares assuming exercise of the Underwriters' over-allotment option in full).
The Common Shares sold in the Equity Offering will be freely tradeable without
restrictions or further registration under the Securities Act. As of the close
of the Equity Offering, all of the Common Shares beneficially held by TPG will
be "restricted" securities within the meaning of the Securities Act as a result
of TPG being deemed an "affiliate" of the Company under such act. These
"restricted" Common Shares may be publicly sold only if registered under the
Securities Act or sold in accordance with an applicable exemption from
registration, such as that provided by Rule 144.
62
<PAGE> 63

In general, under Rule 144 as currently in effect, a person (or persons
whose shares are aggregated) who has beneficially owned shares for at least one
year, including persons who may be deemed "affiliates" of the Company, would be
entitled to sell within any three-month period a number of shares that does not
exceed the greater of the average weekly trading volume during the four calendar
weeks preceding such sale or 1% of the then outstanding Common Shares. A person
who is deemed not to have been an "affiliate" of the Company at any time during
the 90 days preceding a sale, and who has beneficially owned such shares for at
least two years, would be entitled to sell such Common Shares under Rule 144
without regard to the volume limitations described above. The Company is unable
to estimate the number of Common Shares, if any, that TPG may sell from time to
time under Rule 144, since such number will depend on the future market price
and trading volume for the Common Shares, as well as other factors beyond the
Company's control.

In connection with the Equity Offering, the Company, each of its directors
and executive officers and TPG have agreed not to sell or otherwise dispose of
any Common Shares, including any securities exercisable for or convertible into
Common Shares, for a period of 120 days from the date of this Prospectus,
without the prior written consent of Morgan Stanley & Co. Incorporated. See
"Underwriters."

The Company has granted TPG certain demand and "piggyback" registration
rights with respect to its Common Shares. See "Interests of Management in
Certain Transactions." TPG has waived its right to maintain its pro rata
ownership in connection with the Equity Offering.

An increase in the number of Common Shares that may become available for
sale in the public market may adversely affect the market price prevailing from
time to time of the Common Shares and could impair the Company's ability to
raise additional capital through the sale of its equity securities.

63
<PAGE> 64

UNDERWRITERS

Under the terms and subject to the conditions contained in an underwriting
agreement (the "Underwriting Agreement"), DRI has agreed to sell 4,557,200
Common Shares to a syndicate of underwriters (the "Underwriters"), for whom
Morgan Stanley & Co. Incorporated, Gordon Capital, Inc., Johnson Rice & Company
L.L.C. and Loewen, Ondaatje, McCutcheon USA Limited are acting as
representatives (the "Representatives"), and the Underwriters have severally
agreed to purchase the number of Common Shares set forth opposite their
respective names below:

<TABLE>
<CAPTION>
NUMBER
UNDERWRITERS OF SHARES
------------ ---------
<S> <C>
Morgan Stanley & Co. Incorporated........................... 789,300
Gordon Capital, Inc. ....................................... 789,300
Johnson Rice & Company L.L.C. .............................. 789,300
Loewen, Ondaatje, McCutcheon USA Limited.................... 789,300
A.G. Edwards & Sons, Inc. .................................. 140,000
EVEREN Securities, Inc. .................................... 70,000
Gaines, Berland Inc. ....................................... 70,000
Jefferies & Company Inc. ................................... 70,000
Lehman Brothers Inc. ....................................... 140,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated.......... 140,000
Midland Walwyn Capital Inc. ................................ 70,000
NationsBanc Montgomery Securities LLC....................... 140,000
Nesbitt Burns Securities Inc. .............................. 70,000
PaineWebber Incorporated.................................... 140,000
Petrie Parkmann & Co. ...................................... 70,000
Sanders Morris Mundy Inc. .................................. 70,000
Smith Barney Inc. .......................................... 140,000
Southwest Securities Inc. .................................. 70,000
---------
Total............................................. 4,557,200
=========
</TABLE>

The Underwriting Agreement provides that the obligations of the several
Underwriters to pay for and accept delivery of the Common Shares offered hereby
are subject to the approval of certain legal matters by their counsel and to
certain other conditions. If any of the Common Shares are purchased by the
Underwriters pursuant to the Underwriting Agreement, all such Common Shares
(other than the Common Shares covered by the over-allotment option described
below) must be so purchased.

The Company has been advised by the Representatives that the Underwriters
propose to offer the Common Shares to the public initially at the price to
public set forth on the cover page of this Prospectus and to certain dealers
(who may include the Underwriters) at such price less a concession not to exceed
$0.485 per share. The Underwriters may allow, and such dealers may reallow, a
concession not in excess of $0.10 per share to any other Underwriter or certain
other dealers. After the initial offering of the Common Shares the offering
price and other selling terms may from time to time be varied by the
Underwriters.

The Company has granted to the Underwriters an option to purchase up to
683,580 additional Common Shares at the price to public set forth on the cover
page hereof less underwriting discounts and commissions, solely to cover
over-allotments. Such option may be exercised at any time until 30 days after
the date of this Prospectus. To the extent that the Underwriters exercise such
option, each of the Underwriters will be committed, subject to certain
conditions, to purchase a number of Common Shares proportionate to such
Underwriter's initial commitment as indicated in the preceding table.

Each of the Underwriters has represented and, during the period of six
months after the date hereof, agreed that (a) it has not offered or sold and
will not offer or sell any Common Shares in the United Kingdom except to persons
whose ordinary activities involve them in acquiring, holding, managing or
disposing of
64
<PAGE> 65

investments (as principal or agent) for the purpose of their business or
otherwise in circumstances which have not resulted and will not result in an
offer to the public in the United Kingdom within the meaning of the Public
Offers of Securities Regulations (1995) (the "Regulations"); (b) it has complied
and will comply with all applicable provisions of the Financial Services Act
1986 and the Regulations with respect to anything done by it in relation to the
Common Shares offered hereby in, from or otherwise involving the United Kingdom;
and (c) it has only issued or passed on and will only issue or pass on to any
person in the United Kingdom any document received by it in connection with the
issue of the Common Shares if that person is a kind described in Article 11(3)
of the Financial Services Act 1986 (Investment Advertisements) (Exemptions)
Order 1996, or is a person to whom such document may otherwise lawfully be
issued or passed on.

The Company has agreed to indemnify the Underwriters against certain
liabilities that may be incurred in connection with the offering of the Common
Shares, including liabilities under the Securities Act, or to contribute to
payments that the Underwriters may be required to make in respect thereof.

It is expected that delivery of the Common Shares will be made against
payment therefor on or about the date specified in the last paragraph of the
cover page of this Prospectus, which is the fifth business day following the
date hereof. Under Rule 15c6-1 of the U.S. Securities and Exchange Commission
under the Exchange Act, trades in the secondary market generally are required to
settle in three business days, unless the parties to any such trade expressly
agree otherwise. Accordingly, purchasers who wish to trade Common Shares on the
date hereof or the day thereafter will be required, by virtue of the fact that
the Common Shares initially will settle in T+5, to specify an alternate
settlement cycle at the time of any such trade to prevent a failed settlement.
Purchasers of Common Shares who wish to trade Common Shares on the date hereof
or the day thereafter should consult their own advisor.

In order to facilitate the Equity Offering, the Underwriters may engage in
transactions that stabilize, maintain or otherwise affect the price of the
Common Shares. Specifically, the Underwriters may over-allot in connection with
the Equity Offering, creating a short position in the Common Shares for their
own account. In addition, to cover over-allotments or to stabilize the price of
the Common Shares, the Underwriters may bid for, and purchase, Common Shares in
the open market. Finally, the underwriting syndicate may reclaim selling
concessions allowed to an underwriter or a dealer for distributing the Common
Shares in the Equity Offering, if the syndicate repurchases previously
distributed Common Shares in transactions to cover syndicate short positions, in
stabilization transactions or otherwise. Any of these activities may stabilize
or maintain the market price of the Common Shares above independent market
levels. The Underwriters are not required to engage in these activities, and may
end any of these activities at any time.

The Common Shares being sold in the TPG Purchase are being sold directly to
TPG by the Company. The TPG Purchase is not being made on an underwritten basis,
and the Underwriters of the Equity Offering are not acting on behalf of the
Company, as agents or in any other capacity, in connection therewith. TPG has
agreed to provide, at the closing of the TPG Purchase, an undertaking to the TSE
not to sell any of the Common Shares acquired pursuant to the TPG Purchase for a
period of six months following the acquisition of such Common Shares without the
prior written consent of the TSE. The closing of the TPG Purchase and the Equity
Offering are each conditioned upon, and will occur concurrently with, the
closing of the other.

LEGAL MATTERS

The legality of the securities offered hereby will be passed upon for the
Company by Burnet, Duckworth & Palmer, Calgary, Alberta and Jenkens & Gilchrist,
a Professional Corporation, Houston, Texas. Certain legal matters in connection
with the Offerings will be passed upon for the Underwriters by Osler, Hoskin &
Harcourt, Calgary, Alberta and Cravath, Swaine & Moore, New York, New York.

65
<PAGE> 66

EXPERTS

The consolidated financial statements and financial statement schedule of
the Company as at December 31, 1995 and 1996 and for each of the three years in
the period ended December 31, 1996 included and incorporated by reference in
this Prospectus and elsewhere in the Registration Statement, have been audited
by Deloitte & Touche, Chartered Accountants, Calgary, Alberta, Canada, as stated
in their reports appearing and incorporated by reference in this Prospectus and
elsewhere in the Registration Statement, and have been so included in reliance
upon the reports of such firm given upon their authority as experts in
accounting and auditing.

The statements of revenues and direct operating expenses of Chevron's
working interest in the Heidelberg Fields acquired by the Company for each of
the two years in the period December 31, 1996 and for the nine months ended
September 30, 1997 included in this Prospectus has been so included in reliance
on the report of Price Waterhouse LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting.

The reference to the reports of Netherland, Sewell & Associates, Inc.,
independent petroleum engineers located in Dallas, Texas, contained herein with
respect to the proved reserves, the estimated future net revenue from such
proved reserves, and the discounted present values of such estimated future net
revenue, is made in reliance upon the authority of such firms as experts with
the respect to such matters.

AVAILABLE INFORMATION

The Company is subject to the information requirements of the Exchange Act,
and in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information can be inspected and copied at the public reference facilities
maintained by the Commission at 450 5th Street, N.W., Room 1024, Washington,
D.C. 20549, and at the following regional offices of the Commission: Seven World
Trade Center, 13th Floor, New York, New York 10048 and Citicorp Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661, at prescribed rates. In
addition, such materials filed electronically by the Company with the Commission
are available at the Commission's World Wide Web site at http://www.sec.gov. The
Common Shares are traded on the NYSE and such reports, proxy statements and
other information may be inspected at 20 Broad Street, New York, New York 10005.
The Common Shares are also traded on the TSE and any filings with the TSE may be
inspected at The Exchange Tower, 2 First Canada Plaza, Toronto, Ontario, Canada
M5X 1J2.

The Company has filed with the Commission a Registration Statement on Form
S-3 under the Securities Act, with respect to the securities offered hereby.
This Prospectus does not contain exhibits and schedules and certain other
information which is part of the Registration Statement and which have been
omitted from this Prospectus as permitted by the rules and regulations of the
Commission. Statements contained herein concerning the contents of any contract,
agreement or other document filed as an exhibit to the Registration Statement
are necessarily summaries of such contracts, agreements or documents and are
qualified in their entirety by reference to each such exhibit. The Registration
Statement and the exhibits and schedules forming a part thereof can be obtained
from the Commission.

66
<PAGE> 67

GLOSSARY

The terms defined in this section are used throughout this Prospectus.

ANTICLINE. Geologically positive structure favorable for trapping
hydrocarbons.

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.

COMMERCIAL WELL; COMMERCIALLY PRODUCTIVE WELL. An oil and gas well
which produces oil and natural gas in sufficient quantities such that
proceeds from the sale of such production exceed production expenses and
taxes.

DEVELOPMENT WELL. A developmental well is a well drilled within the
presently proved productive area of an oil or natural gas reservoir, as
indicated by reasonable interpretation of available data, with the
objective of completing that reservoir.

DRY HOLE; DRY WELL; NON-PRODUCTIVE WELL. A well found to be incapable
of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.

EXPLORATORY WELL. An exploratory well is a well drilled either in
search of a new, as-yet undiscovered oil or natural gas reservoir or to
greatly extend the known limits of a previously discovered reservoir.

FARMOUT. An assignment of an interest in a drilling location and
related acreage conditional upon the drilling of a well on that location.

FORMATION. A succession of sedimentary beds that were deposited under
the same general geologic conditions.

GEOPRESSURED. Pressures in excess of the normal increase in pressure
with depth.

GEOSYNCLINE. A regional area of subsidence in which sediments are
accumulated.

GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may
be, in which a working interest is owned.

HORIZONTAL WELLS. Wells which are drilled at angles greater than 70
degrees from vertical.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand BOEs.

MBOE/d. One thousand BOE/d.

MBtu. One thousand Btus.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One thousand cubic feet of natural gas produced per day.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

MMBOE. One million BOEs.

67
<PAGE> 68

MMBtu. One million Btus.

MMcf. One million cubic feet of natural gas.

MMcf/d. One million cubic feet of natural gas produced per day.

NET; NET REVENUE INTEREST. Production or revenue that is owned by the
Company and produced for its interest after deducting royalties and other
similar interests.

NET ACRES OR NET WELLS. The sum of the fractional working interests
owned in gross acres or gross wells.

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, without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax
expense or to depreciation, depletion and amortization, discounted to
present value using an annual discount rate of 10% in accordance with the
guidelines of the Commission.

PRODUCTIVE WELL. A well that is producing oil or natural gas or that
is capable of production.

PROVED DEVELOPED RESERVES. Reserves that can be expected to be
recovered from 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.

PROVED UNDEVELOPED RESERVES. Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion.

ROYALTY INTEREST. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of
costs of production.

Tcf. One trillion cubic feet of natural gas.

UNDEVELOPED ACREAGE. Lease acreage on which wells have not been
participated in or completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of whether such
acreage contains proved reserves.

WORKING INTEREST. The cost-bearing interest in a well or property
which gives the owner the right to drill, produce and conduct operating
activities on the property as well as to a share of production.

68
<PAGE> 69

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1997 (UNAUDITED)

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
DENBURY RESOURCES INC. AND SUBSIDIARIES
Independent Auditors' Report.............................. F-2
Consolidated Balance Sheets............................... F-3
Consolidated Statements of Income......................... F-4
Consolidated Statements of Cash Flows..................... F-5
Consolidated Statement of Changes in Shareholders'
Equity................................................. F-6
Notes to Consolidated Financial Statements................ F-7 thru F-29
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF
CHEVRON PROPERTIES
Report of Independent Accountants......................... F-30
Statements of Revenues and Direct Operating Expenses of
Properties............................................. F-31
Notes to Statement of Revenues and Direct Operating
Expenses of Properties................................. F-32 thru F-34
</TABLE>

F-1
<PAGE> 70

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Denbury Resources Inc.

We have audited the consolidated balance sheets of Denbury Resources Inc.
as at December 31, 1995 and 1996 and the consolidated statements of income,
changes in shareholders' equity and cash flows for each of the years in the
three year period ended December 31, 1996. 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 Canada and the United States of America. Those standards require
that we plan and perform the audit to obtain reasonable assurance 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.

In our opinion, these consolidated financial statements present fairly in
all material respects, the financial position of the Company as at December 31,
1995 and 1996 and the results of its operations and the changes in shareholders'
equity and cash flows for each of the years in the three year period ended
December 31, 1996, in accordance with accounting principles generally accepted
in Canada.

Deloitte & Touche

Chartered Accountants

Calgary, Alberta
February 21, 1997

F-2
<PAGE> 71

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
ASSETS

DECEMBER 31,
------------------- SEPTEMBER 30,
1995 1996 1997
-------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C>
CURRENT ASSETS
Cash and cash equivalents................................ $ 6,553 $ 13,453 $ 2,236
Accrued production receivable............................ 3,212 11,906 7,097
Trade and other receivables.............................. 1,160 3,643 14,507
-------- -------- --------
Total current assets............................. 10,925 29,002 23,840
-------- -------- --------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties........................... 72,510 159,724 230,521
Unevaluated oil and natural gas properties............... 7,085 6,413 6,389
Less accumulated depreciation and depletion.............. (13,982) (31,141) (53,527)
-------- -------- --------
Net property and equipment....................... 65,613 134,996 183,383
-------- -------- --------
OTHER ASSETS............................................... 1,103 2,507 3,201
-------- -------- --------
TOTAL ASSETS..................................... $ 77,641 $166,505 $210,424
======== ======== ========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities................. $ 2,872 $ 10,903 $ 16,858
Oil and gas production payable........................... 1,014 5,550 4,060
Current portion of long-term debt........................ 177 67 23
-------- -------- --------
Total current liabilities........................ 4,063 16,520 20,941
-------- -------- --------
LONG-TERM LIABILITIES
Senior bank debt......................................... 75 125 20,005
Subordinated debt and other notes payable................ 3,399 -- --
Provision for site reclamation costs..................... 242 613 938
Deferred income taxes and other.......................... 1,361 6,743 12,982
-------- -------- --------
Total long-term liabilities...................... 5,077 7,481 33,925
-------- -------- --------
CONVERTIBLE FIRST PREFERRED SHARES, SERIES A
1,500,000 shares authorized, issued and outstanding at
December 31, 1995..................................... 15,000 -- --
-------- -------- --------
SHAREHOLDERS' EQUITY
Common shares, no par value unlimited shares authorized;
outstanding -- 11,428,809, 20,055,757 and 20,364,799
shares at December 31, 1995, December 31, 1996 and
September 30, 1997, respectively...................... 50,064 130,323 132,744
Retained earnings........................................ 3,437 12,181 22,814
-------- -------- --------
Total shareholders' equity....................... 53,501 142,504 155,558
-------- -------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY....... $ 77,641 $166,505 $210,424
======== ======== ========
</TABLE>

See Notes to Consolidated Financial Statements.

Approved by the Board:

<TABLE>
<S> <C>
/s/ GARETH ROBERTS /s/ WIELAND F. WETTSTEIN
- ----------------------------------------------------- -----------------------------------------------------
Gareth Roberts Wieland F. Wettstein
Director Director
</TABLE>

F-3
<PAGE> 72

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(U.S. DOLLARS)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES
Oil, natural gas and related product
sales................................... $12,692 $20,032 $52,880 $34,709 $60,083
Interest income and other.................. 23 77 769 425 986
------- ------- ------- ------- -------
Total revenues..................... 12,715 20,109 53,649 35,134 61,069
------- ------- ------- ------- -------
EXPENSES
Production................................. 4,309 6,789 13,495 9,197 15,737
General and administrative................. 1,105 1,832 4,267 2,825 4,535
Interest................................... 1,146 2,085 1,993 1,530 387
Imputed preferred dividends................ -- -- 1,281 1,153 --
Loss on early extinguishment of debt....... -- 200 440 440 --
Depletion and depreciation................. 4,209 8,022 17,904 12,557 23,224
Franchise taxes............................ 65 100 213 160 308
------- ------- ------- ------- -------
Total expenses..................... 10,834 19,028 39,593 27,862 44,191
------- ------- ------- ------- -------
Income before income taxes................... 1,881 1,081 14,056 7,272 16,878
Provision for federal income taxes........... (718) (367) (5,312) (2,932) (6,245)
------- ------- ------- ------- -------
NET INCOME................................... $ 1,163 $ 714 $ 8,744 $ 4,340 $10,633
======= ======= ======= ======= =======
NET INCOME PER COMMON SHARE
Primary.................................... $ 0.19 $ 0.10 $ 0.67 $ 0.37 $ 0.53
Fully diluted.............................. 0.19 0.10 0.62 0.36 0.50
======= ======= ======= ======= =======
Average number of common shares
outstanding................................ 6,240 6,870 13,104 11,616 20,175
======= ======= ======= ======= =======
</TABLE>

See Notes to Consolidated Financial Statements

F-4
<PAGE> 73

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(AMOUNTS IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ -------------------
1994 1995 1996 1996 1997
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income..................................... $ 1,163 $ 714 $ 8,744 $ 4,340 $ 10,633
Adjustments needed to reconcile to net cash
flow provided by operations:
Depreciation, depletion and amortization..... 4,304 8,113 17,904 12,557 23,224
Deferred income taxes........................ 718 367 5,312 2,932 6,245
Imputed preferred dividend................... -- -- 1,281 1,153 --
Loss on early extinguishment of debt......... -- 200 440 440 --
Other........................................ -- -- 459 345 64
-------- -------- -------- -------- --------
6,185 9,394 34,140 21,767 40,166
Changes in working capital items relating to
operations:
Accrued production receivable................ (986) (1,303) (8,694) (4,388) 4,809
Trade and other receivables.................. (124) (168) (1,508) (659) (10,864)
Accounts payable and accrued liabilities..... 1,581 (1,660) 6,711 9,688 5,955
Oil and gas production payable............... 261 490 4,536 2,004 (1,490)
-------- -------- -------- -------- --------
NET CASH FLOW PROVIDED BY OPERATIONS............. 6,917 6,753 35,185 28,412 38,576
-------- -------- -------- -------- --------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures............. (10,297) (11,761) (38,450) (25,704) (54,700)
Acquisition of oil and natural gas
properties................................. (6,606) (16,763) (48,407) (47,616) (16,073)
Net purchases of other assets................ (122) (560) (1,726) (1,290) (1,238)
Acquisition of subsidiary, net of cash
acquired................................... -- -- 209 209 --
-------- -------- -------- -------- --------
NET CASH USED FOR INVESTING ACTIVITIES........... (17,025) (29,084) (88,374) (74,401) (72,011)
-------- -------- -------- -------- --------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank borrowings.............................. 9,835 19,350 47,900 44,900 19,900
Bank repayments.............................. (2,485) (34,200) (47,900) -- --
Issuance of subordinated debt................ 1,451 1,772 -- -- --
Issuance of common stock..................... 367 26,825 60,664 1,690 2,421
Issuance of preferred stock.................. -- 15,000 -- -- --
Costs of debt financing...................... (122) (493) (411) (408) (33)
Other........................................ 62 (82) (164) (135) (70)
-------- -------- -------- -------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES........ 9,108 28,172 60,089 46,047 22,218
-------- -------- -------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS.................................... (1,000) 5,841 6,900 58 (11,217)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR... 1,712 712 6,553 6,553 13,453
-------- -------- -------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD....... $ 712 $ 6,553 $ 13,453 $ 6,611 $ 2,236
======== ======== ======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest..... $ 1,027 $ 2,127 $ 1,621 $ 1,080 $ 150
SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES:
Conversion of subordinated debt to common
stock...................................... -- -- $ 3,314 $ 1,465 --
Conversion of preferred stock to common
stock...................................... -- -- 16,281 -- --
Assumption of liabilities in acquisition..... -- -- 1,321 1,321 --
</TABLE>

See Notes to Consolidated Financial Statements

F-5
<PAGE> 74

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
(DOLLAR AMOUNTS IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
COMMON SHARES
(NO PAR VALUE)
--------------------- RETAINED
SHARES AMOUNT EARNINGS TOTAL
---------- -------- -------- --------
<S> <C> <C> <C> <C>
BALANCE -- JANUARY 1, 1994........................ 6,208,417 $ 22,872 $ 1,560 $ 24,432
Issued pursuant to employee stock option plan... 96,250 367 -- 367
Net income...................................... -- -- 1,163 1,163
---------- -------- ------- --------
BALANCE -- DECEMBER 31, 1994...................... 6,304,667 23,239 2,723 25,962
---------- -------- ------- --------
Issued pursuant to employee stock option plan... 10,000 54 -- 54
Private placement of Special Warrants
exchanged.................................... 614,143 2,314 -- 2,314
Private placement of common shares.............. 4,499,999 24,457 -- 24,457
Net income...................................... -- -- 714 714
---------- -------- ------- --------
BALANCE -- DECEMBER 31, 1995...................... 11,428,809 50,064 3,437 53,501
---------- -------- ------- --------
Issued pursuant to employee stock option plan... 197,675 1,070 -- 1,070
Issued pursuant to employee stock purchase
plan......................................... 31,311 358 -- 358
Public placement of common shares............... 4,940,000 58,776 -- 58,776
Conversion of preferred stock................... 2,816,372 16,281 -- 16,281
Conversion of warrants.......................... 75,000 460 -- 460
Conversion of subordinated debt................. 566,590 3,314 -- 3,314
Net income...................................... -- -- 8,744 8,744
---------- -------- ------- --------
BALANCE -- DECEMBER 31, 1996...................... 20,055,757 130,323 12,181 142,504
---------- -------- ------- --------
Issued pursuant to employee stock option plan... 270,056 1,764 -- 1,764
Issued pursuant to employee stock purchase
plan......................................... 38,986 657 -- 657
Net income...................................... -- -- 10,633 10,633
---------- -------- ------- --------
BALANCE -- SEPTEMBER 30, 1997 (UNAUDITED)......... 20,364,799 $132,744 $22,814 $155,558
========== ======== ======= ========
</TABLE>

See Notes to Consolidated Financial Statements

F-6
<PAGE> 75

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996 AND FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 1996 AND 1997 (UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES

The Company's operating activities are related to exploration, development
and production of oil and natural gas in the United States. All of the Canadian
operations were sold effective September 1, 1993.

The Company's name was changed on June 7, 1994, from Canadian Newscope
Resources Inc. to Newscope Resources Ltd. and again on December 21, 1995 to
Denbury Resources Inc.

On October 9, 1996 the shareholders of the Company approved an amendment to
the Articles of Continuance to consolidate the number of issued and outstanding
Common Shares on the basis of one Common Share for each two Common Shares
outstanding. All applicable shares and per share data have been adjusted for the
reverse stock split.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles and include the accounts of
the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury
Management, Inc. and Denbury Marine L.L.C. and the Company's equity in the
operation of its 50% owned subsidiary, Denbury Energy Services ("Services"). The
Company acquired the remaining 50% of Services effective May 1, 1996 and began
consolidating all of Services as of that date. 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 the exploration for 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. 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.

F-7
<PAGE> 76
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

d) Ceiling test

The capitalized costs less accumulated depletion, depreciation, related
deferred taxes and site reclamation costs are limited to an amount which is not
greater than the estimated future net revenue from proved reserves using
period-end prices less estimated future site restoration and abandonment costs,
future production-related general and administrative expenses, financing costs
and income taxes, plus the cost (net of impairments) of undeveloped properties.

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.

FOREIGN CURRENCY TRANSLATION

Since 1993 when the Company sold its Canadian oil and natural gas
properties, virtually all of the Company's assets are located in the United
States. These assets and the United States operations are accounted for and
reported in U.S. dollars and no translation is necessary. The minor amount of
Canadian assets and liabilities are translated to U.S. dollars using year-end
exchange rates and any Canadian operations, which are principally minor
administrative and interest expenses, are translated using the historical
exchange rate.

EARNINGS PER SHARE

Net income per common share is computed by dividing the net income
attributable to common shareholders by the weighted average number of shares of
common stock outstanding. In accordance with Canadian generally accepted
accounting principles ("GAAP"), the imputed dividend during 1996 on the
Convertible First Preferred Shares, Series A has been recorded as an operating
expense in the accompanying financial statements and this is deducted from net
income in computing earnings per share. The conversion of the Convertible First
Preferred Shares, Series A ("Convertible Preferred") was anti-dilutive and was
not included in the calculation of earnings per share. In computing fully
diluted earnings per share, the stock options, warrants and convertible debt
instruments were dilutive for the year ended December 31, 1996 and for the nine
months ended September 30, 1997 and were assumed to be converted or exercised as
of the beginning of the respective period with the proceeds used to reduce
interest expense. For the prior years, these instruments were either
anti-dilutive or immaterial. All of the Convertible Preferred and the
convertible debt were converted into common shares during 1996 and thus were not
relevant to the calculation of earnings per share during 1997.

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

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, 1995 and 1996 and September 30, 1997, the Company's aggregate oil
and natural gas imbalances were not material to its financial statements.

F-8
<PAGE> 77
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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. Credit risk relating to these hedges is
minimal because of the credit risk standards required for counter-parties and
monthly settlements. The Company has entered into hedging contracts with only
large and financially strong companies.

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. 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, 1995, December 31, 1996 and September 30, 1997, the
carrying value of the Company's debt and other financial instruments
approximates its fair market value. The Company's bank debt is based on a
floating interest rate and thus adjusts to market as interest rates change. 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.

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.

INTERIM FINANCIAL DATA

In the opinion of management, the accompanying unaudited consolidated
financial statements contain all the adjustments (consisting of only normal
recurring accruals) necessary to present fairly the consolidated financial
position as of September 30, 1997, and the results of its operations and its
cash flow for the nine months ended September 30, 1996 and 1997.

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

F-9
<PAGE> 78
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

summary of the unevaluated properties excluded from oil and natural gas
properties being amortized at December 31, 1995 and 1996 and September 30, 1997
and the year in which they were incurred follows:

<TABLE>
<CAPTION>
DECEMBER 31, 1995 DECEMBER 31, 1996
--------------------------------- ----------------------
INCURRED IN INCURRED IN
------------------------ ----------------------
1993 1994 1995 TOTAL 1995 1996 TOTAL
------ ------ ------ ------ ---- ------ ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Property acquisition cost..... $1,151 $1,230 $2,909 $5,290 $252 $2,614 $2,866
Exploration costs............. -- 1,146 649 1,795 87 3,460 3,547
------ ------ ------ ------ ---- ------ ------
Total............... $1,151 $2,376 $3,558 $7,085 $339 $6,074 $6,413
====== ====== ====== ====== ==== ====== ======
</TABLE>

<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
(UNAUDITED)
----------------------
INCURRED IN
----------------------
1995 1996 1997 TOTAL
---- ------ ------ ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
Property acquisition cost.............................. $-- $ 286 $ 930 $1,216
Exploration costs...................................... 53 1,457 3,663 5,173
--- ------ ------ ------
Total........................................ $53 $1,743 $4,593 $6,389
=== ====== ====== ======
</TABLE>

The Company anticipates that approximately $75 million of the costs
relating to the Chevron Acquisition which closed in December, 1997 will be
classified as unevaluated as of December 31, 1997.

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.

General and administrative costs that directly relate to exploration and
development activities that were capitalized during the period totaled $480,000,
$630,000 and $1,224,000 for the years ended December 31, 1994, 1995 and 1996 and
$851,000 and $1,675,000 for the nine months ended September 30, 1996 and 1997,
respectively.

Amortization per BOE was $4.03, $5.22, $5.99 and $6.40 for the years ended
December 31, 1994, 1995 and 1996 and nine months ended September 30, 1997,
respectively.

3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS

<TABLE>
<CAPTION>
DECEMBER 31,
------------- SEPTEMBER 30,
1995 1996 1997
------ ---- -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
Senior bank loan......................................... $ 100 $100 $ 20,000
Convertible debentures................................... 3,296 -- --
Other notes payable...................................... 255 92 28
------ ---- -------------
3,651 192 20,028
Less portion due within one year......................... (177) (67) (23)
------ ---- -------------
Total long-term debt................................... $3,474 $125 $ 20,005
====== ==== =============
</TABLE>

F-10
<PAGE> 79
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

BANKS

During 1996 the Company entered into a new $150 million credit facility
with NationsBank of Texas, N.A. ("NationsBank"). This refinancing closed on May
31, 1996 and has a borrowing base as of December 31, 1996 of $60 million.

NationsBank is the agent bank and the facility includes two other banks.
The credit facility is a two-year revolving credit facility that converts to a
three year term loan in May 1998, unless renewed or extended. This revolver
conversion date was extended to May 1999 on April 1, 1997. The credit facility
is secured by virtually all the Company's oil and natural gas properties and
interest is payable at either the bank's prime rate or, depending on the
percentage of the borrowing base that is outstanding, ranging from LIBOR plus
7/8% to LIBOR plus 1 3/8%. This credit facility also 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, and (iv) a prohibition of most debt and
corporate guarantees. As of December 31, 1996, the Company had $100,000
outstanding on this line of credit and $645,000 of letters of credit
outstanding.

The Company made two amendments to its bank credit facility during 1997 and
revised and restated its facility in December, 1997. See Note 12 for additional
disclosures.

SUBORDINATED DEBT

On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of
6 3/4% unsecured convertible debentures and on January 17, 1995, Denbury issued
Cdn. $2,500,000 principal amount of 9 1/2% unsecured convertible debentures.
These debentures were converted into 566,590 Common Shares during 1996.

INDEBTEDNESS REPAYMENT SCHEDULE

The Company's indebtedness is repayable as follows:

<TABLE>
<CAPTION>
DECEMBER 31, 1996
-------------------------------------
OTHER NOTES
YEAR BANK LOAN PAYABLE TOTAL
---- --------- ----------- -----
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
1997.............................................. $ -- $67 $ 67
1998.............................................. 17 23 40
1999.............................................. 33 2 35
2000.............................................. 33 -- 33
2001.............................................. 17 -- 17
---- --- ----
$100 $92 $192
==== === ====
</TABLE>

F-11
<PAGE> 80
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
SEPTEMBER 30, 1997 (UNAUDITED)
---------------------------------------
OTHER NOTES
YEAR BANK LOAN PAYABLE TOTAL
---- --------- ----------- -------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
1997........................................... $ -- $ 3 $ 3
1998........................................... -- 23 23
1999........................................... 3,333 2 3,335
2000........................................... 6,667 -- 6,667
2001........................................... 6,667 -- 6,667
2002........................................... 3,333 -- 3,333
------- --- -------
$20,000 $28 $20,028
======= === =======
</TABLE>

4. INCOME TAXES

The Company's tax provision is as follows:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- ------------------
1994 1995 1996 1996 1997
----- ----- ------- ------- -------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Deferred
Federal.................................... $718 $367 $5,312 $2,932 $5,907
State...................................... -- -- -- -- 338
---- ---- ------ ------ ------
Total.............................. $718 $367 $5,312 $2,932 $6,245
==== ==== ====== ====== ======
</TABLE>

Income tax expense for the year varies from the amount that would result
from applying Canadian federal and provincial tax rates to income before income
taxes as follows:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- ------------------
1994 1995 1996 1996 1997
----- ----- ------- ------- --------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Deferred income tax provision calculated
using the Canadian federal and
provincial statutory combined tax rate
of 44.34%............................... $ 834 $ 479 $ 6,233 $3,224 $ 7,484
Increase resulting from:
Imputed preferred dividend.............. -- -- 568 511 --
Non-deductible Canadian expenses........ -- -- 97 64 --
Decrease resulting from:
Effect of lower income tax rates on
United States income................. (116) (112) (1,586) (867) (1,239)
----- ----- ------- ------ -------
$ 718 $ 367 $ 5,312 $2,932 $ 6,245
===== ===== ======= ====== =======
</TABLE>

F-12
<PAGE> 81
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company at December 31, 1996 had net operating loss carryforwards for
U.S. tax purposes of approximately $18,329,000 and approximately $12,485,000 for
alternative minimum tax purposes. The net operating losses are scheduled to
expire as follows:

<TABLE>
<CAPTION>
INCOME ALTERNATIVE
YEAR TAX MINIMUM TAX
---- ------- ------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C>
2004.................................................. $ 39 $ --
2005.................................................. 11 --
2006.................................................. 644 500
2007.................................................. 714 99
2008.................................................. 5,016 4,889
2009.................................................. 3,377 2,868
2010.................................................. 3,467 3,420
2011.................................................. 5,061 710
</TABLE>

5. SHAREHOLDERS' EQUITY

AUTHORIZED

The Company is authorized to issue an unlimited number of Common Shares
with no par value, First Preferred Shares and Second Preferred Shares. The
preferred shares may be issued in one or more series with rights and conditions
as determined by the Directors.

COMMON SHARES

Each Common Share entitles the holder thereof to one vote on all matters on
which holders are permitted to vote. The Texas Pacific Group ("TPG") was granted
a right of first refusal in the private placement (see below), to maintain
proportionate ownership. No stockholder has any right to convert common stock
into other securities. The holders of shares of common stock are entitled to
dividends when and if declared by the Board of Directors from funds legally
available therefore and, upon liquidation, to a pro rata share in any
distribution to stockholders, subject to prior rights of the holders of the
preferred stock. The Company is restricted from declaring or paying any cash
dividend on the Common Shares by its bank loan agreement.

1996 CAPITAL ADJUSTMENTS

During 1996, the Company issued 250,000 Common Shares for the conversion of
the 6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for
the exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10,
1996, the Company effected a one-for-two reverse split of its outstanding common
Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2%
Convertible Debentures ("Debentures") were converted by their holders in
accordance with their terms into 308,642 Common Shares. The holders of the
Debentures also received an additional 7,948 Common Shares in lieu of interest
which would have been due the holders absent an early conversion of the
Debentures. At a special meeting held on October 9, 1996, the shareholders of
the Company approved an amendment to the terms of the First Preferred Shares,
Series A ("Convertible Preferred") to allow the Company to require the
conversion of the Convertible Preferred at any time, provided that the
conversion rate in effect as of January 1, 1999 would apply to any required
conversion prior to that date. The Company converted all of the 1,500,000 shares
of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. The
Company also issued an aggregate of 4,940,000 Common Shares on October 30, 1996
and November 1, 1996 at a net price of $12.035 per share as part of a public
offering for net proceeds to the Company of approximately $58.8 million (the
"Public Offering"). TPG purchased 800,000 of these shares at $12.035 per share.

F-13
<PAGE> 82
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

PRIVATE PLACEMENT OF SECURITIES

In December 1995, the Company closed a $40 million private placement of
securities with partnerships that are affiliated with the Texas Pacific Group
("TPG Placement"). The TPG Placement was comprised of: (i) 4.166 million common
shares issued at $5.85 per share, (ii) 625,000 warrants at a price of $1.00 per
warrant entitling the holder to purchase 625,000 common shares at $7.40 per
share through December 21, 1999 and (iii) 1.5 million shares of $10 stated value
Convertible Preferred. The Convertible Preferred shares were initially
convertible at $7.40 of stated value per common share with such conversion rate
declining 2.5% per quarter. The shares also had a mandatory redemption at a
63.86% premium at December 21, 2000. The Convertible Preferred were converted
into 2,816,372 Common Shares on October 30, 1996. During the period that the
Convertible Preferred were outstanding, the Company made a charge to net income
to accrue the increase during the period in the mandatory redemption premium.
The Company may force conversion of the $7.40 warrants issued in the TPG
Placement after December 21, 1997, if the price of the Common Shares exceeds
$10.00 per share for a period of 40 consecutive days.

As part of the TPG Placement, TPG was granted certain "piggyback"
registration rights which allow TPG to include all or part of the Common Shares
acquired by TPG in any registration statement of the Company during the first
two years. After the initial two years and until December 21, 2000, TPG may
request and receive one demand registration statement to register the Common
Shares acquired by TPG.

The TPG agreement provides that TPG shall have the right, but not the
obligation, to maintain its pro rata ownership interest (after the assumed
exercise of their warrants) in the equity securities of the Company, in the
event that the Company issues any additional equity securities or securities
convertible into Common Shares of the Company, by purchasing additional shares
of the Company on the same terms and conditions. However, this right expires
should TPG's share holdings represent less than 20% of the outstanding Common
Shares. TPG waived its right to maintain its pro rata ownership with regard to
the Equity Offering.

As part of the TPG Placement, Tortuga Investment Corp. was paid a financial
advisor fee of 333,333 Common Shares of the Company. The sole shareholder of
Tortuga Investment Corp. was appointed to the Board of Directors of the Company
and elected Chairman upon the closing of the TPG Placement.

WARRANTS

At December 31, 1996, 75,000 warrants were outstanding at an exercise price
of Cdn. $8.40 expiring on May 5, 2000. TPG holds 625,000 warrants at an exercise
price of $7.40 expiring on December 21, 1999. Each warrant entitles the holder
thereof to purchase one Common Share at any time prior to the expiration date.

SPECIAL WARRANT ISSUES

On April 25, 1995, the Company issued 614,143 Special Warrants at a price
of $4.70 (Cdn. $6.50) per Special Warrant for gross proceeds of $2,750,000
(29,036 Common Share Purchase Warrants were issued to Southcoast Capital
Corporation, as placement agent, in partial payment of their fee). Costs of the
issue were $436,000, resulting in net proceeds to the Company of approximately
$2,314,000. Each Special Warrant was exchanged, at no additional cost, for one
Common Share of Denbury on August 11, 1995.

F-14
<PAGE> 83
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK OPTIONS AND STOCK PURCHASE PLAN

The Company maintains a Stock Option Plan which authorizes the grant of
options of up to 2,243,525 of Common Shares. Under the plan, incentive and
non-qualified options may be issued to officers, key employees and consultants.
The plan is administered by the Stock Option Committee of the Board.

Following is a summary of stock option activity during the years ended
December 31, 1994, 1995 and 1996 and the nine months ended September 30, 1997:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED
------------------------------------------------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------------------- ------------------- --------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE AVERAGE
NUMBER PRICE NUMBER PRICE NUMBER PRICE NUMBER PRICE
------- -------- ------- -------- --------- -------- --------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
OUTSTANDING AT
BEGINNING OF
PERIOD.............. 541,312 $6.68 557,312 $6.30 731,925 $6.11 1,053,000 $ 7.63
Granted............... 138,750 5.64 274,500 5.89 525,500 8.96 750,512 13.64
Terminated............ (26,500) 9.35 (89,887) 7.79 (6,750) 6.28 (21,250) 12.02
Exercised............. (96,250) 3.74 (10,000) 5.42 (197,675) 5.42 (270,056) 6.93
Expired............... -- -- -- -- -- -- -- --
------- ----- ------- ----- --------- ----- --------- ------
OUTSTANDING AT END OF
PERIOD.............. 557,312 $6.30 731,925 $6.11 1,053,000 $7.63 1,512,206 $10.69
======= ===== ======= ===== ========= ===== ========= ======
Options exercisable at
end of period....... 487,937 $6.39 539,675 $6.19 532,375 $6.82 395,222 $ 7.56
======= ===== ======= ===== ========= ===== ========= ======
</TABLE>

<TABLE>
<CAPTION>
WEIGHTED WEIGHTED
OPTIONS OUTSTANDING AS OF OPTIONS AVERAGE WEIGHTED AVERAGE EXERCISABLE AVERAGE
DECEMBER 31, 1996: OUTSTANDING PRICE REMAINING LIFE (YRS.) OPTIONS PRICE
- ------------------------- ----------- -------- --------------------- ----------- --------
<S> <C> <C> <C> <C> <C>
Exercise price of:
$3.65 to $6.99 372,000 $ 5.79 4.3 305,250 $ 5.77
$7.00 to $9.99 444,625 7.78 6.5 175,906 7.70
$10.00 to $14.87 236,375 10.23 9.4 51,219 10.09
</TABLE>

In February 1996, the Company also implemented a Stock Purchase Plan which
authorizes the sale of up to 250,000 Common Shares to all full-time employees
with at least six months of service. 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 Shares of the Company based on its current market value at the
end of the each quarter. The Company recognizes compensation expense for the 75%
Company matching portion, which for 1996 totaled $147,000 and for the nine
months ended September 30, 1997 totaled $282,000. This plan is administered by
the Stock Purchase Plan Committee of the Board.

6. PRODUCT PRICE HEDGING CONTRACTS

In October 1994, the Company entered into two financial contracts
("collars") to hedge 10,000 Mcf/d of natural gas production for calendar year
1995. The first natural gas contract for 8,000 Mcf/d of natural gas had a floor
of $1.845 per MMBTU and a ceiling of $2.095 per MMBTU. The second natural gas
contract was for 2,000 Mcf/d and had a floor of $1.775 per MMBTU and a ceiling
of $1.885 per MMBTU. These contracts covered 75% of the Company's net revenue
interest production in 1995 and increased oil and natural gas revenues by
approximately $800,000 during such period.

In addition, in 1995 the Company entered into two swap contracts for oil.
The first oil contract was for 500 Bbls/d of oil at a price of $17.79 per barrel
of oil commencing on February 1, 1995, and ending on January 31, 1996. The
second oil contract was also for 500 Bbls/d of oil at a price of $18.83, for the
period commencing on April 12, 1995, and ending on December 30, 1995. These
contracts covered 43% of the Company's net revenue interest production for 1995
and decreased oil and natural gas revenues by approximately $47,000 during such
period.

F-15
<PAGE> 84
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company did not have any hedge contracts in place as of December 31,
1996 or September 30, 1997.

7. COMMITMENTS AND CONTINGENCIES

The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1996, and September 30, 1997 long-term
commitments for these items require the following future minimum rental
payments:

<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1996 1997
------------ -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C>
1997............................................. $ 442 $ 123
1998............................................. 441 474
1999............................................. 166 988
2000............................................. -- 1,196
2001............................................. -- 1,192
2002............................................. -- 1,178
------ ------
$1,049 $5,151
====== ======
</TABLE>

On August 6, 1997, the Company entered into a ten year office lease. See
Note 12.

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
and other matters. Although management believes 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 is not currently a party to any litigation which would have a
material impact on its financial statements. However, due to the nature of its
business, certain legal or administrative proceedings may arise in the ordinary
course of its business.

8. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN
CANADA AND THE UNITED STATES

The consolidated financial statements have been prepared in accordance with
GAAP in Canada. The primary differences between Canadian and U.S. GAAP affecting
the Company's consolidated financial statements are as discussed below.

LOSS ON EXTINGUISHMENT OF DEBT AND IMPUTED PREFERRED DIVIDENDS

The most significant GAAP difference relates to the presentation of the
early extinguishment of debt and the imputed dividend on the Convertible
Preferred. During 1996, the Company expensed $1,281,000 relating to the imputed
preferred dividend, as required under Canadian GAAP. Under U.S. GAAP, this
dividend would be deducted from net income to compute the net income
attributable to the common shareholders. The Company also expensed its debt
issue cost relating to the Company's prior bank credit agreements totaling
$200,000 and $440,000 for 1995 and 1996, respectively. Under Canadian GAAP this
is an operating expense, while under U.S. GAAP a loss on early extinguishment of
debt is an extraordinary item. While net income per common share and all balance
sheet accounts are not affected by these differences in GAAP, the net income

F-16
<PAGE> 85
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

for 1995 and 1996 under U.S. GAAP would be $714,000 and $10,025,000,
respectively, while under Canadian GAAP the amounts reported were $714,000 and
$8,744,000, respectively.

EARNINGS PER SHARE

In addition, the methodology for computing earnings per common share is not
consistent between the two countries. For Canadian purposes, dilutive securities
are only considered in the fully diluted presentation of earnings per share and
the proceeds from such dilutive securities are used to reduce debt in the
calculation. Under U.S. GAAP, the proceeds from such instruments are used to
repurchase Common Shares, using a slightly different methodology for the primary
and fully diluted calculations. For the years ended December 31, 1994 and 1995,
the stock options, warrants, convertible debt and the conversion of the
Convertible Preferred were either anti-dilutive or immaterial and were not
included in the earnings per share under either GAAP calculation. For the year
ended December 31, 1996, the Convertible Preferred was still anti-dilutive, but
the stock options, convertible debt and warrants were dilutive and included in
the earnings per share calculations, but with different results under the two
respective GAAP's. Under U.S. GAAP for the year ended December 31, 1996, the
primary earnings per share would be $.64 and the fully-diluted earnings per
share would be $.63 as compared to the $.67 and $.62 as reported under Canadian
GAAP.

For the first nine months of 1996, under U.S. GAAP, the primary and
fully-diluted earnings per common share would be $0.36 and $0.35, compared to
the $0.37 and $0.36, respectively, as reported under Canadian GAAP. Under U.S.
GAAP for the first nine months of 1997, the primary and fully-diluted earnings
per common share would be $0.50 and $0.49, as compared to the $0.53 and $0.50,
respectively, as reported under Canadian GAAP.

During 1996, the Company issued 4,940,000 Common Shares in a public
offering and used a portion of the proceeds to retire bank debt. On a pro forma
basis using U.S. GAAP and assuming that the Common Shares had been issued as of
January 1, 1996 and the interest expense for 1996 relating to the bank debt was
reversed, the primary earnings per share would be $.57 per share. No interest
income was assumed in the pro forma calculation even though the proceeds from
the equity issuance exceeded the bank debt that was retired.

STOCK-BASED COMPENSATION

In 1995, the United States Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for
Stock-Based Compensation." SFAS No. 123 is effective for fiscal years beginning
after December 31, 1995 and requires companies to use recognized option pricing
models to estimate the fair value of stock-based compensation, including stock
options. The Statement requires additional disclosures based on this fair value
based method of accounting for an employee stock option and encourages, but does
not require, companies to recognize the value of these stock option grants as
additional compensation using the methodology of SFAS No. 123. The Company has
elected to continue recognizing expense as prescribed by APB Opinion No. 25,
"Accounting for Stock Issued to Employees", as allowed under SFAS No. 123 rather
than recognizing compensation expense as calculated under SFAS No. 123. As such,
the adoption of SFAS No. 123 during 1996 did not have any effect on the
Company's consolidated financial statements.

F-17
<PAGE> 86
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company has two stock-based compensation plans as more fully described
in Note 5. With regard to its stock option plan, the Company applies APB Opinion
No. 25 in accounting for this plan and accordingly no compensation cost has been
recognized. Had compensation expense been determined based on the fair value at
the grant dates for the stock option grants consistent with the method of SFAS
No. 123, the Company's net income and net income per common share would have
been reduced to the pro forma amounts indicated below:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1996
------- --------
<S> <C> <C>
Net income:
As reported (thousands)................................... $ 714 $8,744
Pro forma (thousands)..................................... 503 8,215
Net income per common share:
As reported............................................... $0.10 $ 0.67
Pro forma................................................. 0.07 0.63
Stock options issued during period (thousands).............. 275 526
Weighted average exercise price............................. $5.90 $ 8.96
Average per option compensation value of options
granted(a)................................................ 2.34 2.95
Compensation cost (thousands)............................... 320 801
</TABLE>

- ---------------

(a) Calculated in accordance with the Black-Scholes option pricing model, using
the following assumptions; expected volatility computed using, as of the
date of grant, the prior three-year monthly average of the Common Shares as
listed on the TSE, which ranged from 32% to 67%; expected dividend
yield -- 0%; expected option term -- 3 years, and risk-free rate of return
as of the date of grant which ranged from 5.3% to 7.8%, based on the yield
of five-year U.S. treasury securities.

DEFERRED INCOME TAXES

Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1995 and 1996 balance sheet dates.
At December 31, 1995, and 1996, all deferred tax assets and liabilities were
computed based on Canadian GAAP amounts and were noncurrent as follows:

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
DECEMBER 31, SEPTEMBER 30,
------------------ -------------
1995 1996 1997
------- ------- -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
Deferred tax assets:
Loss carryforwards............................... $(4,511) $(4,902) $(10,100)
Deferred tax liabilities:
Exploration and intangible development costs..... 5,942 11,645 23,088
------- ------- --------
Net deferred tax liability......................... $ 1,431 $ 6,743 $ 12,988
======= ======= ========
</TABLE>

RECENTLY ISSUED ACCOUNTING STANDARDS

The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants has adopted Statement of Position 96-1,
"Environmental Remediation Liabilities," which provides guidance on the
recognition, measurement, display and disclosure of environmental remediation
liabilities. The Statement is effective for the Company's 1997 fiscal year.
Management evaluated such Statement and believes that it will not have a
material effect on the financial position or results of operations of the
Company.

F-18
<PAGE> 87
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In February 1997 the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 Earnings Per Share, ("SFAS 128")
simplifies the standards for computing earnings per share ("EPS") and makes them
more comparable to international EPS standards. SFAS 128 replaces the
presentation of primary EPS with a presentation of basic EPS. Basic EPS excludes
dilution and is computed by dividing income available to common shareholders by
the weighted average number of common shares outstanding for the period. Diluted
EPS reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised, converted into common stock or
resulted in the issuance of common shares that then shared in the earnings of
the entity. Diluted EPS is computed similarly to fully diluted EPS pursuant to
Accounting Principles Board Opinion No. 15. SFAS 128 is effective for financial
statements issued for periods ending after December 15, 1997, including interim
periods. Earlier application is not permitted. Basic EPS for the year ended
December 31, 1994, 1995 and 1996 and the nine months ended September 30, 1996
and 1997 under SFAS 128 would $0.19, $0.10, $0.67, $0.37, and $0.53 per common
share respectively. This compares to $0.19, $0.10, $0.64, $0.36, and $0.50
respective periods as computed under current U.S. GAAP.

In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for reporting and
display of comprehensive income in the financial statements. Comprehensive
income is the total of net income and all other non-owner changes in equity.
SFAS No. 131 requires that companies disclose segment data based on how
management makes decisions about allocating resources to segments and measuring
their performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of
these standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.

9. 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
period ended December 31, 1996, the Company sold 10% or more of its net
production of oil and natural gas to the following purchasers: Natural Gas
Clearinghouse (20%), Penn Union Energy Services (19%), Enron Oil Trading &
Transportation (13%), and Hunt Refining (15%).

COSTS INCURRED

The following table summarizes costs incurred 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
revenues 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.

F-19
<PAGE> 88
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Costs incurred in oil and natural gas activities for the years ended
December 31, 1994, 1995 and 1996 and the nine months ended September 1997 are as
follows:

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------- ------- ------- -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C>
Property acquisition......................... $ 6,736 $17,198 $48,856 $17,592
Exploration.................................. 1,796 1,687 4,592 14,058
Development.................................. 8,371 9,639 33,409 39,123
------- ------- ------- -------
$16,903 $28,524 $86,857 $70,773
======= ======= ======= =======
</TABLE>

PROPERTY ACQUISITIONS

During April 1996, the Company closed an acquisition of additional working
interests in five Mississippi oil and natural gas properties in which the
Company already owned an interest, plus certain overriding royalty interests in
other areas for approximately $7.5 million (the "Ottawa Acquisition"). The
properties were acquired from Ottawa Energy, Inc., a subsidiary of Highridge
Exploration Ltd.

On April 17, 1996, Denbury entered into a purchase and sale agreement with
Amerada Hess Corporation to purchase producing oil and natural gas properties in
Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in
Ohio, for approximately $37.2 million (the "Hess Acquisition"). The Company
funded this acquisition with bank financing from its NationsBank credit facility
and closed this transaction during June 1996.

These two acquisitions were accounted for under purchase accounting and the
results of operations were consolidated during the second quarter of 1996. Pro
forma results of operations of the Company as if the acquisitions had occurred
at the beginning of each respective period are as follows:

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
-----------------
1995 1996
------- -------
<S> <C> <C>
Revenues (thousands)........................................ $41,273 $61,573
Net income (thousands)...................................... 899 9,820
Net income per common share................................. 0.13 0.75
</TABLE>

In computing the pro forma results, depreciation, depletion and
amortization expense was computed using the units of production method, and an
adjustment was made to interest expense reflecting the bank debt that was
required to fund the acquisitions. The pro forma results reflect an increase of
$250,000 and $500,000 for 1996 and 1995, respectively, in general and
administrative expense for additional personnel and associated costs relating to
the acquired properties, net of anticipated allocations to operations and
capitalization of exploration costs.

F-20
<PAGE> 89
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Hess Acquisition by the Company
and are presented on the full cost accrual basis of accounting. Depreciation,
depletion, and amortization, allocated general and administrative expenses,
interest expense and income, and income taxes have been excluded because the
property interests acquired represent only a portion of a business and these
expenses are not necessarily indicative of the expenses to be incurred by the
Company.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1995 1996
------- ------- -------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product sales............. $17,787 $18,210 $20,165
Direct operating expenses:
Lease operating expense................................ 6,598 7,888 6,302
------- ------- -------
Excess of revenues over direct operating expenses........ $11,189 $10,322 $13,863
======= ======= =======
</TABLE>

The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Ottawa Acquisition by the
Company and are presented on the full cost accrual basis of accounting.
Depreciation, depletion, and amortization, allocated general and administrative
expenses, interest expense and income, and income taxes have been excluded
because the property interests acquired represent only a portion of a business
and these expenses are not necessarily indicative of the expenses to be incurred
by the Company.

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1996
------------
(AMOUNTS IN
THOUSANDS)
<S> <C>
Revenues:
Oil, natural gas and related product sales................ $4,215
Direct operating expenses:
Lease operating expense................................... 760
------
Excess of revenues over direct operating expenses........... $3,455
======
</TABLE>

In November 1995, the Company acquired seven producing wells and certain
non-producing leases in the Gibson/Humphreys Fields of Terrebonne Parish,
Louisiana for approximately $10.2 million.

See also Note 12 for disclosures regarding the Chevron Acquisition made in
December, 1997.

F-21
<PAGE> 90
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Denbury Management, Inc. will be issuing debt securities during early 1998
which will be fully and unconditionally guaranteed by Denbury Resources Inc.
Denbury Holdings Ltd. was merged into Denbury Resources Inc. in December 1997
and is not a guarantor of the debt. Condensed consolidating financial
information for Denbury Resources Inc. and Subsidiaries as of December 31, 1995
and 1996 and September 30, 1997 and for the years ended December 31, 1994, 1995
and 1996 and for the nine months ended September 30, 1996 and 1997 is as
follows:

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS
(IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
DECEMBER 31, 1995
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets.......................... $10,910 $ -- $ 15 $ -- $10,925
Property and equipment (using full cost
accounting)........................... 65,613 -- -- -- 65,613
Investment in subsidiaries (equity
method)............................... -- 71,693 70,130 (141,823) --
Other assets............................ 1,075 -- 1,591 (1,563) 1,103
------- ------- ------- --------- -------
Total assets................... $77,598 $71,693 $71,736 $(143,386) $77,641
======= ======= ======= ========= =======

LIABILITIES AND
STOCKHOLDERS' EQUITY

Current liabilities..................... $ 4,054 $ -- $ 9 $ -- $ 4,063
Long-term liabilities................... 1,851 1,563 3,226 (1,563) 5,077
Convertible First Preferred Shares...... -- -- 15,000 -- 15,000
Shareholders' equity.................... 71,693 70,130 53,501 (141,823) 53,501
------- ------- ------- --------- -------
Total liabilities and
shareholders' equity......... $77,598 $71,693 $71,736 $(143,386) $77,641
======= ======= ======= ========= =======
</TABLE>

F-22
<PAGE> 91
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS
(IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
DECEMBER 31, 1996
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets............................. $ 28,722 $ -- $ 280 $ -- $ 29,002
Property and equipment (using full cost
accounting).............................. 134,996 -- -- -- 134,996
Investment in subsidiaries (equity
method).................................. -- 142,321 140,763 (283,084) --
Other assets............................... 2,505 -- 1,560 (1,558) 2,507
-------- -------- -------- --------- --------
Total assets....................... $166,223 $142,321 $142,603 $(284,642) $166,505
======== ======== ======== ========= ========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current liabilities........................ $ 16,421 $ -- $ 99 $ -- $ 16,520
Long-term liabilities...................... 7,481 1,558 -- (1,558) 7,481
Shareholders' equity....................... 142,321 140,763 142,504 (283,084) 142,504
-------- -------- -------- --------- --------
Total liabilities and shareholders'
equity........................... $166,223 $142,321 $142,603 $(284,642) $166,505
======== ======== ======== ========= ========
</TABLE>

<TABLE>
<CAPTION>
SEPTEMBER 30, 1997 (UNAUDITED)
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets............................. $ 23,453 $ -- $ 387 $ -- $ 23,840
Property and equipment (using full cost
accounting).............................. 183,383 -- -- -- 183,383
Investment in subsidiaries (equity
method).................................. -- 155,174 153,630 (308,804) --
Other assets............................... 3,200 -- 1,545 (1,544) 3,201
-------- -------- -------- --------- --------
Total assets....................... $210,036 $155,174 $155,562 $(310,348) $210,424
======== ======== ======== ========= ========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current liabilities........................ $ 20,937 $ -- $ 4 $ -- $ 20,941
Long-term liabilities...................... 33,925 1,544 -- (1,544) 33,925
Shareholders' equity....................... 155,174 153,630 155,558 (308,804) 155,558
-------- -------- -------- --------- --------
Total liabilities and shareholders'
equity........................... $210,036 $155,174 $155,562 $(310,348) $210,424
======== ======== ======== ========= ========
</TABLE>

F-23
<PAGE> 92
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1994
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $12,714 $ -- $ 1 $ -- $12,715
Expenses................................... 10,607 -- 227 -- 10,834
------- ------- ------- -------- -------
Income (loss) before the following: 2,107 -- (226) -- 1,881
Equity in net earnings of subsidiaries... -- 1,389 1,389 (2,778) --
------- ------- ------- -------- -------
Income before income taxes................. 2,107 1,389 1,163 (2,778) 1,881
Provision for federal income taxes......... (718) -- -- -- (718)
------- ------- ------- -------- -------
Net income................................. $ 1,389 $ 1,389 $ 1,163 $ (2,778) $ 1,163
======= ======= ======= ======== =======
</TABLE>

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $20,107 $ -- $ 460 $ (458) $20,109
Expenses................................... 19,026 -- 460 (458) 19,028
------- ------- ------ --------- -------
Income (loss) before the following: 1,081 -- -- -- 1,081
Equity in net earnings of subsidiaries... -- 714 714 (1,428) --
------- ------- ------ --------- -------
Income before income taxes................. 1,081 714 714 (1,428) 1,081
Provision for federal income taxes......... (367) -- -- -- (367)
------- ------- ------ --------- -------
Net income................................. $ 714 $ 714 $ 714 $ (1,428) $ 714
======= ======= ====== ========= =======
</TABLE>

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $53,631 $ -- $ 179 $ (161) $53,649
Expenses................................... 38,008 -- 1,746 (161) 39,593
------- ------- ------- -------- -------
Income (loss) before the following: 15,623 -- (1,567) -- 14,056
Equity in net earnings of subsidiaries... -- 10,311 10,311 (20,622) --
------- ------- ------- -------- -------
Income before income taxes................. 15,623 10,311 8,744 (20,622) 14,056
Provision for federal income taxes......... (5,312) -- -- -- (5,312)
------- ------- ------- -------- -------
Net income................................. $10,311 $10,311 $ 8,744 $(20,622) $ 8,744
======= ======= ======= ======== =======
</TABLE>

F-24
<PAGE> 93
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DENBURY RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(IN THOUSANDS OF U.S. DOLLARS)

<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1996 (UNAUDITED)
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $35,130 $ -- $ 117 $ (113) $35,134
Expenses................................... 26,507 -- 1,468 (113) 27,862
------- ------- ------- --------- -------
Income (loss) before the following: 8,623 -- (1,351) -- 7,272
Equity in net earnings of subsidiaries... -- 5,691 5,691 (11,382) --
------- ------- ------- --------- -------
Income before income taxes................. 8,623 5,691 4,340 (11,382) 7,272
Provision for federal income taxes......... (2,932) -- -- -- (2,932)
------- ------- ------- --------- -------
Net income................................. $ 5,691 $ 5,691 $ 4,340 $ (11,382) $ 4,340
======= ======= ======= ========= =======
</TABLE>

<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1997 (UNAUDITED)
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $61,066 $ -- $ 105 $ (102) $61,069
Expenses................................... 44,191 -- 102 (102) 44,191
------- ------- ------- --------- -------
Income (loss) before the following: 16,875 -- 3 -- 16,878
Equity in net earnings of subsidiaries... -- 10,630 10,630 (21,260) --
------- ------- ------- --------- -------
Income before income taxes................. 16,875 10,630 10,633 (21,260) 16,878
Provision for federal income taxes......... (6,245) -- -- -- (6,245)
------- ------- ------- --------- -------
Net income................................. $10,630 $10,630 $10,633 $ (21,260) $10,633
======= ======= ======= ========= =======
</TABLE>

11. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

Net proved oil and natural gas reserve estimates as of December 31, 1995
and 1996 were prepared by Netherland & Sewell and the net oil and natural gas
reserve estimates as of December 31, 1994 were prepared by The Scotia Group,
Inc., both 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.
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.

F-25
<PAGE> 94
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ESTIMATED QUANTITIES OF RESERVES

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1994 1995 1996
--------------- --------------- ---------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Balance beginning of year............... 3,583 13,029 4,230 42,047 6,292 48,116
Revisions of previous estimates....... (48) 2,827 830 (1,620) (490) 3,737
Revisions due to price changes........ -- -- -- -- 1,053 402
Extensions, discoveries and other
additions.......................... 640 14,978 732 -- 3,492 5,480
Production............................ (489) (3,326) (728) (4,844) (1,500) (8,933)
Acquisition of minerals in place...... 544 14,539 1,228 12,533 6,205 25,300
----- ------ ----- ------ ------ ------
Balance at end of period................ 4,230 42,047 6,292 48,116 15,052 74,102
===== ====== ===== ====== ====== ======
Proved developed reserves:
Balance at beginning of year.......... 3,418 12,303 3,755 35,578 5,290 34,894
Balance at end of period.............. 3,755 35,578 5,290 34,894 13,371 58,634
</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. 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 carry forwards 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,
-------------------------------
1994 1995 1996
-------- -------- ---------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows................................. $126,129 $214,932 $ 627,476
Future production costs............................. (35,069) (56,323) (134,986)
Future development costs............................ (7,369) (16,154) (28,722)
-------- -------- ---------
Future net cash flows before taxes.................. 83,691 142,455 463,768
10% annual discount for estimated timing of cash
flows.......................................... (31,000) (45,490) (147,670)
-------- -------- ---------
Discounted future net cash flows before taxes....... 52,691 96,965 316,098
Discounted future income taxes...................... (5,763) (15,801) (74,226)
-------- -------- ---------
Standardized measure of discounted future net
cash.............................................. $ 46,928 $ 81,164 $ 241,872
======== ======== =========
</TABLE>

F-26
<PAGE> 95
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
-----------------------------
1994 1995 1996
------- -------- --------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Beginning of year..................................... $28,465 $ 46,928 $ 81,164
Sales of oil and natural gas produced, net of
production costs.................................... (8,383) (13,243) (39,385)
Net changes in sales prices........................... 863 23,037 116,587
Extensions and discoveries, less applicable future
development and production costs.................... 13,416 1,926 34,113
Previously estimated development costs incurred....... 2,492 2,193 5,278
Revisions of previous estimates, including revised
estimates of development costs, reserves and rates
of production....................................... (2,914) 3,958 7,747
Accretion of discount................................. 2,847 4,693 8,116
Purchase of minerals in place......................... 15,732 21,710 86,677
Net change in income taxes............................ (5,590) (10,038) (58,425)
------- -------- --------
End of period......................................... $46,928 $ 81,164 $241,872
======= ======== ========
</TABLE>

12. SUBSEQUENT EVENTS (UNAUDITED)

On December 30, 1997, Denbury acquired producing oil and natural gas
properties in Mississippi, for approximately $202 million (the "Chevron
Acquisition"). The acquisition included 122 wells, of which 96 wells will be
Company operated. The Company funded this acquisition with bank financing from a
revised and restated credit facility.

This acquisition was accounted for under purchase accounting and the
results of operations will be consolidated effective December 31, 1997. Pro
forma results of operations of the Company as if the Chevron Acquisition had
occurred at the beginning of each respective period are as follows:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED SEPTEMBER 30,
DECEMBER 31, ----------------------
1996 1996 1997
-------------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Revenues........................................... $77,311 $52,534 $75,103
Net income......................................... 4,909 1,181 6,886
Net income per common share........................ 0.37 0.10 0.34
</TABLE>

In computing the pro forma results, depreciation, depletion and
amortization expense was computed using the units of production method, and an
adjustment was made to interest expense reflecting the bank debt that was
required to fund the acquisitions. The pro forma results reflect an increase of
$687,000, $514,000 and $514,000 for 1996 and the nine months ended September 30,
1996 and 1997, respectively, in general and administrative expense for
additional personnel and associated costs relating to the acquired properties,
net of anticipated allocations to operations and capitalization of exploration
costs.

F-27
<PAGE> 96
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Chevron Acquisition by the
Company and are presented on the full cost accrual basis of accounting.
Depreciation, depletion, and amortization, allocated general and administrative
expenses, interest expense and income, and income taxes have been excluded
because the property interests acquired represent only a portion of a business
and these expenses are not necessarily indicative of the expenses to be incurred
by the Company.

<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS
DECEMBER 31, ENDED
----------------- SEPTEMBER 30,
1995 1996 1997
------- ------- -------------
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product............... $17,460 $23,662 $14,034
Direct operating expenses:
Lease operating expense............................ 5,825 6,650 5,237
------- ------- -------
Excess of revenues over direct operating expenses.... $11,635 $17,012 $ 8,797
======= ======= =======
</TABLE>

The Company made two amendments to its credit facility during 1997. In
April, 1997, the Company amended its bank credit facility (i) to extend the
revolver by one year to May 31, 1999, (ii) to extend the termination date by one
year to May 31, 2002, and (iii) to reduce the commitment fee percentages.

In October, 1997, the Company further amended its bank credit facility to
(i) modify the security requirement of the facility such that mortgages will
only be required by the banks to the extent that they were in place as of the
date of the amendment and (ii) to modify certain other definitions and minor
provisions of the agreement.

In order to fund the Chevron Acquisition, the Company revised and restated
its credit facility (the "Credit Facility") with NationsBank of Texas, as agent,
("NationsBank") a group of banks and increased the size of the facility from
$150 million to $300 million. This restatement was made during the fourth
quarter of 1997, with an adjusted borrowing base as of December 31, 1997 of $260
million of which $20 million was available. The Credit Facility includes a five
year revolving credit facility of $165 million, unless renewed or extended, plus
an Acquisition Tranche of $95 million. Unless the acquisition tranche is repaid,
the interest rate on the total loan escalates 0.25% each quarter beginning March
1, 1998 through March 31, 1999. Upon repayment of the acquisition tranche, the
interest rate reverts back to the LIBOR margins applicable to borrowings where
borrowings under the Acquisition Tranche are not outstanding.

On August 6, 1997, the Company entered into a ten year office lease for its
corporate headquarters which is expected to commence late in 1998. The estimated
minimum annual rental payments for the first five years of the lease are
projected to be $1.15 million per year (commencing on occupancy) and the minimum
annual rental payments during the remaining five years of the lease are
projected to be $1.25 million per year.

F-28
<PAGE> 97
DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UNAUDITED QUARTERLY INFORMATION

The following table presents unaudited summary financial information on a
quarterly basis for 1995 and 1996 and the first three quarters of 1997 (in
thousands except per share amounts).

<TABLE>
<CAPTION>
1995
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Revenues.................................. $ 4,381 $ 4,636 $ 4,841 $ 6,251
Expenses.................................. 3,723 4,583 4,554 6,168
Net income................................ 435 35 190 54
Net income per share (primary)............ 0.08 0.00 0.02 0.00
Cash flow from operations(a).............. 2,112 1,913 2,234 3,135
</TABLE>

<TABLE>
<CAPTION>
1996
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Revenues.................................. $ 9,092 $11,682 $14,359 $18,516
Expenses.................................. 6,767 9,608 11,486 11,732
Net income................................ 1,380 1,215 1,745 4,404
Net income per share (primary)(b)......... 0.12 0.11 0.14 0.25
Cash flow from operations(a).............. 6,065 7,238 8,464 12,373
</TABLE>

<TABLE>
<CAPTION>
1997
---------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30
-------- ------- ------------
<S> <C> <C> <C> <C>
Revenues.................................. $21,653 $19,015 $20,401
Expenses.................................. 13,375 15,512 15,304
Net income................................ 5,215 2,207 3,211
Net income per share (primary)............ 0.26 0.11 0.16
Cash flow from operations(a).............. 14,922 12,001 13,243
</TABLE>

- ---------------

(a) Exclusive of the net change in non-cash working capital balances.

(b) Due to the significant variances between quarters in net income and average
shares outstanding, the combined quarterly income per share does not equal
the reported earnings per share for 1996.

F-29
<PAGE> 98

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors
of Denbury Resources Inc.

We have audited the accompanying statement of revenues and direct operating
expenses of Chevron U.S.A. Inc.'s working interest in the Heidelberg Fields (the
"Properties") acquired by Denbury Resources Inc. (the "Company") for each of the
two years in the period ended December 31, 1996 and for the nine months ended
September 30, 1997. This statement is the responsibility of the Company's
management. Our responsibility is to express an opinion on this statement based
on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of revenues and direct
operating expenses is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statement of revenues and direct operating expenses. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the statement of
revenues and direct operating expenses. We believe that our audit provides a
reasonable basis for our opinion.

The accompanying statement of revenues and direct operating expenses was
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission (for inclusion in the registration statement
on Form S-3 of Denbury Resources Inc.) as described in Note 1 and is not
intended to be a complete presentation of the Properties' revenues and expenses.

In our opinion, the statement of revenues and direct operating expenses
referred to above presents fairly, in all material respects, the revenues and
direct operating expenses of the Properties described in Note 1 for each of the
two years in the period ended December 31, 1996 and for the nine months ended
September 30, 1997, in conformity with generally accepted accounting principles.

Price Waterhouse LLP

San Francisco, California
December 19, 1997

F-30
<PAGE> 99

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF PROPERTIES

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, NINE MONTHS ENDED
------------------ SEPTEMBER 30,
1995 1996 1997
------- ------- -----------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product sales......... $17,460 $23,662 $14,034
Direct operating expenses:
Lease operating expense............................ 5,825 6,650 5,237
------- ------- -------
Excess of revenues over direct operating expense..... $11,635 $17,012 $ 8,797
======= ======= =======
</TABLE>

The accompanying notes are an integral part of these statements.

F-31
<PAGE> 100

NOTES TO STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF PROPERTIES

1. BASIS OF PRESENTATION

Denbury Resources Inc. (the "Company") agreed on November 25, 1997 to
acquire Chevron U.S.A. Inc.'s working interest in the Heidelberg Fields for
approximately $202 million. The Properties are located in the state of
Mississippi. The acquisition is expected to close in December 1997. These
acquired Properties will be consolidated in the Company's financial statements
effective January 1, 1998. Other owners of working interests in the Properties
covered by the acquisition agreement have the preferential right to acquire the
Properties, which if exercised could reduce the interest acquired by the
Company.

Historical financial statements reflecting financial position, results of
operations and cash flows required by generally accepted accounting principles
are not presented, as such information is neither readily available on an
individual property basis nor meaningful for the Properties acquired because the
entire acquisition cost is being assigned to oil and natural gas properties.
Accordingly, the statement of revenues and direct operating expenses is
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X.

The accompanying statement of revenues and direct operating expenses (the
"Statement") relates only to the working interest in the Properties acquired and
may not be representative of future operations. The Statement includes revenues
from natural gas sales and direct operating expenses for each of the periods
presented. The Statement does not include federal and state income taxes,
interest, depletion, depreciation and amortization or general and administrative
expenses because such amounts would not be indicative of those expenses which
would be incurred by the Company.

Revenues in the Statement are recognized on the entitlement method.

The accompanying Statement has been prepared on the accrual basis in
accordance with generally accepted accounting principles. Preparation of the
Statement in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts reported in
the Statement and accompanying notes. Actual results could differ from those
estimates.

2. COMMITMENTS AND CONTINGENCIES

Chevron U.S.A. Inc. is a defendant in numerous lawsuits, including, along
with other oil companies, actions challenging oil royalty and severance tax
payments based on posted prices. Plaintiffs may seek to recover large and
sometimes unspecified amounts, and some matters may remain unresolved for
several years. The amount of such future cost is indeterminable. Such liability
for events occurring prior to the effective date of the acquisition shall be
retained by Chevron U.S.A. Inc. and Chevron U.S.A. Inc. has indemnified the
Company for any costs incurred by it in conjunction with these suits.

Given the nature of the Properties acquired and as stipulated in the
purchase agreement, the Company is subject to loss contingencies, if any,
pursuant to existing or expected environmental laws, regulations, and leases
covering the acquired Properties. Management does not believe such matters will
have a material impact on the Statement.

3. CONCENTRATION OF CUSTOMERS

During the year ended December 31, 1996 and the nine months ended September
30, 1997, approximately 67% and 31% of the Properties' production was sold to
Hunt Refining Company and Southland Oil Company, respectively. During the year
ended December 31, 1995, approximately 88% and 10% of the Properties' production
was sold to Amerada Hess Corporation and Hunt Refining Company, respectively.
While management believes that its relationships with these purchasers is good,
any loss of revenue from these purchasers due to nonpayment or late payment by
the purchaser would have an adverse effect on the Statement.

F-32
<PAGE> 101
NOTES TO STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF PROPERTIES -- (CONTINUED)

4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED)

The Properties' proved oil and natural gas reserves at December 31, 1997,
1996 and 1995 have been estimated by the Company's petroleum consultants,
Netherland & Sewell, in accordance with guidelines established by the Securities
and Exchange Commission ("SEC"). The December 31, 1997 reserves have been
adjusted by production from the Properties to estimate the September 30, 1997
reserves.

<TABLE>
<CAPTION>
OIL GAS
ESTIMATED QUANTITIES OF PROVED RESERVES (MBBL) (MMCF)
- --------------------------------------- -------- -------
<S> <C> <C>
January 1, 1995............................................. 31,331.1 3,303.7
Production................................................ 1,321.5 290.6
-------- -------
December 31, 1995........................................... 30,009.6 3,013.1
Production................................................ 1,252.0 245.1
-------- -------
December 31, 1996........................................... 28,757.6 2,768.0
Production................................................ 793.6 160.1
-------- -------
September 30, 1997.......................................... 27,964.0 2,607.9
======== =======
Proved Developed Reserves:
As of January 1, 1995..................................... 17,230.8 3,303.7
As of December 31, 1995................................... 15,909.3 3,013.1
As of December 31, 1996................................... 14,657.3 2,768.0
As of September 30, 1997.................................. 13,863.7 2,607.9
</TABLE>

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATED TO OIL AND NATURAL GAS RESERVES

The standardized measure of discounted future net cash flows ("Standardized
Measure") relating to oil and natural gas reserves acquired is calculated in
accordance with regulations prescribed by the SEC. The Standardized Measure has
been prepared assuming year-end selling prices adjusted for future fixed and
determinable price changes, year-end development and production costs and a 10%
annual discount rate. The reserves and the related Standardized Measure at
September 30, 1997 were adjusted for production during the nine-months ended
September 30, 1997 and the years ended December 31, 1996 and 1995, and in
addition, Standardized Measure was also adjusted for price changes to derive
reserves and the Standardized Measure as of September 30, 1997, December 31,
1996 and December 31, 1995. The Standardized Measure is not a fair market value
of the mineral interests purchased and the Standardized Measure presented for
the proved oil and natural gas reserves does not purport to present the fair
market value of the 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 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 are inherently
imprecise and subject to substantial revision.

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------- SEPTEMBER 30,
1995 1996 1997
--------- --------- -------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows............................ $ 470,689 $ 613,780 $ 426,489
Future production and development costs........ (201,520) (204,876) (189,243)
--------- --------- ---------
Future net cash flows undiscounted............. 269,169 408,904 237,246
10% annual discount for estimated timing of
cash flows................................... (142,503) (203,206) (113,931)
--------- --------- ---------
Standardized measure of discounted future net
cash flows................................... $ 126,666 $ 205,698 $ 123,315
========= ========= =========
</TABLE>

F-33
<PAGE> 102
NOTES TO STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF PROPERTIES -- (CONTINUED)

The following are principal sources of changes in the standardized measure
of discounted future net cash flows:

<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS
DECEMBER 31, ENDED
-------------------- SEPTEMBER 30,
1995 1996 1997
-------- -------- -------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure of discounted future net
cash flows at beginning of period.............. $ 97,753 $126,666 $205,698
Changes resulting from:
Net change in prices........................... 30,772 83,377 (89,014)
Sales of oil and natural gas produced.......... (11,635) (17,012) (8,797)
Accretion of discount.......................... 9,776 12,667 15,428
-------- -------- --------
Standardized measure of discounted future net
cash flows at end of period.................... $126,666 $205,698 $123,315
======== ======== ========
</TABLE>

F-34
<PAGE> 103

[NSAI LETTERHEAD]
January 13, 1998

Mr. William E. Gross
Denbury Management, Inc.
17304 Preston Road, Suite 200
Dallas, Texas 75252

Dear Mr. Gross:

In accordance with your request, we have estimated the proved and probable
reserves and future revenue, as of December 31, 1997, to the Denbury Management,
Inc. (DMI) interest in certain oil and gas properties located in Louisiana,
Mississippi, Ohio, and Texas as listed in the accompanying tabulations. These
properties include those in the East Heidelberg and West Heidelberg Fields
acquired from Chevron U.S.A. Inc. (CUSA) effective December 31, 1997. For the
purposes of this report, all DMI properties except those acquired from CUSA are
referred to as the Corporate Properties. This report has been prepared using
constant prices and costs as set forth in this letter. For the proved reserves,
this report conforms to the guidelines of the Securities and Exchange Commission
(SEC). However, inasmuch as the SEC does not recognize probable reserves, the
sections of this report dealing with such reserves should not be used in filings
with the SEC.

As presented in the accompanying summary projections, Tables I through V,
we estimate the net reserves and future net revenue to the DMI interest, as of
December 31, 1997, to be:

<TABLE>
<CAPTION>
NET RESERVES FUTURE NET REVENUE
----------------------- ----------------------------
OIL GAS PRESENT WORTH
CATEGORY (BARRELS) (MCF) TOTAL AT 10%
-------- ---------- ---------- ------------ -------------
<S> <C> <C> <C> <C>
Proved Developed
Producing....................... 20,495,088 32,925,654 $240,589,400 $182,575,200
Non-Producing................... 10,860,120 36,879,723 174,904,500 93,904,400
Proved Undeveloped................ 20,663,028 7,385,636 187,968,700 84,849,000
---------- ---------- ------------ ------------
Total Proved............ 52,018,236 77,191,013 $603,462,600 $361,328,600
</TABLE>

The oil reserves shown include crude oil, condensate, and gas plant
liquids. Oil volumes are expressed in barrels which are equivalent to 42 United
States gallons. Gas volumes are expressed in thousands of standard cubic feet
(MCF) at the contract temperature and pressure bases.

As shown in the Table of Contents, this report is divided into sections for
Corporate Properties and Chevron Acquisition Properties. Each section includes
summary projections of reserves and revenue for each reserve category and by
reserve category for each state along with one-line summaries of reserves,
economics, and basic data by lease. Supplemental data summaries are also
included by reserve category for each state. For the purposes of this report,
the term "lease" refers to a single economic projection.

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The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, proved undeveloped,
and probable reserves. No study was made to determine whether possible reserves
might be established for these properties. This report does not include any
value which could be attributed to interests in undeveloped acreage beyond those
tracts for which undeveloped reserves have been estimated.

Future gross revenue to the DMI interest is prior to deducting state
production taxes and ad valorem taxes. Future net revenue is after deducting
these taxes, future capital costs, and operating expenses, but before
consideration of federal income taxes. In accordance with SEC guidelines, the
future net revenue has been discounted at an annual rate of 10 percent to
determine its "present worth." The present worth is shown to indicate the effect
of time on the value of money and should not be construed as being the fair
market value of the properties.

For the purposes of this report, a field inspection of the properties has
not been performed nor has the mechanical operation or condition of the wells
and their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability.
Also, our estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.

Oil prices used in this report are based on a December 1997 average Koch
West Texas Intermediate posted price of $16.18 per barrel, adjusted by lease for
gravity, transportation fees, and regional posted price differentials. The
natural gas liquids price used for Gibson Field, Louisiana, is $12.26 per
barrel. Gas prices used in this report are based on a December 1997 NYMEX Henry
Hub Natural Gas Contract settlement price of $2.58 per MMBTU, adjusted by lease
for transportation fees, BTU content, and regional price differentials. Oil,
natural gas liquids, and gas prices are held constant in accordance with SEC
guidelines.

Lease and well operating costs are based on operating expense records of
DMI and CUSA. For non-operated properties, these costs include the per-well
overhead expenses allowed under joint operating agreements along with costs
estimated to be incurred at and below the district and field levels. As
requested, lease and well operating costs for the operated properties include
only direct lease and field level costs. Headquarters general and administrative
overhead expenses of DMI are not included. Lease and well operating costs are
held constant in accordance with SEC guidelines. Capital costs are included as
required for workovers, new development wells, and production equipment.

We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the DMI interest.
Therefore, our estimates of reserves and future revenue do not include
adjustments for the settlement of any such imbalances; our projections are based
on DMI receiving its net revenue interest share of estimated future gross gas
production.

The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the revenues therefrom and the costs related thereto could be more or less than
the estimated amounts. A substantial portion of these reserves are for
behind-pipe zones, undeveloped locations, and producing wells that lack
sufficient production history upon which performance-related estimates of
reserves can be based. Therefore, these reserves are based on estimates of
reservoir volumes and recovery efficiencies along with analogies to similar
production. As such reserve estimates are usually subject to greater revision
than those based on substantial production and pressure data, it may be
necessary to revise these estimates up or down in the future as additional
performance data become available. The sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may vary from
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we
have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgments.

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The titles to the properties have not been examined by Netherland, Sewell &
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Denbury Management, Inc.; Chevron U.S.A. Inc.; other interest owners; various
operators of the properties; and the nonconfidential files of Netherland, Sewell
& Associates, Inc. and were accepted as accurate. We are independent petroleum
engineers, geologists, and geophysicists; we do not own an interest in these
properties and are not employed on a contingent basis. Basic geologic and field
performance data together with our engineering work sheets are maintained on
file in our office.

Very truly yours,

/s/ FREDERIC D. SEWELL

DMA:EIB

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