DENBURY RESOURCES INC, 424B1, 1996-10-25

DENBURY RESOURCES INC
424B1, 1996-10-25
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
Filed pursuant to Rule 424(b)(1)
Registration No. 333-12005

PROSPECTUS
October 24, 1996
4,400,000 SHARES

[DRI LOGO]

DENBURY RESOURCES INC.

COMMON SHARES

All of the Common Shares offered hereby are being sold by Denbury Resources
Inc. Of the 4,400,000 shares offered hereby, 3,600,000 shares are being offered
in an underwritten public offering (the "Public Offering") and 800,000 shares
are being offered in a concurrent offering (the "TPG Offering") directly to an
existing stockholder at a price equal to the price to the public per share set
forth below less underwriting discounts and commissions. The Public Offering and
the TPG Offering are each conditioned on the consummation of the other. The
Public Offering and the TPG Offering are collectively referred to as the
"Offerings."

The Common Shares are listed on the Nasdaq National Market under the symbol
"DENRF" ("DENFD" through November 13, 1996 due to a one-for-two reverse stock
split) and on The Toronto Stock Exchange under the symbol "DNR." On October 24,
1996, the closing price of the Common Shares on the Nasdaq National Market and
The Toronto Stock Exchange as reported by each such exchange was U.S. $13.91 and
Cdn. $18.75, respectively. See "Price Range of Common Shares and Dividend
Policy."

SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN MATTERS
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.
- --------------------------------------------------------------------------------

<TABLE>
<S> <C> <C> <C>
PRICE UNDERWRITING PROCEEDS
TO THE DISCOUNTS AND TO THE
PUBLIC COMMISSIONS(1) COMPANY(2)
</TABLE>

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

<TABLE>
<S> <C> <C> <C>
Per Share
Public Offering......... $12.875 $0.84 $12.035
TPG Offering............ $12.035 $ -- $12.035
Total(3).................. $55,978,000 $3,024,000 $52,954,000
- ---------------------------------------------------------------------------------
</TABLE>

(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
(2) Before deducting estimated expenses of $500,000 payable by the Company.
(3) The Company has granted to the Underwriters an option, exercisable within 30
days of the date hereof, to purchase up to 540,000 additional Common Shares
at the Price to the Public less Underwriting Discounts and Commissions,
solely to cover over-allotments, if any. If such option is exercised in
full, the total Price to the Public, Underwriting Discounts and Commissions
and Proceeds to the Company will be $62,930,500, $3,477,600 and $59,452,900,
respectively. See "Underwriting."

The Common Shares are being offered in the Public Offering by the several
Underwriters when, as and if delivered to and accepted by the Underwriters and
subject to various prior conditions, including their right to reject orders in
whole or in part. It is expected that delivery of such share certificates will
be made in New York, New York on or about October 30, 1996.

DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
PRUDENTIAL SECURITIES INCORPORATED
JOHNSON RICE & COMPANY L.L.C.
<PAGE> 2

IN CONNECTION WITH THE PUBLIC OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR
EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE
SECURITIES AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

IN CONNECTION WITH THE PUBLIC OFFERING, CERTAIN UNDERWRITERS AND SELLING
GROUP MEMBERS (IF ANY) MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE
COMMON SHARES ON THE NASDAQ NATIONAL MARKET IN ACCORDANCE WITH RULE 10B-6A UNDER
THE SECURITIES EXCHANGE ACT OF 1934. SEE "UNDERWRITING."

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<PAGE> 3

PROSPECTUS SUMMARY

The following summary is qualified in its entirety and should be read in
conjunction with the more detailed information and Consolidated Financial
Statements and notes thereto included in this Prospectus. Investors should
carefully consider the information set forth under "Risk Factors." 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 ("GAAP"). All share information
contained in this Prospectus has been adjusted to reflect a one-for-two reverse
split of the Common Shares, effective on October 10, 1996. The July 1, 1996
estimated proved reserve data included throughout this Prospectus have been
prepared by Netherland, Sewell & Associates, Inc. ("Netherland & Sewell"),
independent petroleum engineers. Unless otherwise indicated herein, the
information contained in this Prospectus assumes that the Underwriters'
over-allotment option will not be exercised. The terms "Denbury" and the
"Company" refer to Denbury Resources Inc., a Canadian corporation, and all
references to the operations and assets of the Company include those of its
wholly-owned subsidiaries. Certain terms used herein are defined in the Glossary
included elsewhere in this Prospectus.

THE COMPANY

Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. Since
1993, after having disposed of its Canadian oil and natural gas properties, the
Company has focused its operations primarily onshore in Louisiana and
Mississippi. Over the last three 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 those properties.

For the three-year period ended December 31, 1995, the Company increased
its proved reserves by 57% per annum, from 5.8 MMBOE at December 31, 1993 to
14.3 MMBOE. As of July 1, 1996, including the Hess and Ottawa Acquisitions (as
herein defined), the Company had increased its proved reserves to 22.7 MMBOE,
representing a 59% increase over December 31, 1995 reserves. Over the same
three-year period, the Company also increased its average daily production by
88% per annum, from 1,194 BOE/d to 4,207 BOE/d. Pro forma for the Hess and
Ottawa Acquisitions, production for the first six months of 1996 was 9,323
BOE/d. For the three-year period ended December 31, 1995, Adjusted EBITDA grew
at an annual rate of 94%, from $3.0 million to $11.3 million. Pro forma Adjusted
EBITDA for the first six months of 1996 was $18.7 million.

As of July 1, 1996, the Company had proved reserves of 11.7 MMBbls and 65.8
Bcf. At such date, the PV10 Value was $175.3 million, of which $157.8 million
was attributable to proved developed reserves. Denbury operates wells comprising
approximately 68% of its PV10 Value. The twelve largest fields owned by the
Company constitute approximately 80% of its estimated proved reserves and within
these twelve fields, Denbury owns an average working interest of 84%.

BUSINESS STRATEGY

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. The Company seeks to achieve attractive returns on capital through
prudent acquisitions, development and exploratory drilling and efficient
operations; maintain a conservative balance sheet to preserve maximum financial
and operational flexibility; and create strong employee incentives through
equity ownership. These fundamental principles are at the core of the Company's
long-term growth strategy.

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<PAGE> 4

cost manner once acquired. The Company believes the Gulf Coast represents one of
the most attractive regions in North America given the region's prolific
production history and the new 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 attractive 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 acquires properties where it
believes significant additional value can be created. Such properties are
typically characterized by: (i) long production histories, (ii) complex
geological formations which have multiple producing zones and substantial
exploitation potential, (iii) a history of limited operational attention 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. By maintaining conservative levels of
debt, the Company is able to respond quickly to acquisitions that fit within its
criteria. The Company believes that due to continuing rationalization of
properties, primarily by major integrated and independent energy companies, a
strong backlog of acquisition opportunities should continue. 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 Company's recent Hess and Ottawa Acquisitions
are illustrative of the type of opportunities the Company seeks.

OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company typically seeks
to acquire working interest positions that give the Company operational control
or which the Company believes may lead to operational control. As the operator
of properties comprising approximately 68% of its total PV10 Value, the Company
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 in fully evaluating a field for future potential and, if favorable,
consolidates 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 to
the point where the potential benefits of value enhancement activities justify
the allocation of Company resources.

EXPLOITATION OF PROPERTIES. The Company seeks to maximize the value of its
properties by either increasing production, increasing recoverable reserves or
reducing operating costs, and often through a combination of all three. The
Company utilizes a variety of techniques to achieve this goal, 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; (iv)
conducting developmental drilling to access undrained portions of the field
which can only be produced from a new wellbore; and (v) utilizing exploratory
drilling, which is frequently based on various advanced technologies such as 3-D
seismic. The Company believes that by employing a full range of value
enhancement techniques it is better able to extract the maximum value from its
properties.

PERSONNEL. The Company believes it has assembled a highly competitive team
of experienced and technically proficient employees who are motivated through a
positive work environment and by ownership in the Company, which is encouraged
through the Company's stock option and stock purchase plans. The Company's
geological and engineering professionals have an average of over 15 years of
experience in the Gulf Coast region. The Company believes that employee
ownership is essential for attracting, retaining and motivating quality
personnel. Approximately 92% of Denbury's eligible employees were participating
in the Company's stock purchase plan as of July 1, 1996.

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<PAGE> 5

RECENT DEVELOPMENTS

TPG INVESTMENTS

In December 1995, the Company completed a $40.0 million private placement
of securities with the Texas Pacific Group ("TPG") consisting of Common Shares,
$10 Convertible First Preferred Shares, Series A ("Convertible Preferred") and
warrants to purchase Common Shares (collectively, the "TPG Placement"). The TPG
Placement enabled the Company to repay its then outstanding bank debt and
facilitated its ability to pursue its long-term growth strategy. See "Interests
of Management in Certain Transactions."

Concurrent with the Public Offering, the Company will sell an additional
800,000 Common Shares directly to TPG at a price equal to the price to the
public less underwriting discounts and commissions. The Public Offering and the
TPG Offering are each conditioned on the consummation of the other.

CAPITALIZATION ADJUSTMENTS

Subsequent to June 30, 1996, the Company issued 187,500 Common Shares for
the conversion of the remaining 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
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 intends to convert all of the 1,500,000 shares of Convertible
Preferred simultaneously with the closing of the Offerings into 2,816,372 Common
Shares.

Giving effect to the issuance of Common Shares for the 6 3/4% Convertible
Debentures, the Warrants, the Debentures and the conversion of the Convertible
Preferred concurrently with the closing of the Offerings (collectively, the
"Capitalization Adjustments"), as of June 30, 1996 an additional 3,395,462
Common Shares would have been outstanding.

ACQUISITION OF HESS PROPERTIES

The Company completed several property acquisitions during the first half
of 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, from Amerada Hess Corporation ("Amerada Hess") for
$37.2 million (the "Hess Acquisition"), effective May 1, 1996. Average daily
production during the first half of 1996 from these properties, including the
periods when they were not owned by the Company, was approximately 6.6 MMcf/d
and 2,230 Bbls/d, or 3,335 BOE/d, net to the interest acquired by Denbury. As of
July 1, 1996, the Hess Acquisition properties had estimated net proved reserves
of approximately 5.9 MMBOE, consisting of approximately 5.0 MMBbls and 5.6 Bcf,
with a PV10 Value of $43.1 million. Approximately 90% of the PV10 Value of the
Hess Acquisition was for wells on which Denbury assumed operations with an
average working interest of approximately 80%.

OTHER ACQUISITIONS

In addition to the Hess Acquisition, during the first half of 1996 the
Company completed other acquisitions totaling $10.8 million. The largest of
these was the acquisition of additional working interests in five Mississippi
oil and natural gas properties in which the Company already owned an interest,
and certain overriding royalty interests in other areas, which were acquired
during April 1996 for approximately $7.5 million from Ottawa Energy, Inc.
("Ottawa"), a subsidiary of Highridge Exploration Ltd. (the "Ottawa
Acquisition"). In addition to the Ottawa Acquisition, the Company completed four
other acquisitions,

5
<PAGE> 6

primarily in Louisiana, totaling $3.3 million. Average daily production during
the first half of 1996 from these acquisitions, including the Ottawa Acquisition
and the periods when they were not owned by the Company, was approximately 3.7
MMcf/d and 434 Bbls/d, or 1,048 BOE/d, net to the interest acquired by the
Company. As of July 1, 1996, the Company's estimated net proved reserves for
these acquisitions totaled approximately 1.1 MMBbls and 13.1 Bcf or 3.3 MMBOE,
with a PV10 Value of $24.1 million.

NEW CREDIT FACILITY

In order to fund these acquisitions, improve the terms and increase the
size of the previous credit facility, the Company has entered into a new $150.0
million dollar credit facility (the "Credit Facility") with NationsBank of Texas
("NationsBank"). This refinancing closed during the second quarter of 1996, and
has a borrowing base as of October 15, 1996 of $60.0 million. 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. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- New Credit
Facility."

THE OFFERINGS

<TABLE>
<S> <C>
Common Shares offered by the Company:
Public Offering........................................ 3,600,000 shares
TPG Offering........................................... 800,000 shares
Total.......................................... 4,400,000 shares

Common Shares to be outstanding after the Offerings...... 19,498,269 shares(1)

Use of Proceeds.......................................... To repay outstanding indebtedness
under the Credit Facility incurred
primarily in connection with the
recent acquisitions. The remainder
of the proceeds will be used to
fund future capital expenditures
related to exploration,
development and acquisition
activities, to increase working
capital or for general corporate
purposes. See "Use of Proceeds."

Nasdaq National Market trading symbol.................... DENRF(2)

The Toronto Stock Exchange trading symbol................ DNR
</TABLE>

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(1) Represents Common Shares outstanding as of October 15, 1996 after giving
effect to the Capitalization Adjustments and the Offerings. This total does
not include 1,758,750 shares issuable pursuant to outstanding warrants and
stock options, of which 1,179,187 were exercisable as of October 15, 1996.

(2) Due to the one-for-two reverse stock split, the Common Shares will trade on
the Nasdaq National Market under the symbol "DENFD" through November 13,
1996.

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SUMMARY OIL AND NATURAL GAS RESERVE DATA

The net proved oil and natural gas reserve estimates as of December 31,
1995 and July 1, 1996 have been prepared by Netherland & Sewell, and the net
proved oil and natural gas reserve estimates as of December 31, 1993 and 1994
have been prepared by the Scotia Group, Inc., both independent petroleum
engineers. For additional information relating to the Company's oil and natural
gas reserves, see "Risk Factors -- Uncertainty of Estimates of Oil and Natural
Gas Reserves," "Business and Properties -- Oil and Natural Gas Operations," and
Note 10 to the Consolidated Financial Statements of the Company. Attached hereto
as Appendix A is a letter from Netherland & Sewell relating to their July 1,
1996 reserve report.

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
----------------------------- JULY 1,
1993 1994 1995 1996
------- ------- ------- --------
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil (MBbls).......................................... 3,583 4,230 6,292 11,725
Natural gas (MMcf)................................... 13,029 42,047 48,116 65,807
Oil equivalent (MBOE)................................ 5,755 11,238 14,311 22,693
Discounted estimated future net cash flow before
income taxes (PV10 Value) (thousands)(1).......... $28,638 $52,691 $96,965 $175,255
Standardized measure of discounted estimated future
net cash flow after net income taxes
(thousands)(1).................................... $28,465 $46,928 $81,164 $150,160
</TABLE>

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(1) Determined based on period-end unescalated prices and costs in accordance
with the guidelines of the Securities and Exchange Commission (the "SEC"),
discounted at 10% per annum. The oil prices as of December 31, 1995 and July
1, 1996, respectively, were West Texas Intermediate $18.00 and $20.00 per
barrel adjusted by field, and the NYMEX Henry Hub natural gas prices for the
same two periods were $2.24 and $2.65 per MMBtu, also adjusted by field.

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>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
--------------------------------------- -----------------------------
PRO PRO
FORMA FORMA
1993(1) 1994 1995 1995(2) 1995 1996 1996(2)
------- ------ ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
NET AVERAGE DAILY PRODUCTION VOLUMES:
Oil (Bbls).......................... 858 1,340 1,995 4,966 1,830 2,894 4,651
Natural gas (Mcf)................... 2,013 9,113 13,271 21,918 12,075 22,518 28,031
Oil equivalent (BOE)................ 1,194 2,859 4,207 8,619 3,843 6,647 9,323
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)....................... $13.91 $13.84 $ 14.90 $ 14.64 $ 14.92 $ 17.39 $ 17.33
Natural gas (per Mcf)............... 2.06 1.78 1.90 1.83 1.85 2.80 2.72
UNIT DATA ($ PER BOE):
Revenue............................. $13.47 $12.17 $ 13.05 $ 13.09 $ 12.94 $ 17.07 $ 16.84
Production expenses................. (4.75) (4.13) (4.42) (4.87) (4.50) (4.42) (4.64)
------ ------ ------- ------- ------- ------- -------
Production netback.................. 8.72 8.04 8.63 8.22 8.44 12.65 12.20
General and administrative.......... (1.80) (1.12) (1.25) (0.77) (1.40) (1.46) (1.18)
Interest, net....................... 0.04 (0.99) (1.26) (0.46) (1.25) (0.19) (0.07)
------ ------ ------- ------- ------- ------- -------
Operating cash flow (3)............. $ 6.96 $ 5.93 $ 6.12 $ 6.99 $ 5.79 $ 11.00 $ 10.95
====== ====== ======= ======= ======= ======= =======
</TABLE>

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(1) Includes production from Canadian properties sold during 1993.

(2) Gives effect to the (i) Capitalization Adjustments, (ii) Hess Acquisition,
(iii) Ottawa Acquisition, and (iv) the application of estimated net proceeds
of $52.5 million from the Offerings as if such transactions had been
consummated as of January 1 of the period presented. See "Use of Proceeds."

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

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The summary historical financial data set forth below as of and for the
years ended December 31, 1993, 1994 and 1995 have been derived from the
Company's audited financial statements and notes thereto contained elsewhere in
this Prospectus. The financial data for the six-month periods ended June 30,
1995 and 1996 were derived from the unaudited financial statements of the
Company, and include in management's opinion, 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 and
none of the data presented below are necessarily indicative of future results.
The summary historical and unaudited pro forma financial data for the Company
are qualified in their entirety and should be read in conjunction with "Pro
Forma Operating Results," "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's Consolidated Financial
Statements and Notes.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
---------------------------------------- -----------------------------
PRO PRO
FORMA FORMA
1993 1994 1995 1995(1) 1995 1996 1996(1)
------- ------- ------- ------- ------- ------- -------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
SELECTED INCOME STATEMENT DATA:
Revenue:
Oil, natural gas and related
product sales.................... $ 5,868 $12,692 $20,032 $41,196 $ 8,997 $20,650 $28,574
Interest income.................... 76 23 77 77 21 124 124
------- ------- ------- ------- ------- ------- -------
Total revenues.............. 5,944 12,715 20,109 41,273 9,018 20,774 28,698
------- ------- ------- ------- ------- ------- -------
Expenses:
Production......................... 2,067 4,309 6,789 15,336 3,128 5,350 7,870
General and administrative......... 782 1,105 1,832 2,332 935 1,656 1,906
Interest........................... 83 1,146 2,085 1,601 927 681 233
Imputed preferred dividends........ -- -- -- -- -- 759 --
Loss on early extinguishment of
debt............................. -- -- 200 200 200 440 440
Depletion and depreciation......... 1,898 4,209 8,022 16,521 3,075 7,382 10,099
Franchise taxes.................... -- 65 100 100 42 107 107
------- ------- ------- ------- ------- ------- -------
Total expenses.............. 4,830 10,834 19,028 36,090 8,307 16,375 20,655
------- ------- ------- ------- ------- ------- -------
Income before the following: 1,114 1,881 1,081 5,183 711 4,399 8,043
Gain on sale of Canadian
properties....................... 966 -- -- -- -- -- --
------- ------- ------- ------- ------- ------- -------
Income before income taxes........... 2,080 1,881 1,081 5,183 711 4,399 8,043
Provision for federal income taxes... (345) (718) (367) (1,761) (242) (1,804) (2,785)
------- ------- ------- ------- ------- ------- -------
Net income........................... $ 1,735 $ 1,163 $ 714 $ 3,422 $ 469 $ 2,595 $ 5,258
======== ======== ======== ======== ======== ======== ========
Net income per common share.......... $ 0.35 $ 0.19 $ 0.10 $ 0.29 $ 0.07 $ 0.23 $ 0.27
======== ======== ======== ======== ======== ======== ========
Weighted average common shares
outstanding........................ 4,990 6,240 6,870 11,921 6,536 11,512 19,321
======== ======== ======== ======== ======== ======== ========
OTHER DATA:
Operating cash flow(2)............. $ 3,030 $ 6,185 $ 9,394 $21,995 $ 4,025 $13,303 $18,582
Capital expenditures............... 29,855 16,903 28,524 -- 10,506 60,733 --
Adjusted EBITDA(3)................. 3,019 7,213 11,311 23,428 4,892 13,537 18,691
</TABLE>

<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
AS OF DECEMBER 31, ---------------------
------------------------------- PRO
1993 1994 1995 ACTUAL FORMA(4)
------- ------- ------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Total assets.................................... $35,978 $48,964 $77,641 $132,900 $145,814
Working capital (deficiency).................... (1,410) (1,620) 6,862 (1,184) 11,730
Long-term debt, net of current maturities....... 6,177 16,536 3,474 42,964 34
Convertible preferred stock..................... -- -- 15,000 15,759 --
Shareholders' equity............................ 24,431 25,962 53,501 57,258 128,861
</TABLE>

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<PAGE> 9

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(1) Gives effect to the (i) Capitalization Adjustments, (ii) Hess Acquisition,
(iii) Ottawa Acquisition, and (iv) the application of estimated net proceeds
of $52.5 million from the Offerings as if such transactions had been
consummated as of January 1 of the period presented. See "Use of Proceeds."

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

(3) Adjusted EBITDA represents earnings before interest income, interest
expense, income taxes, depletion and depreciation, gain on sale of oil and
natural gas properties, imputed preferred dividends and losses on early
extinguishment of debt. Adjusted EBITDA is not intended to represent cash
flows for the period, nor has it been presented as an alternative to
operating income nor as an indicator of operating performance. It should not
be considered in isolation or as a substitute for measures of performance
prepared in accordance with GAAP. See the Company's Consolidated Statements
of Cash Flows in the Consolidated Financial Statements included elsewhere in
this Prospectus. Adjusted EBITDA is included in this Prospectus because it
is a basis upon which the Company assesses its financial performance.

(4) Gives effect to the Capitalization Adjustments and the application of
estimated net proceeds of $52.5 million from the Offerings.

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<PAGE> 10

RISK FACTORS

In addition to other information set forth elsewhere in this Prospectus,
the following factors relating to the Company and the Offerings should be
considered when evaluating an investment in the Common Shares offered hereby.

PRICE FLUCTUATIONS AND MARKETS

The Company's revenue, profitability and future rate of growth are
substantially 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 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. It is impossible 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 the Company's oil and natural gas that can be produced
economically and could, therefore, 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 in the past entered
into hedging arrangements from time to time. The Company did not have any
financial hedging contracts in place as of the date of this Prospectus, although
it may have 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 shutin for lack of a market or due to
inadequacy or unavailability of pipeline or gathering system capacity.

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 55% of the
Company's proved developed reserves at July 1, 1996 are located in the lower
Gulf Coast geosyncline in southern Louisiana which is characterized by
relatively rapid decline rates. Approximately 59% of the Company's total proved
reserves at July 1, 1996 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.

DRILLING AND OPERATING RISKS

Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. 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. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells but from
wells that are productive but do not produce sufficient net revenues to return a
profit after 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, damage to property of the

10
<PAGE> 11

Company and others, and the imposition of fines and penalties pursuant to
environmental legislation. See "-- Governmental and Environmental Regulation."
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 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.

The Company has focused its oil and natural gas operations in certain key
areas and currently receives approximately 80% of its production from 14 fields.
Any interruption to these key areas could materially adversely affect the
operations 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.

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. 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 the reserve reports could
have a material adverse effect on the Company.

ACQUISITION RISKS

The Company's rapid growth in recent years has been attributable in
significant part to acquisitions of producing properties. After the Offerings,
the Company expects to continue to evaluate and, where appropriate, pursue
acquisition opportunities on terms management considers favorable to the
Company. There can be no assurance that suitable acquisition candidates will be
identified in the future, nor that they will be integrated successfully into the
Company's operations or 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 reveal all existing or potential problems, nor will it
necessarily permit a buyer to become sufficiently familiar with the properties
to fully assess their 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 be substantially different in operating and
geologic characteristics or geographic location than existing properties. While
it is the Company's current intent to concentrate on acquiring producing
properties with development and exploration

11
<PAGE> 12

potential located in the Gulf Coast region, there is no assurance that the
Company will not pursue acquisitions or properties located in other geographic
regions.

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 capital expenditures have
averaged four times more than its cash flow from operations (exclusive of the
changes in non-cash working capital balances) and it has continued this trend
into 1996 by spending approximately 4.6 times its cash flow during the first
half of 1996. Historically, the Company has funded these expenditures
principally through debt and equity. As of October 15, 1996, the Company had a
$60.0 million borrowing base on its Credit Facility, $12.0 million of which was
available. The Company intends to use the net proceeds from the Offerings to
substantially reduce its outstanding bank debt. See "Use of Proceeds." The
borrowing base on this facility will be redetermined semi-annually by the lender
in its sole discretion and there can be no assurance the borrowing base will be
maintained at its present level. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- New Credit Facility."

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. Should outside capital
resources be limited, the rate of Company 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 oil and natural gas reserves.
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.

CONTROLLING SHAREHOLDER

In December 1995, the Company completed a $40.0 million private placement
of securities to TPG consisting of the Convertible Preferred, Common Shares and
warrants. The Convertible Preferred will be converted into approximately 2.8
million Common Shares concurrently with the closing of the Offerings. TPG will
buy 800,000 Common Shares in the TPG Offering directly from the Company at the
price to the public less underwriting discounts and commissions. After adjusting
for the conversion of the Convertible Preferred, the Offerings and the other
Capitalization Adjustments, TPG will own approximately 42% of the Common Shares
outstanding on a fully-diluted basis. TPG is entitled to nominate a minimum of
three of seven representatives to the Company's Board of Directors as long as
TPG maintains certain ownership levels. The current Board of Directors has six
members of which three members were nominated by TPG. 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 representative. Additionally, TPG has the right
(which has been waived for the Public 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 of the Company by purchasing additional shares on
the same terms and conditions. However, this right expires should TPG's
ownership interest fall below 20%. See "Interests of Management in Certain
Transactions."

SHARES ELIGIBLE FOR FUTURE SALE

After giving pro forma effect to the Offerings and the Capitalization
Adjustments, the Company would have had 19,498,269 Common Shares outstanding as
of October 15, 1996 (20,038,269 shares assuming exercise of the Underwriters'
over-allotment option in full). The Common Shares sold in the Public Offering
will be freely tradable without restrictions or further registration under the
Securities Act of 1933, as amended (the "Securities Act"). Of the 8,408,038
Common Shares beneficially owned by TPG upon the close of the TPG Offering
7,608,038 Common Shares will be "restricted" securities within the meaning of
the Securities Act as a result of the issuance thereof in a private transaction.
The Company believes that such "restricted"

12
<PAGE> 13

Common Shares will become eligible for sale on the open market under Rule 144
from time to time after December 21, 1997. In connection with the Public
Offering, 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
Donaldson, Lufkin & Jenrette Securities Corporation. See "Underwriting."

In addition, the Company has granted certain registration rights to TPG.
After December 21, 1997 and until December 21, 2000, TPG has the right, subject
to certain conditions, to demand that its stock be registered under the
Securities Act on one occasion. TPG also has "piggyback" registration rights
and, subject to certain conditions, may participate in a future registration by
the Company of Common Shares (or securities convertible into or exchangeable
for, or options, warrants or other rights to acquire, Common Shares) under the
Securities Act. TPG has waived its "piggyback" registration rights with regard
to the Public Offering. 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.

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. The loss of the
services from 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 -- Directors
and Executive Officers."

COMPETITION

The Company operates in a highly competitive environment. The Company
competes with major 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."

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. State and federal statutes and regulations require permits for
drilling, reworking and recompletion operations, drilling bonds and reports
concerning operations. 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 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.
See "Business and Properties -- Regulations."

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

13
<PAGE> 14

not had a material effect on the Company's capital expenditures, earnings or
competitive position. 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. 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 -- Environmental Regulations."

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

The Company'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 Company'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 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. As of the close of 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 the Company's Board of Directors rather
than pursue non-negotiated takeover attempts. These existing anti-takeover
provisions 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 "Canadian Taxation and the Investment Canada Act" and
"Description of Capital Stock."

NO DIVIDENDS

During the last five fiscal years, the Company has not paid any dividends
on its outstanding Common Shares, nor does the Company intend to do so. In
addition, the Company is restricted from doing so under its Credit Facility. The
Company currently intends to retain its cash for the continued expansion of its
business, including exploration, development and acquisition activities.

FORWARD-LOOKING INFORMATION

All statements other than statements of historical fact contained in this
Prospectus, including statements in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Business and Properties,"
are forward-looking statements. Forward-looking statements in this Prospectus
generally are accompanied by words such as "anticipate," "believe," "estimate,"
"project" or "expect" or similar statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, no
assurance can be given that such expectations will prove correct. Factors that
could cause the Company's results to differ materially from the results
discussed in such forward-looking statements include the aforementioned risks
described under "Risk Factors," such as the 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, the competition from
other exploration, development and production companies and the effects of
governmental and environmental regulation. All forward-looking statements in
this Prospectus are expressly qualified in their entirety by the cautionary
statements in this paragraph.

14
<PAGE> 15

CONCURRENT OFFERINGS

Concurrent with the Public Offering, the Company will sell an additional
800,000 Common Shares to TPG at a price equal to the price to the public per
share set forth on the cover of this Prospectus less underwriting discounts and
commissions. The Public Offering and the TPG Offering are each conditioned on
the consummation of the other.

USE OF PROCEEDS

The net proceeds to the Company from the sale of Common Shares in the
Offerings are estimated to be approximately $52.5 million ($59.0 million if the
Underwriters' over-allotment option is exercised in full). From these proceeds,
the Company intends to repay its borrowings under the Credit Facility to better
position the Company for future acquisition and development activities. As of
October 15, 1996, the Credit Facility had an outstanding balance of $48.0
million and an average interest rate of 6.8% per annum. The Credit Facility is
currently a revolving credit facility that will convert to a three-year term
loan in May 1998, unless renewed or extended. The Company borrowed $39.9 million
against this Credit Facility during the second quarter of 1996, primarily to
fund the Hess Acquisition, the Ottawa Acquisition and other acquisitions. See
"Business and Properties -- Acquisitions of Oil and Natural Gas Properties."
Since June 30, 1996, an additional $8.0 million has been borrowed to fund the
Company's development program. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- New Credit Facility." The
remainder of the proceeds from the Offerings will be used to fund future capital
expenditures related to acquisition, development, and exploration activities,
increase working capital or for general corporate purposes. To the extent that
the net proceeds of the Offerings are not immediately used, they will be
invested in investment grade short-term interest-bearing obligations.

15
<PAGE> 16

PRICE RANGE OF COMMON SHARES AND DIVIDEND POLICY

The Company's Common Shares have been listed on the Nasdaq National Market
("NASDAQ") since August 25, 1995 and on The Toronto Stock Exchange ("TSE") in
Toronto, Ontario, Canada, since February 14, 1984 and currently trade under the
symbols "DENRF" and "DNR," respectively. Due to the one-for-two reverse stock
split, the Common Shares will trade on NASDAQ under the symbol "DENFD" through
November 13, 1996. The following table summarizes the high and low last reported
sales prices on days in which there were trades of the Common Shares on NASDAQ
and on the TSE (as reported by such exchanges) for each quarterly period during
the last two fiscal years and to date during 1996. The following prices have
been adjusted for the one-for-two reverse stock split effective on October 10,
1996.

<TABLE>
<CAPTION>
NASDAQ TSE
-------------- --------------
HIGH LOW HIGH LOW
----- ----- ----- -----
(U.S. $) (CDN. $)
<S> <C> <C> <C> <C>
1994
First Quarter.......................................... -- -- 8.00 6.30
Second Quarter......................................... -- -- 8.80 7.00
Third Quarter.......................................... -- -- 9.00 7.20
Fourth Quarter......................................... -- -- 8.80 7.10
1995
First Quarter.......................................... -- -- 7.80 6.60
Second Quarter......................................... -- -- 8.70 7.00
Third Quarter.......................................... 6.74 5.32 8.70 7.00
Fourth Quarter......................................... 6.26 5.50 8.70 7.10
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 13.70
Fourth Quarter (through October 24, 1996).............. 13.91 12.50 18.75 17.00
</TABLE>

The last reported sales prices of the Common Shares on NASDAQ and the TSE
on October 24, 1996, as reported by such exchanges, were U.S. $13.91 per share
and Cdn. $18.75 per share, respectively.

During the last five fiscal years, the Company has not paid any dividends
on its outstanding Common Shares, nor does the Company intend to do so in the
foreseeable future. In addition, the Company is prohibited from doing so under
its Credit Facility. See "Management's Discussions and Analysis of Financial
Condition and Results of Operations -- New Credit Facility."

As of October 15, 1996, to the best of the Company's knowledge, the Common
Shares were held of record by approximately 1,200 holders.

16
<PAGE> 17

CAPITALIZATION

The following table sets forth the capitalization of the Company as of June
30, 1996 and as adjusted to give effect to the Capitalization Adjustments and
the application of the $52.5 million estimated net proceeds from the Offerings,
as if each had been consummated as of June 30, 1996. See "Use of Proceeds." This
table should be read in conjunction with the Company's Consolidated Financial
Statements and related notes thereto, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and other financial information
included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
------------------------
ACTUAL AS ADJUSTED
-------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents.............................................. $ 3,085 $ 15,999
======== ========
Long-term debt:
Revolving bank loan.................................................. $ 40,000 $ --
Convertible debentures............................................... 2,930 --
Other notes payable.................................................. 34 34
-------- --------
Total long-term debt......................................... 42,964 34
-------- --------
Convertible First Preferred Shares, Series A
1,500,000 authorized; $10 par value; 1,500,000 and -0- shares
outstanding, respectively......................................... 15,759 --
-------- --------
Shareholders' equity(1):
Common Shares, no par value; unlimited shares authorized; 11,632,215
and 19,427,677 outstanding, respectively(2)....................... 51,226 122,946
Retained earnings(3).............................................. 6,032 5,915
-------- --------
Total shareholders' equity................................... 57,258 128,861
-------- --------
Total capitalization....................................... $115,981 $ 128,895
======== ========
</TABLE>

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

(1) Excludes 1,043,425 outstanding stock options as of June 30, 1996,
exercisable at various prices ranging from $2.50 to $11.36 per share with a
weighted average price of $7.36 (of which 503,800 were currently
exercisable), and 700,000 Common Shares reserved for issuance upon exercise
of the two series of Common Share purchase warrants.

(2) Includes the issuance of: (i) 4,400,000 Common Shares upon the closing of
the Offerings, (ii) 2,816,372 Common Shares in exchange for the Convertible
Preferred, (iii) 308,642 Common Shares for the principal and 7,948 Common
Shares for the interest from October 15, 1996 (the date of conversion) to
April 13, 1997 on the 9 1/2% Convertible Debentures, (iv) 187,500 Common
Shares for the 6 3/4% Convertible Debentures converted on July 31, 1996 and
(v) 75,000 Common Shares for the Cdn. $8.40 warrants exercised on August 27,
1996. See "Interests of Management in Certain Transactions."

(3) Includes a $117,000 charge to earnings for the imputed interest from October
15, 1996 to April 13, 1997 for the pro forma early conversion of the 9 1/2%
Convertible Debentures. This interest was paid in 7,948 Common Shares at a
price of Cdn. $14.72 per Common Share.

17
<PAGE> 18

PRO FORMA OPERATING RESULTS

The following unaudited pro forma consolidated statements of income for the
year ended December 31, 1995 and the six months ended June 30, 1996 reflect the
historical information of the Company as adjusted to give effect to: (i) revenue
and direct operating expenses of the Ottawa Acquisition, (ii) revenue and direct
operating expenses of the Hess Acquisition, (iii) the pro forma adjustments
related to the Ottawa and Hess Acquisitions ("Acquisition Adjustments") and (iv)
the Capitalization Adjustments, the Offerings and application of the estimated
net proceeds therefrom, in each case as if such transactions had been
consummated as of the beginning of each respective period. A pro forma balance
sheet is not presented as both the Ottawa and Hess Acquisitions had been
consummated before June 30, 1996. Additional property acquisitions were made in
1996 that have not been included in the pro forma adjustments since they are
immaterial individually and in the aggregate. See "Capitalization."

The unaudited pro forma consolidated statements of income are provided for
comparative purposes only and should be read in conjunction with the historical
consolidated financial statements of the Company and the historical statements
of revenues and direct operating expenses of the properties acquired in the
Ottawa Acquisition and the Hess Acquisition. The pro forma information presented
is not necessarily indicative of the results that actually would have been
obtained if such transactions had occurred at the beginning of the indicated
periods or of future results.

18
<PAGE> 19

UNAUDITED PRO FORMA STATEMENT OF INCOME

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1996
--------------------------------------------------------------------------------------
CAPITALIZATION
DENBURY OTTAWA HESS ACQUISITION AND OFFERING PRO FORMA
HISTORICAL ACQUISITION ACQUISITION ADJUSTMENTS ADJUSTMENTS COMBINED
---------- ----------- ----------- ----------- -------------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and
related product
sales................. $ 20,650 $ 854 $ 7,070 $ -- $ -- $28,574
Interest and other....... 124 -- -- -- -- 124
------- ----- ------- ------- ------- -------
Total revenues... 20,774 854 7,070 -- -- 28,698
------- ----- ------- ------- ------- -------
Expenses:
Production............... 5,350 168 2,352 -- -- 7,870
General and
administrative........ 1,656 -- -- 250(1) -- 1,906
Interest................. 681 -- -- 1,041(2) (1,489)(3) 233
Imputed preferred
dividend.............. 759 -- -- -- (759)(6) --
Loss on early
extinguishment of
debt.................. 440 -- -- -- -- 440
Depletion and
depreciation.......... 7,382 -- -- 2,717(4) -- 10,099
Franchise taxes.......... 107 -- -- -- -- 107
------- ----- ------- ------- ------- -------
Total expenses... 16,375 168 2,352 4,008 (2,248) 20,655
------- ----- ------- ------- ------- -------
Income before tax.......... 4,399 686 4,718 (4,008) 2,248 8,043
Provision for federal
income tax............... (1,804) (233)(5) (1,604)(5) 1,362(5) (506)(5) (2,785)
------- ----- ------- ------- ------- -------
Net income................. $ 2,595 $ 453 $ 3,114 $(2,646) $ 1,742 $ 5,258
======= ===== ======= ======= ======= =======
Net income per common
share.................... $ 0.23 $ 0.27
======= =======
Average common shares
outstanding.............. 11,512 19,321
======= =======
</TABLE>

See notes on the following page.

19
<PAGE> 20

UNAUDITED PRO FORMA STATEMENT OF INCOME

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
--------------------------------------------------------------------------------------
CAPITALIZATION
DENBURY OTTAWA HESS ACQUISITION AND OFFERING PRO FORMA
HISTORICAL ACQUISITION ACQUISITION ADJUSTMENTS ADJUSTMENTS COMBINED
---------- ----------- ----------- ----------- -------------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and
related product
sales................. $ 20,032 $ 2,954 $18,210 $ -- $ -- $41,196
Interest and other....... 77 -- -- -- -- 77
------- ------ ------- -------- ------ -------
Total revenues... 20,109 2,954 18,210 -- -- 41,273
------- ------ ------- -------- ------ -------
Expenses:
Production............... 6,789 659 7,888 -- 15,336
General and
administrative........ 1,832 -- -- 500(1) -- 2,332
Interest................. 2,085 -- -- 3,338(2) (3,822)(3) 1,601
Loss on early
extinguishment of
debt.................. 200 -- -- -- -- 200
Depletion and
depreciation.......... 8,022 -- -- 8,499(4) -- 16,521
Franchise taxes.......... 100 -- -- -- -- 100
------- ------ ------- -------- ------ -------
Total expenses... 19,028 659 7,888 12,337 (3,822) 36,090
------- ------ ------- -------- ------ -------
Income before tax.......... 1,081 2,295 10,322 (12,337) 3,707 5,183
Provision for federal
income tax(5)............ (367) (780) (3,509) 4,194 (1,299) (1,761)
------- ------ ------- -------- ------ -------
Net income................. $ 714 $ 1,515 $ 6,813 $ (8,143) $2,523 $ 3,422
======= ====== ======= ======== ====== =======
Net income per common
share.................... $ 0.10 $ 0.29
======= =======
Average common shares
outstanding.............. 6,870 11,921
======= =======
</TABLE>

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

(1) Reflects an increase of $500,000 in annual 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.

(2) Reflects an increase in interest expense for the period to reflect the
$44.5 million of bank debt that would have been required to fund the
Hess and Ottawa Acquisitions had they occurred as of the beginning of each
respective period. The applicable interest rate was reduced from the
Company's historical bank interest rate by 1 3/8% for such periods to
reflect the reduction in the margin over LIBOR as a result of the new
Credit Facility.

(3) Interest expense was: (i) reduced to reflect receipt of $52.5 million in
estimated net proceeds from the Offering and the $460,000 from the exercise
on August 27, 1996 of 75,000 of the Cdn. $8.40 Warrants and the application
thereof to reduce debt, in each case as if the funds were received and
applied at the beginning of each period ($3.8 million and $1.6 million for
1995 and 1996, respectively), (ii) increased to reflect the imputed
interest on the Debentures from the end of each respective period through
April 13, 1997, in addition to the interest actually charged on the
Debentures during the period presented ($167,000 and $87,000 for 1995 and
1996, respectively), and (iii) reduced to reflect the conversion as of the
beginning of each period of the 6 3/4% Convertible Debentures that were
converted into 187,500 Common Shares on July 31, 1996 ($74,000 and $35,000
for 1995 and 1996, respectively).

(4) Depreciation, depletion and amortization ("DD&A") expense has been computed
using the unit of production method and reflects the Company's increased
investment in oil and natural gas properties. The July 1, 1996 estimated
net proved reserves prepared by Netherland & Sewell were used in the DD&A
computation for the Hess and Ottawa Acquisitions.

(5) Income taxes were computed on a pro forma basis using the U.S. federal
statutory rate of 34%.

(6) Reflects the elimination of the imputed preferred dividend on the
Convertible Preferred that will be converted into Common Shares concurrent
with the completion of the Offering.

20
<PAGE> 21

SELECTED CONSOLIDATED FINANCIAL DATA

The following selected consolidated financial data of the Company for each
year for the five-year period ended December 31, 1995 are derived from the
Company's audited Consolidated Financial Statements. The selected consolidated
financial data for the six-month periods ended June 30, 1995 and 1996 are
unaudited and include, in management's opinion, all adjustments (consisting of
only normal recurring adjustments) necessary to present fairly the results for
such interim periods. Results for the interim periods are not necessarily
indicative of results to be expected for the entire year. The selected
consolidated financial data should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Company's Consolidated Financial Statements and the Notes thereto included
elsewhere herein. See Note 8 of the Notes to Consolidated Financial Statements
for a reconciliation between Canadian and U.S. GAAP.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------------- ------------------
1991 1992 1993 1994 1995 1995 1996
------- ------ ------- ------- ------- ------- -------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
SELECTED INCOME STATEMENT DATA:
Revenue:
Oil, natural gas and related product sales.... $ 1,962 $1,912 $ 5,868 $12,692 $20,032 $ 8,997 $20,650
Interest income............................... 5 40 76 23 77 21 124
------- ------ ------- ------- ------- ------- -------
Total revenues............................ 1,967 1,952 5,944 12,715 20,109 9,018 20,774
Expenses:
Production.................................... 669 634 2,067 4,309 6,789 3,128 5,350
General and administrative.................... 437 955 782 1,105 1,832 935 1,656
Interest...................................... 16 8 83 1,146 2,085 927 681
Imputed preferred dividends................... -- -- -- -- -- -- 759
Loss on early extinguishment of debt.......... -- -- -- -- 200 200 440
Depletion and depreciation.................... 1,973 690 1,898 4,209 8,022 3,075 7,382
Franchise taxes............................... -- -- -- 65 100 42 107
------- ------ ------- ------- ------- ------- -------
Total expenses............................ 3,095 2,287 4,830 10,834 19,028 8,307 16,375
------- ------ ------- ------- ------- ------- -------
Income (loss) before the following:............. (1,128) (335) 1,114 1,881 1,081 711 4,399
Gain on sale of Canadian properties........... -- -- 966 -- -- -- --
------- ------ ------- ------- ------- ------- -------
Income (loss) before income taxes............... (1,128) (335) 2,080 1,881 1,081 711 4,399
Provision for federal income taxes.............. -- -- (345) (718) (367) (242) (1,804)
------- ------ ------- ------- ------- ------- -------
Net income (loss)............................... $(1,128) $ (335) $ 1,735 $ 1,163 $ 714 $ 469 $ 2,595
======= ====== ======= ======= ======= ======= =======
Net income (loss) per common share.............. $ (0.58) $(0.11) $ 0.35 $ 0.19 $ 0.10 $ 0.07 $ 0.23
======= ====== ======= ======= ======= ======= =======
Weighted average common shares outstanding...... 1,952 2,949 4,990 6,240 6,870 6,536 11,512
======= ====== ======= ======= ======= ======= =======
OTHER DATA:
Operating cash flow(1).......................... $ 846 $ 354 $ 3,030 $ 6,185 $ 9,394 $ 4,025 $13,303
Capital expenditures............................ 1,068 6,189 29,855 16,903 28,524 10,506 60,733
Adjusted EBITDA(2).............................. 856 323 3,019 7,213 11,311 4,892 13,537
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF JUNE 30,
------------------------------------------------- -------------------
1991 1992 1993 1994 1995 1995 1996
------ ------ ------- ------- ------- ------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Total assets.................................... $3,466 $8,225 $35,978 $48,964 $77,641 $56,917 $132,900
Working capital (deficiency).................... (125) 1,369 (1,410) (1,620) 6,862 (2,262) (1,184)
Long-term debt, net of current maturities....... -- -- 6,177 16,536 3,474 20,491 42,964
Convertible preferred stock..................... -- -- -- -- 15,000 -- 15,759
Shareholders' equity............................ 2,882 7,548 24,431 25,962 53,501 28,891 57,258
</TABLE>

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

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

(2) Adjusted 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. Adjusted EBITDA is not intended to represent cash
flows for the period, nor has it been presented as an alternative to
operating income nor as an indicator of operating performance. It should not
be considered in isolation or as a substitute for measures of performance
prepared in accordance with GAAP. See the Company's Consolidated Statements
of Cash Flows in the Consolidated Financial Statements included elsewhere in
this Prospectus. Adjusted EBITDA is included in this Prospectus because it
is a basis upon which the Company assesses its financial performance.

21
<PAGE> 22

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

ACQUISITION OF HESS PROPERTIES

The Company completed several property acquisitions during the first half
of 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 was approximately 5.9 MMcf/d
and 1,962 Bbls/d, which increased the Company's average daily production during
the first half of 1996 by approximately 2.0 MMcf/d and 650 Bbls/d, or 1,000
BOE/d. As of July 1, 1996, the properties in this acquisition had estimated net
proved reserves of approximately 5.9 MMBOE which consisted of approximately 5.0
MMBbls and approximately 5.6 Bcf, with a PV10 Value of $43.1 million.
Approximately 90% of the PV10 Value was for wells on which Denbury assumed
operations with an average working interest of approximately 80%. See "Business
and Properties -- Acquisitions of Oil and Natural Gas Properties."

OTHER ACQUISITIONS

In addition to the Hess Acquisition, during the first half of 1996 the
Company completed other acquisitions totaling $10.8 million. The largest of
these was the Ottawa Acquisition, 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,
which were acquired during April 1996 for approximately $7.5 million. The
average daily production from the Ottawa Acquisition during April, May and June
1996 was approximately 1.5 MMcf/d and 354 Bbls/d, which increased the Company's
average daily production during the first half of 1996 by approximately 760
Mcf/d and 175 Bbls/d, or 300 BOE/d.

In addition to the Ottawa Acquisition, the Company spent an additional $3.3
million on four other acquisitions, primarily in Louisiana. These properties
contributed approximately 1.5 MMcf/d and 50 Bbls/d, or 300 BOE/d, to the
Company's average daily production during the first half of 1996. See "Business
and Properties -- Acquisitions of Oil and Natural Gas Properties." As of July 1,
1996, the Company's estimated net proved reserves for all of these other
acquisitions, including the Ottawa Acquisition, totaled approximately 1.1 MMBbls
and 13.1 Bcf or 3.3 MMBOE, with a PV10 Value of $24.1 million.

NEW CREDIT FACILITY

In order to fund these acquisitions, improve the terms and increase the
size of its previous credit facility, the Company entered into the new $150.0
million Credit Facility. This refinancing closed during the second quarter of
1996 and has a borrowing base as of October 15, 1996 of $60.0 million. 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. 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, at rates ranging
from LIBOR plus 7/8% to LIBOR plus 1 3/8%. 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 and (iv) a prohibition of most
debt and corporate guarantees.

22
<PAGE> 23

CAPITAL RESOURCES AND LIQUIDITY

As outlined in the following table, in each of the last three years and
during the first half of 1996, the Company made capital expenditures which
required additional debt and equity capital to supplement cash flow from
operations.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
------------------------------ JUNE 30,
1993 1994 1995 1996
-------- -------- -------- ----------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Acquisitions of oil and natural gas
properties.................................... $ 20,076 $ 6,606 $ 16,763 $ 47,974
Oil and natural gas expenditures................ 9,779 10,297 11,761 12,759
------- ------- ------- -------
Total................................. $ 29,855 $ 16,903 $ 28,524 $ 60,733
======= ======= ======= =======
</TABLE>

Since January 1, 1993, the Company has made total capital expenditures of
$136.0 million, which were primarily financed with equity ($58.1 million,
including the Convertible Preferred), debt ($43.2 million) and cash from
operations ($31.9 million). During 1995, the Company's sources of capital, other
than cash flow from operations, were a $1.8 million issue of subordinated debt,
a $2.4 million private placement of Common Shares and the $39.5 million, net of
expenses, TPG Placement in December 1995. During the first half of 1996, the
Company's funds were provided by operating cash flow and bank debt, beginning
the year with $100,000 of outstanding bank debt and ending the six month period
with $40.0 million of bank debt outstanding.

As of June 30, 1996, the Company had a working capital deficit of $1.2
million and total bank debt of $40.0 million. The Company has budgeted
development expenditures for the remainder of 1996 that exceed its projected
cash flow. As of October 15, 1996, the Company had a borrowing base of $60.0
million with a total of $48.0 million drawn against the Credit Facility. With
the increased cash flow from the acquired properties and the undrawn portion of
the Credit Facility, the Company anticipates that it can fund its development
budget for the second half of 1996 of approximately $16.0 million and meet its
obligations in the foreseeable future. If external capital resources are limited
or reduced in the future, the Company can adjust its development expenditure
program accordingly. However, such adjustments could limit, or even eliminate,
the Company's future growth. In addition to its development 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 equity financing from the
Offerings in order to reduce its debt levels and better position the Company for
future opportunities.

Sources and Uses of Funds

During the first half of 1996, the Company spent approximately $10.7
million on oil and natural gas development expenditures, $48.0 million on the
previously discussed oil and natural gas acquisitions, and approximately $2.0
million on geological, geophysical and acreage expenditures. The development
expenditures included $3.9 million spent on drilling and the balance of $6.8
million spent on workover costs. These expenditures were funded by bank debt,
available cash and cash flow from operations.

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 the balance of $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

23
<PAGE> 24

December 1995 with a portion of the $39.5 million of net proceeds from the TPG
Placement. See "Interests of Management in Certain Transactions."

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.

During 1993, the Company made capital expenditures of approximately $29.9
million, of which $20.1 million was for acquisitions. The remaining $9.8 million
was expended on drilling, completions and equipment. Included in the 1993
capital expenditures was approximately $8.7 million for the acquisition of the
several properties from a major oil company in Mississippi (the "Mississippi
Acquisition"), approximately $1.8 million for the acquisition and $4.7 million
for the exploitation of the Puckett field in Mississippi and approximately $9.0
million for the acquisition of properties in Southern Louisiana (the "Louisiana
Acquisition").

The Company's largest source of funds in 1993 was net proceeds of $15.1
million from the issuance of equity in Canada, principally comprised of three
offerings totaling 2,142,500 Common Shares at an average price of Cdn. $9.16 per
share. In each of these offerings, the Company issued special warrants that were
subsequently converted into Common Shares. In addition to cash provided by
equity during 1993, the Company also received $7.6 million of cash from
long-term debt, $3.0 million of cash flow provided by operations and $3.1
million of cash from the disposal of the Company's remaining Canadian
properties.

RESULTS OF OPERATIONS

Comparison of Six Months Ended June 30, 1996 and June 30, 1995

Denbury continued to increase its daily production with an average of 5,453
BOE/d during the first quarter of 1996 and 7,841 BOE/d during the second
quarter, for an overall average of 6,647 BOE/d during the first half of 1996 as
compared to 3,843 BOE/d for the comparable six month period of 1995 (73%
increase). The combination of the Hess and Ottawa Acquisitions contributed
approximately 1,300 BOE/d to the Company's average daily production during the
first half of 1996. The production from these two acquisitions for the first six
months of 1996, including the periods when they were not owned by the Company,
was approximately 3,964 BOE/d. In addition, the Gibson Acquisition contributed
approximately 1,039 BOE/d to the Company's average daily production during the
first half of 1996, with the balance of the increase, 465 BOE/d, primarily
attributable to the Company's development and exploitation program.

In addition, oil and natural gas prices improved substantially over 1995
levels during the first half of 1996. Average oil prices were $17.39 per Bbl as
compared to $14.92 per Bbl for the comparable period in 1995 (17% increase) and
natural gas prices increased to an average price of $2.80 per Mcf during the
first half of 1996 as compared to $1.85 for the comparable period in 1995 (51%
increase). The Company averaged a sales price of $17.07 per BOE during the first
half of 1996 as compared to $12.94 per BOE during the first half of 1995 (32%
increase).

As a result of the aforementioned production and price increases and
property acquisitions, oil and natural gas revenue increased 130% to $20.7
million during the first half of 1996 from $9.0 million for the first half of
1995. Approximately $3.7 million of the increase was related to the Hess and
Ottawa Acquisitions, approximately $3.3 million to the Gibson Acquisition,
approximately $3.4 million to the increase in product prices, and the balance
due to an increase in production as a result of development and other
acquisition activities. Production expenses also increased 71% to $5.4 million
during the first half of 1996 as compared to $3.1 million for the comparable
period in 1995. Production expenses on a BOE basis were $4.42 and $4.50 for the
first half of 1996 and 1995 respectively, a decline of 2% from first half 1995
levels. The first quarter of 1996 operating expenses were slightly less on a BOE
basis because a larger percentage of the first quarter's production was natural
gas (62% on a BOE basis), which typically has a lower operating cost per BOE
than

24
<PAGE> 25

oil. However, the second quarter included two months of operating expenses
relating to the Hess Acquisition which had an average production cost of $6.27
per BOE. In July 1996, the Company assumed operations of these Hess Acquisition
properties and will focus on lowering the production costs during the last half
of 1996 to levels more consistent with the Company's average.

General and administrative expenses increased by 77% to $1.7 million for
the first half of 1996 from $935,000 for the comparable period in 1995. On a per
BOE basis, however, general and administrative costs remained relatively
consistent at $1.46 per BOE for the first half of 1996 as compared to $1.40 per
BOE for the comparable period in 1995. During the first half of 1996, the
Company conducted a review of salaries and awarded raises and bonuses to its
employees. Bonuses, including related payroll taxes, amounted to approximately
$225,000. 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 as
Amerada Hess remained the operator of record until that date. During the first
half of 1995, the Company had non-recurring expenses of approximately $190,000
relating to personnel changes. The Company's objective is to lower general and
administrative costs for the last half of 1996 on a BOE basis to a level close
to the overall average for 1995 of $1.25 per BOE.

As a result of the $39.5 million TPG Placement and the corresponding
retirement of bank debt, the only interest-bearing debt outstanding during the
first quarter of 1996 was approximately $3.3 million of subordinated debt and
minor trade notes payable. During the second quarter, however, the Company
borrowed $39.9 million on its Credit Facility in order to close the Hess and
Ottawa Acquisitions. The net effect was an overall 27% reduction in interest
expense to $681,000 for the first half of 1996, from $927,000 for the comparable
period of 1995.

During the first half of 1996, the Company expensed $759,000 relating to an
imputed dividend on the Convertible Preferred. Under Canadian GAAP this is
reported as an operating expense, while under U.S. GAAP this would be deducted
from net income to arrive at net income applicable to the common shareholders.
This charge to earnings reflects the increase in the mandatory redemption value
of the Convertible Preferred during the period. The Company has not, nor does it
intend to, pay any dividends on the Convertible Preferred.

Also during the first half of 1996, the Company had a $440,000 charge
relating to a loss on early extinguishment of debt. These costs relate to the
remaining unamortized debt issue costs of the Company's prior credit facility
with ING Capital Corporation, 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 item relating to another bank refinancing. Under U.S. GAAP, a
loss on early extinguishment of debt would be an extraordinary item rather than
a normal operating expense as required by Canadian GAAP.

DD&A increased by 140% to $7.4 million for the first half of 1996 as
compared to $3.1 million for the first half of 1995. DD&A per BOE increased 17%
to $6.10 per BOE for the first half of 1996 from $5.22 per BOE for the year
ended December 31, 1995 due to a large percentage of the 1995 and 1996 capital
expenditures relating to acquisitions, which have had a higher per unit cost for
the Company than those reserves added by development expenditures.

The deferred tax provision for the first half of 1996 was approximately
41%, which is higher than the U.S. statutory rate due to certain non-deductible
Canadian expenses and the non-deductible imputed preferred dividend expense of
$759,000. The Company did not have a current tax provision as it generated a
loss for federal income tax purposes.

Primarily as a result of increased production and improved product prices,
net income increased 453% to $2.6 million ($0.11 per common share) for the first
half of 1996 from $469,000 ($0.04 per common share) during the first half of
1995. Cash flow from operations (before the change in non-cash working capital
balances) also increased 231% over first half 1995 levels to $13.3 million
during the first half of 1996 from $4.0 million during the first half of 1995,
also primarily due to strong oil and natural gas prices as well as increased
production.

25
<PAGE> 26

Comparison of Years Ended December 31, 1995 and December 31, 1994

During 1995, production for the year averaged 4,207 BOE/d, which compares
to 2,859 BOE/d in 1994 (a 47% increase), with a higher percentage increase in
revenue of $7.3 million (a 58% increase) between the two years. Oil production
for 1995 increased by 49% from 1,340 Bbls/d in 1994 to 1,995 Bbls/d in 1995 and
natural gas production increased by 46% from 9,113 Mcf/d in 1994 to 13,271 Mcf/d
in 1995. Approximately 240 BOE/d was attributable to the Gibson Acquisition with
the balance primarily attributable to the Company's development and exploitation
program. In addition, the average oil price increased 8% from $13.84 per Bbl in
1994 to $14.90 per Bbl in 1995 and the natural gas price also increased 7%, from
an average price of $1.78 per Mcf in 1994 to $1.90 per Mcf during 1995. The
Company realized a $800,000 gas hedging gain during 1995 which added $0.17 per
Mcf to its average net natural gas price. The Company does not have any oil or
natural gas hedges in place for 1996 due to the relatively strong commodity
prices to date in 1996 and the reduced debt levels and resultant reduced risk of
price changes on cash flow.

The combination of production and price increases caused oil and natural
gas revenue to increase 57%, from $12.7 million in 1994 to $20.0 million in
1995. Approximately $700,000 of the increase is attributable to the Gibson
Acquisition, approximately $1.3 million to product price increases with the
balance due to the increases in production resulting from development and other
acquisition activities.

Production expenses were $6.8 million in 1995 compared to $4.3 million in
1994 as a result of increased production, although on a BOE basis, production
expense had a slight increase of seven percent to $4.42 per BOE in 1995 from
$4.13 in 1994.

General and administrative expenses increased by 65% from $1.1 million in
1994 to $1.8 million in 1995 as a result of the Company's continuing growth. On
a per BOE basis, these costs also increased by 12% from $1.12 per BOE in 1994 to
$1.25 per BOE in 1995 primarily due to $190,000 of expenses during 1995 ($0.12
per BOE) for costs relating to non-recurring personnel changes.

Interest expense increased significantly to $2.1 million in 1995 from $1.1
million in 1994. Approximately $19.4 million of bank debt was borrowed during
1995 primarily for acquisitions, increasing bank debt levels to a peak of $32.2
million just before year end when the bank debt was reduced to $100,000 with the
proceeds from the TPG Placement. Interest expense on a BOE basis was $1.26 in
1995 versus $0.99 per BOE in 1994 due to the net borrowing during the first
eleven months of 1995.

Cash flow from operations in 1995 (before the changes in non-cash working
capital balances) increased over 1994 by 52%, to $9.4 million in 1995 from $6.2
million in 1994. On a per BOE basis, cash flow from operations in 1995 also
increased over 1994 by 3%, to $6.12 in 1995 from $5.93 in 1994. Higher product
prices more than offset the higher interest costs, operating expenses and
general and administrative costs.

DD&A increased by 91% to $8.0 million in 1995 from $4.2 million in 1994.
DD&A per BOE also increased 30% from $4.03 in 1994 to $5.22 in 1995 due to a
large percentage of the 1995 capital expenditures (60%) relating to
acquisitions, which have had a higher per unit cost for the Company than those
reserves added by development expenditures.

During 1995, the Company recognized $200,000 of expenses relating to the
loss on early extinguishment of debt. These costs relate to the unamortized debt
issue costs which were written off when the Company changed its primary bank
lender in April 1995. Under U.S. GAAP, these costs would be an extraordinary
item, rather than a normal operating expense as required under Canadian GAAP.

The deferred tax provision for 1995 was approximately 34%, slightly less
than 1994's provision of approximately 38%. The 1994 provision was slightly
higher than the U.S. statutory rate due to the mix of Canadian versus U.S.
expenses. The Company did not have a current tax provision as it generated a
loss for federal income tax purposes.

Net income decreased by 39% to $714,000 in 1995 from $1.2 million in 1994.
Although every category of revenue and expense increased substantially between
the two years, the reduced net income was primarily a result of certain
nonrecurring charges and a disproportionate increase in depreciation and
depletion expense as compared to the increase in revenue.

26
<PAGE> 27

Comparison of Years Ended December 31, 1994 and December 31, 1993

During 1994, production for the year averaged 2,859 BOE/d, which compares
to 1,194 BOE/d in 1993. Oil production for 1994 increased by 56% from 858 Bbls/d
in 1993 to 1,340 Bbls/d in 1994 and natural gas production increased by 353%
from 2.0 MMcf/d in 1993 to 9.1 MMcf/d in 1994. However, natural gas prices
decreased 14%, from 1993 average prices of $2.06 per Mcf to the $1.78 per Mcf in
1994 with oil prices remaining almost constant at $13.91 per Bbl in 1993 and
$13.84 per Bbl in 1994. The net effect of the production increase and natural
gas price decrease was an increase in revenue for 1994 of 116% over 1993
revenue, with 1994 oil and natural gas revenue of $12.7 million as compared to
1993 levels of $5.9 million. Approximately $7.8 million of the increase was
attributable to production increases, partially offset by the drop in revenue of
approximately $931,000 attributable to the decline in natural gas prices.

Production expenses were $4.3 million in 1994 compared to $2.1 million in
1993 as a result of increased production. On a BOE basis, production expense
declined by 13% to $4.13 per BOE in 1994 from $4.75 per BOE in 1993 as a result
of cost saving measures by the Company and the gas properties acquired in the
Louisiana Acquisition late in 1993 which generally have a lower operating cost
per BOE than oil properties.

General and administrative expenses increased by 41% from $782,000 in 1993
to $1.1 million in 1994. This reflects the Company's increased activity and the
establishment of the second major operating area in Southern Louisiana in late
1993. On a per BOE basis, however, these costs decreased by 38% from $1.80 per
BOE in 1993 to $1.12 per BOE in 1994.

Interest expense increased significantly to $1.1 million in 1994 from
$83,000 in 1993. Approximately $7.6 million of interest-bearing debt was added
in late 1993 primarily to complete the Louisiana Acquisition, and further
acquisitions during 1994 increased debt to $16.4 million by year end.
Additionally, the weighted average interest rate increased by 0.9 percentage
points during 1994 from 8.0% in 1993 to 8.9% in 1994. Interest expense was $0.99
per BOE in 1994 versus a net interest income of $0.04 per BOE in 1993.

Cash flow from operations in 1994 (before the changes in non-cash working
capital balances) increased over 1993 by 104%, from $3.0 million in 1993 to $6.2
million in 1994. On a per BOE basis, however, cash flow from operations in 1994
decreased from 1993 levels by 15%, from $6.96 per BOE in 1993 to $5.93 per BOE
in 1994. Higher interest costs and lower product prices more than offset the
positive effects of lower per unit operating and general and administrative
costs.

DD&A increased by 122% to $4.2 million in 1994 from $1.9 million in 1993 as
a result of the 140% increase in production. The percentage increase in DD&A was
lower than the percentage increase in production due to the addition of
significant reserves at a lower cost per BOE. DD&A per BOE decreased 8% from
$4.36 in 1993 to $4.03 in 1994.

Deferred taxes represent approximately 38% of income before income taxes in
1994, an increase from the 17% in 1993. The 1993 tax provision was reduced by
the application of Canadian tax loss carry forwards against the one-time gain
from the sale of Canadian assets. The Company did not have a current tax
provision as it generated a loss for federal income tax purposes.

Net income, before the one-time gain in 1993 from the sale of Canadian
properties, increased by 51% to $1.2 million in 1994 from $769,000 in 1993,
primarily as a result of the increased production and associated revenue with a
less than proportionate increase in most expenses.

27
<PAGE> 28

BUSINESS AND PROPERTIES

THE COMPANY

The Company's address is 17304 Preston Road, Suite 200, Dallas, TX 75252
and the telephone number is (972) 380-1923.

BUSINESS STRATEGY

REGIONAL FOCUS. By focusing its efforts in the Gulf Coast region, primarily
Louisiana and Mississippi, the Company has been able to accumulate substantial
geological, reservoir and operating data which it believes provides it with a
significant competitive advantage. Given its experience in the Gulf Coast
region, the Company believes it is better able to proactively identify and
evaluate potential acquisitions, negotiate and close selected acquisitions on
favorable terms, and develop and operate the properties in an efficient and low-
cost manner once acquired. The Company believes the Gulf Coast represents one of
the most attractive regions in North America given the region's prolific
production history and the new 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 attractive northeastern U.S. markets, the Company typically
realizes natural gas prices in excess of those realized in many other producing
regions.

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<PAGE> 29

to acquisitions that fit within its criteria. The Company believes that due to
continuing rationalization of properties, primarily by major integrated and
independent energy companies, a strong backlog of acquisition opportunities
should continue. 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 Company's
recent Hess and Ottawa Acquisitions are illustrative of the type of
opportunities the Company seeks.

OIL AND NATURAL GAS OPERATIONS

Denbury operates in two core areas, Louisiana and Mississippi. The Company
operates 54 wells in Louisiana from an office in Houma and 107 wells in
Mississippi from an office in Laurel. The 12 largest oil and natural gas fields
owned by the Company constitute approximately 80% of its total reserves on both
a BOE and PV10 Value basis. Within these 12 fields, Denbury owns an average 84%
working interest and operates 77% of the wells, which comprise 54% of the
Company's PV10 Value. 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 mostly multiple
sandstone reservoirs with strong water-drive characteristics. 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

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<PAGE> 30

potential for larger discoveries, particularly of natural gas. The Company's
production in Louisiana is predominately natural gas, while the Company's
production in Mississippi is predominately oil.

The following tables set forth information with respect to Denbury's
properties, reserves, drilling and production activities. The information
included in this table about the Company's proved oil and natural gas reserve
estimates as of July 1, 1996 were prepared by Netherland & Sewell. See "Risk
Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves."

<TABLE>
<CAPTION>
1996 AVERAGE
PROVED RESERVES AS OF JULY 1, 1996 PRODUCTION(1)
----------------------------------------------- ---------------------- GROSS AVERAGE NET
OIL NATURAL GAS PV10 VALUE PV10 VALUE OIL NATURAL GAS PRODUCTIVE REVENUE
(MBBLS) (MMCF) (000'S)(2) % OF TOTAL (BBLS/D) (MCF/D) WELLS(3) INTEREST(3)
------- ----------- ---------- ---------- -------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LOUISIANA:
Lirette................ 290 28,566 $ 45,661 26.1% 157 7,897 11 60.1%
Gibson................. 309 6,732 14,879 8.5% 184 4,330 2 54.5%
South Chauvin.......... 144 7,362 8,857 5.0% 25 283 2 76.0%
Bayou Rambio........... 38 4,591 6,454 3.7% 30 2,200 1 72.2%
Lapeyrouse............. 127 2,578 6,025 3.4% 3 66 3 61.8%
Other Louisiana........ 1,484 10,863 29,425 16.8% 433 5,541 83 41.0%
------ ------ -------- ------ ----- ------ ---
Total Louisiana...... 2,392 60,692 111,301 63.5% 832 20,317 102 44.4%
------ ------ -------- ------ ----- ------ ---
MISSISSIPPI:
Eucutta................ 2,999 -- 20,751 11.8% 350 -- 36 71.9%
Davis.................. 2,375 -- 12,420 7.1% 622 -- 24 70.6%
South Thompson Creek... 516 -- 5,930 3.4% 116 -- 4 80.0%
West Yellow Creek...... 869 -- 4,657 2.7% 266 -- 7 78.2%
Quitman................ 854 -- 4,137 2.4% 61 -- 7 67.5%
Dexter................. -- 3,699 4,070 2.3% 1 1,643 8 48.3%
Puckett................ 750 40 3,845 2.2% 185 9 7 75.4%
Other Mississippi...... 818 699 5,103 2.9% 406 202 79 28.9%
------ ------ -------- ------ ----- ------ ---
Total Mississippi.... 9,181 4,438 60,913 34.8% 2,007 1,854 172 51.3%
------ ------ -------- ------ ----- ------ ---
OTHER.................... 152 677 3,041 1.7% 55 347 14 35.9%
------ ------ -------- ------ ----- ------ ---
COMPANY TOTAL............ 11,725 65,807 $175,255 100.0% 2,894 22,518 288 48.1%
====== ====== ======== ====== ===== ====== ===
</TABLE>

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

(1) Average production during the period from January 1, 1996 through June 30,
1996. Certain properties, including those purchased in the Hess and Ottawa
Acquisitions, were acquired during 1996. This table only includes production
during the periods when such properties were owned by the Company. See
"-- Production Volumes, Sales Prices and Production Costs" for pro forma
production data.

(2) The reserves were prepared using constant prices and costs in accordance
with the guidelines of the SEC, based on the prices received on a field by
field basis as of July 1, 1996. The oil price at that date was West Texas
Intermediate $20.00 per Bbl adjusted by field and a NYMEX Henry Hub natural
gas price average of $2.65 per MMBtu, also adjusted by field.

(3) Includes only productive wells in which the Company had a working interest
as of July 1, 1996.

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 areas
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. Thus 3-D seismic has become a valuable tool in exploration and
development throughout the onshore Gulf Coast and has been pivotal in
discovering

30
<PAGE> 31

significant reserves. The Company believes that the first generation of 3-D data
acquired in these swampy areas has the potential to identify significant
exploration prospects, particularly in the deeper geopressured sections below
12,000 feet.

Lirette

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. An
initial geological review indicated significant potential and in early 1994,
Denbury increased its interest in the field to an average 60% working interest
by acquiring additional interests from working interest partners in four
separate transactions. 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
early 1995 to increase the Company's ownership to its current average 78%
working interest.

As a result of two workovers and two wells drilled during 1996, net
production had increased to an average during September 1996 of 12.0 MMcf/d and
174 Bbls/d from 13 wells. During the latter half of 1996 and into 1997, the
Lirette Field will be covered by a 3-D survey currently in process. It is
anticipated that drilling projects created out of this seismic work will
probably be drilled in late 1997 or in 1998. See "-- Southern Louisiana 3-D
Acquisitions."

Gibson/Humphreys

In late 1994, Denbury acquired minor working interests in five wells in the
Gibson and Humphreys Fields located in Terrebonne Parish, 20 miles northwest of
the Lirette Field, in the northern part of the Houma embayment. The Gibson
Field, discovered in 1937, has produced over 813 Bcf and 14 MMBbls while the
Humphreys Field, discovered in 1956, has produced 527 Bcf and 6 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 majority working interest
in these fields. By December 1995, Denbury's acreage position had grown to 3,165
net acres with interests in six active wells and eight inactive wells. During
September 1996, net production in these two fields averaged approximately 4.6
MMcf/d and 82 Bbls/d. Two additional wells are currently planned in this area
during 1997, one of which is an offset to the Kuntz A-10 well, Gibson Field's
largest current producer, to attempt to accelerate the production of the field's
behind pipe zones. The second well will be drilled to a new horizon within the
same field.

South Chauvin

In February 1996, Denbury purchased interests in two producing wells and
four non-producing wells in South Chauvin Field located in the Houma embayment
area, about 4 miles south of Houma and six miles northwest of Lirette Field.
Chauvin Field, discovered by Shell Oil, is a faulted anticline which has
produced approximately 180 Bcf and 8,500 MBbls since 1960 at depths between
6,000 feet and 14,500 feet. The Company believes considerable potential exists
in the deeper sections below 13,000 feet. Some production has already been
established at Chauvin from this deeper section but appears not to have been
drilled at the optimum location. Denbury intends to either shoot a new 3-D
survey or purchase one recently shot by another company within the next 12
months to confirm the structure.

Of the three currently producing wells at Chauvin, Denbury owns an average
95% working interest. During September 1996, these three wells produced at an
average net rate of 0.3 MMcf/d and 20 Bbls/d. The Company plans a series of
workovers in the latter half of 1996 and has to date identified 16 potential
behind pipe zones in four wells and two undeveloped drilling locations. This
drilling activity is planned for 1997.

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<PAGE> 32

Bayou Rambio

Production at the Bayou Rambio Field was established in 1955 and has
exceeded 150 Bcf and 920 MBbls to date. Denbury operates one producing well in
the field, the Kelly #2 which is located in Terrebonne Parish about 15 miles
west of Lirette Field. During October 1995, the Company successfully recompleted
this well and during the first part of 1996, acquired additional interests in
this well, bringing its working interest to 88%. During September 1996, the
Kelly #2 produced at an average net rate of approximately 1 MMcf/d and 10
Bbls/d. The Company is currently evaluating 15 square miles of 3-D seismic data
covering this area. Based upon this evaluation, a development location is
tentatively scheduled to be drilled during 1997. This field has historically
produced from twenty-five different pay zones.

Lapeyrouse

The Lapeyrouse Field is a large structural feature which has produced over
0.6 Tcf and 10 MMBbls since its discovery in 1941. Denbury currently operates
one producing well and one shut-in well and has a small interest in one other
producing well in the Lapeyrouse field. Net production from this area was
relatively minor during September 1996, averaging 0.1 MMcf/d and 2 Bbls/d.
However, this area is part of the Lirette 3-D joint venture and also will be
covered by the 147 square mile 3-D survey to be conducted in late 1996. The
Company believes considerable potential exists in the section below 15,000 feet
which has produced 8 Bcf from one well in the field. The Company is planning a
workover of the shut-in well during 1997, pending a review of the 3-D seismic,
and anticipates that other drilling opportunities may arise as 3-D data is
evaluated across this large feature. See "-- Southern Louisiana 3-D
Acquisitions."

Other Louisiana

The Company has a 50% working interest in 17 operated producing wells in
the Bayou Des Allemands Field, located in the LaFourche and St. Charles
Parishes. This field was acquired as part of the Hess Acquisition. During
September 1996, net production from this field averaged 0.1 MMcf/d and 173
Bbl/d. Production in this field is from discrete sand intervals located from
3,700 feet to 11,500 feet in depth. Over 30 behind pipe sands have been
identified for future completion as the present zones deplete. Additional
potential may exist in updip locations in producing fault blocks, in untested
fault blocks and in deeper horizons. A 3-D seismic survey is planned during 1997
to help identify any upside potential.

The Company also acquired Lake Chicot Field in St. Martin Parish, Louisiana
as part of the Hess Acquisition and has a 50% working interest in 12 wells. Only
three wells are currently producing, although the Company is in the process of
returning another 9 wells to production as the field was temporarily shut-in
when the Company took over as operator after the acquisition.

Denbury owns a non-operated 19% working interest in three active wells in
North Deep Lake Field in Cameron Parish. During 1995, one of these wells was
successfully recompleted into a shallower sand. During September 1996, net
production from this field averaged 1.6 MMcf/d.

Denbury owns a 100% working interest in 473 acres covering Breton Sound
Blocks 12 and 13 located in Louisiana State water approximately 70 miles
southeast of New Orleans. Breton Sound Block 13 is an abandoned oil and natural
gas field in 14 feet of water. Production was established in the 1960s from a
mid-Miocene sand at 7,500 feet, but water and natural gas coning from an
associated natural gas cap prevented significant economic production. The field
was abandoned in the 1970s after having produced less than 150 MBbls. During the
second quarter of 1996, Denbury drilled a horizontal well to redevelop this
field. The well tested at a gross production rate of 5.5 MMcf/d and commenced
production on September 2, 1996. During the first 23 days of production, the
well's gross production averaged 1.9 MMcf/d and 55 Bbls/d. Although the well is
on production, the Company is still in process of completing its oil storage
facilities that should be completed by early October. Because of the limited oil
storage facilities, the Company is not currently able to produce the well at its
optimum rates and until the facilities are completed, an accurate assessment of
future production rates is not possible.

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<PAGE> 33

Southern Louisiana 3-D Acquisitions

During 1995, the Company acquired approximately 46 square miles of 3-D
seismic data over five of its existing fields in southern Louisiana consisting
of Bayou Rambio, DeLarge, North Deep Lake, Gibson and Humphreys. During the
second quarter of 1996, the Company entered into a joint venture agreement with
two industry partners to acquire approximately 147 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 will own
a one-third interest in any new prospects discovered through this joint venture,
which currently owns rights to over 35,000 acres within the survey area. The
Company will be responsible for one-third of the cost of both the 3-D seismic
survey and any wells drilled. The Company anticipates that the 3-D seismic
survey should be completed and the data analyzed by the fall of 1997. In
addition, five of the fields acquired during the first half of 1996 have 3-D
seismic coverage which should be available to the Company in the future and two
additional fields are presently being surveyed. The acquisition and processing
of this data will occur during the second half of 1996 and continue into 1997.

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.

Eucutta

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
recent Hess Acquisition and currently operates 31 producing oil wells and 16
saltwater injection wells. The field is divided into a shallow Eutaw sand unit
in which the Company has a 76% working interest and the deeper Tuscaloosa sand
zones in which the Company has a 100% working interest. The Eucutta Field traps
oil in multiple sandstones in a highly faulted anticline. At present, seven
different sands are productive at depths between 5,000 feet and 11,000 feet.
Most of the wells produce oil with large amounts of saltwater, which requires
pumping. During September 1996, net production from this field averaged 1,063
Bbls/d.

The Company plans a capital expenditure program at Eucutta Field which will
include upgrading producing facilities, drilling wells and a 3-D seismic
evaluation. The Company believes that through a combination of these
investments, production can be increased and operating costs reduced. Two wells
are planned to be drilled in late 1996, with perhaps four more in 1997 and 1998.
Consideration is being given to acquiring a 3-D seismic survey over the field
and, if pursued, most likely would occur in 1997.

Davis/Frances Creek

The Davis Field and nearby Frances Creek Field are located 42 miles
northeast of Laurel in the northern part of the Mississippi salt basin. Denbury
operates 19 producing wells within the area and owns minor non-operated
interests in eight other wells. The net average production from these wells
during September 1996 was approximately 929 Bbls/d. 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.

Both the Davis and Frances Creek Fields are relatively mature fields and
produce large amounts of saltwater. During August 1996, these fields produced an
average of approximately 55,000 barrels of saltwater per day, all of which were
re-injected into the ground. The Company places considerable emphasis on
controlling operating costs in these fields to minimize the cost of saltwater
disposal and pumping equipment.

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<PAGE> 34

Since acquiring the majority of the field in 1993, Denbury has undertaken
an active redevelopment program including numerous workovers and two 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 the remainder of 1996, the Company plans to drill a horizontal well to
improve withdrawal efficiency, with another horizontal well planned for 1997.
The Company has identified 11 zones behind pipe for future development.

South Thompson Creek

The South Thompson Creek Field is located in Wayne County, Mississippi,
about 23 miles southeast of Laurel. Denbury operates 3 wells in the field with a
working interest of 100%. In September 1996, net production from the field
averaged 356 Bbls/d. The South Thompson Creek Field is an anticline which has
produced a total of 3.9 MMBbls since its discovery in 1960 from sandstone
reservoirs in the Hosston, Rodessa and Tuscaloosa formations.

Denbury first acquired an interest in the field in 1993 and increased its
ownership in 1995 by acquiring the apex of the field. Subsequently, in 1995, the
Company drilled its first horizontal well and in April 1996, Denbury acquired
the remaining interest in the field as part of the Ottawa Acquisition. A second
horizontal well was drilled in May 1996, which during September 1996 produced an
average of 252 Bbls/d and 763 barrels of saltwater per day.

In 1997, the Company may drill a third horizontal well in the field pending
continued evaluation of the first two horizontal wells. In addition, there are
two shut in wells which have recompletion potential.

West Yellow Creek

The West Yellow Creek Field is located 28 miles west of Laurel in Wayne
County, Mississippi. Denbury operates seven producing oil wells and two
saltwater disposal wells, with an average working interest of 97%. During
September 1996, net production from the field averaged 266 Bbls/d.

The Company's production is located in the central part of West Yellow
Creek Field which has produced over 34 MMBbls since 1947, with most of the
production being from the Eutaw formation at 5,000 feet. Production also occurs
from multiple sands in the Tuscaloosa and Washita-Fredericksburg formations.
This Tuscaloosa and Washita-Fredericksburg production, discovered in 1966, was
essentially abandoned prior to 1993, when the Company acquired its first
interests in the field. The Company began a drilling program in 1993 which
continued through 1994. By a combination of successful drilling and additional
production acquisitions, the Company was able to increase its net production
from 40 Bbls/d in 1993 to 250 Bbls/d in 1995. In 1996, the Company acquired an
additional 50% working interest in the operated wells through the Ottawa
Acquisition.

Quitman

The Quitman Field is located in Clarke County, Mississippi, 31 miles
northeast of Laurel and near the Davis and Frances Creek Fields. The Company
acquired the field as part of the Hess Acquisition and now operates seven
producing wells and 13 shut in wells. The Company owns an average working
interest of 82%. In September 1996, net production from these wells averaged 180
Bbls/d.

The Quitman Field was discovered in 1966 and has produced approximately 21
MMBbls from 18 separate reservoirs between 4,000 feet and 12,000 feet. The
principal producing zones at Quitman are the Smackover formation and several
sands in the Cotton Valley formation.

Denbury has identified 24 prospective zones behind pipe in existing shut-in
wells. Testing of these zones will begin during the second half of 1996. The
Company also plans to upgrade production and saltwater disposal facilities in an
attempt to lower operating costs.

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<PAGE> 35

In 1997, the Company plans to evaluate the Quitman Field and the immediate
vicinity, including Davis and Frances Creek fields, with a 3-D seismic survey.
The Company believes that this survey will aid in the accurate evaluation of the
existing reservoir and could lead to the discovery of new producing horizons.

Dexter

The Dexter Field is located in southern Mississippi, about 60 miles
northeast of New Orleans, Louisiana. This field has produced 240 Bcf and 10.8
MMBbls since its discovery in 1957 from a series of natural gas and oil bearing
reservoirs between 8,000 feet and 16,000 feet. The Company currently owns
interests in eight outside operated wells, with an average 56% working interest.
These interests were acquired in several transactions between 1992 and 1996.
During September 1996, average net production from these wells was 2.4 MMcf/d.
The Company has identified four additional zones for recompletion potential and
may drill a development well in this field in 1997.

Puckett

The Puckett Field, which was discovered in 1960, is located about 40 miles
northwest of Laurel in Southern Mississippi. Since its discovery Puckett has
produced 7.3 Bcf and 6 MMBbls. Denbury operates seven wells in the field with an
average working interest of 94%. In August 1996, average net production from
these wells was 143 Bbls/d. Denbury acquired its interest in January 1993 and
immediately began a workover program in the field. Gross production was
increased from 40 BOE/d at acquisition to its current level of 147 BOE/d during
September 1996. Current plans are to produce the current zones and then
recomplete these wells into uphole horizons. There are presently 13 zones
identified behind pipe for future development.

Other Mississippi

The Sandersville Field is located about 12 miles northeast of Laurel,
Mississippi. The field produces heavy oil from shallow sands of the Eutaw
formation along with large amounts of saltwater. The Sandersville Field was
first purchased in late 1994 when Denbury acquired a 97% working interest in 15
active and inactive wells. During 1996, the Company completed a rework of six
producing wells and two saltwater disposal wells, and net production in
September 1996 averaged 246 Bbls/d. Sandersville Field is a four-mile long
structure with oil trapped in multiple sands at around 4,000 feet. Historically,
the recovery of oil has been low and may be enhanced by horizontal drilling. A
study is underway to determine the best location to test this concept with a
well planned for mid-1997.

ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES

The Company regularly seeks to acquire properties that complement its
operations, that provide exploitation, exploration and development opportunities
and that 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 were approximately $93.7 million.
The properties included in the Company's five largest acquisitions make up
approximately 80% of its total proved reserves on a BOE basis. These five
acquisitions are discussed below in the order of their acquisition by the
Company.

Mississippi Acquisition

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 2,206 MBOE. From the date of
acquisition through June 30, 1996, the Company produced 789 MBOE from the
acquired properties and has successfully increased its ownership in the Davis
Field through approximately $600,000 of incremental

35
<PAGE> 36

acquisitions. As of July 1, 1996, the estimated net proved reserves of the
properties totaled 2.4 MMBOE, with a PV10 Value of $12.5 million.

Louisiana Acquisition

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 located 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 1,677 MBOE. From the date of acquisition through June
30, 1996, the Company produced 1,669 MBOE from the acquired properties.
Subsequent to the acquisition, Denbury has successfully completed approximately
$9.6 million in acquisitions of incremental interests in the Lirette and Bayou
Rambio Fields. As of July 1, 1996, the estimated net proved reserves of the
properties was 7.1 MMBOE, with a PV10 Value of $65.0 million.

Gibson Acquisition

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 1,985 MBOE. From the date of acquisition through
June 30, 1996, the Company produced 256 MBOE from the acquired properties. As of
July 1, 1996, the estimated net proved reserves of the properties was 1.6 MMBOE,
with a PV10 Value of $16.5 million.

Ottawa Acquisition

In April 1996, the Company acquired additional working interests in five of
its existing oil and natural gas properties in Mississippi, plus certain
overriding royalty interests in other areas, from Ottawa for approximately $7.5
million. This acquisition included 29 producing gross wells (8.8 net working
interest wells), plus overriding royalty interests in an additional 65 wells.
These properties contributed approximately 760 Mcf/d and 175 Bbls/d, or 300
BOE/d, to the Company's average net daily production during the first half of
1996. Average daily production during the first half of 1996 from these
properties, including the periods when they were not owned by the Company, was
approximately 1,615 Mcf/d and 360 Bbls/d, or 629 BOE/d, net to the interest
acquired by Denbury. As of July 1, 1996, the estimated net proved reserves of
these properties was 1.3 MMBOE, with a PV10 Value of $10.4 million.

Hess Acquisition

The largest acquisition by the Company to date, which occurred during the
first half of 1996, 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. In
May and June 1996, these properties contributed approximately 2.0 MMcf/d and 650
Bbls/d, or 1,000 BOE/d, to the Company's average daily production during the
first half of 1996. Average daily production during the first half of 1996 from
these properties, including the periods when they were not owned by the Company,
was approximately 6.6 MMcf/d and 2,230 Bbls/d, or 3,335 BOE/d, net to the
interest acquired by Denbury. The properties in this acquisition had estimated
net proved reserves of approximately 5.9 MMBOE which consisted of 5.0 MMBbls and
5.6 Bcf, with a PV10 Value of $43.1 million.

Approximately 90% of the PV10 Value of the Hess Acquisition was for wells
on which Denbury assumed operations with an average working interest of
approximately 80%. Four fields out of a total of 60 fields, comprise
approximately 73% of the total Hess Acquisition PV10 Value. The two largest
fields in Mississippi, Eucutta and Quitman Fields, make up approximately 57% of
the total acquisition PV10 Value. Both fields are

36
<PAGE> 37

in the same vicinity as the Company's existing Mississippi core properties, with
the Eucutta Field located in Wayne County, Mississippi between the Company's
Sandersville and West Yellow Creek existing production. The Quitman Field is
located in Clarke County, Mississippi, adjacent to the Company's Davis and
Frances Creek existing production. The two largest fields in Louisiana are the
Atchafalaya Bay and Bayou Des Allemands Fields, which comprise approximately 16%
of the total acquisition PV10 Value. These two fields are in adjacent parishes
to Terrebonne Parish where the majority of the Company's existing Louisiana
production is located. Atchafalaya Bay Field is just west of Terrebonne Parish
in St. Mary Parish and Bayou Des Allemands Field is located Northeast of
Terrebonne Parish in St. Charles and LaFourche Parishes.

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 year of
the three-year period ended December 31, 1995 and the six month periods ended
June 30, 1995 and 1996.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
-------------------------------------- -----------------------------
PRO PRO
FORMA FORMA
1993 1994 1995 1995(1) 1995 1996 1996(1)
------ ------ ------ ------- ------ ------ -------
<S> <C> <C> <C> <C> <C> <C> <C>
NET PRODUCTION VOLUME:
Crude oil (MBbls)......... 313 489 728 1,813 331 527 847
Natural gas (MMcf) ....... 735 3,326 4,844 8,000 2,186 4,098 5,102
Oil equivalent (MBOE)..... 435 1,043 1,535 3,146 696 1,210 1,697
AVERAGE SALE PRICES:
Crude oil ($/Bbl)......... $13.91 $13.84 $14.90 $14.64 $14.92 $17.39 $17.33
Natural gas ($/Mcf) ...... 2.06 1.78 1.90 1.83 1.85 2.80 2.72
Oil equivalent ($/BOE).... 13.47 12.17 13.05 13.09 12.94 17.07 16.84
AVERAGE PRODUCTION COSTS:
Per equivalent BOE........ $ 4.75 $ 4.13 $ 4.42 $ 4.87 $ 4.50 $ 4.42 $ 4.64
</TABLE>

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

(1) During 1996, the Company made two significant property acquisitions. See
"Acquisitions of Oil and Natural Gas Properties." The summary pro forma
results assume that these transactions were completed as of the beginning of
each respective period. See also "Pro Forma Operating Results."

OIL AND NATURAL GAS ACREAGE

The following table sets forth the Company's acreage position as of
December 31, 1995:

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Louisiana............................................. 13,704 10,333 3,990 3,902
Mississippi........................................... 5,940 3,079 3,826 1,963
Oklahoma.............................................. -- -- 550 340
Texas................................................. 840 660 1,385 417
------ ------ ------ ------
Total....................................... 20,484 14,072 9,751 6,622
====== ====== ====== ======
</TABLE>

37
<PAGE> 38

The following table sets forth the Company's acreage position as of June
30, 1996:

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Alabama............................................... 870 600 1,089 361
Louisiana............................................. 29,802 20,487 7,565 6,765
Mississippi........................................... 18,087 11,903 13,181 6,336
Oklahoma.............................................. -- -- 550 340
Texas................................................. 840 660 1,385 417
------ ------ ------ ------
Total....................................... 49,599 33,650 23,770 14,219
====== ====== ====== ======
</TABLE>

PRODUCTIVE WELLS

The following table sets forth the Company's gross and net productive wells
as of December 31, 1995:

<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS WELLS TOTAL
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Louisiana................................... 9 5.7 32 20.5 41 26.2
Mississippi................................. 64 45.9 11 2.2 75 48.1
Texas....................................... -- -- 4 2.9 4 2.9
-- ---- -- ---- --- ----
Total ............................ 73 51.6 47 25.6 120 77.2
== ==== == ==== === ====
</TABLE>

The following table sets forth the Company's gross and net productive wells
as of June 30, 1996:

<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS WELLS TOTAL
--------------- -------------- ---------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Alabama................................... 2 0.2 5 1.0 7 1.2
Louisiana................................. 54 27.9 48 27.2 102 55.1
Mississippi............................... 158 102.8 14 5.3 172 108.1
Texas..................................... 2 1.8 5 3.3 7 5.1
--- ----- == ---- --- -----
Total........................... 216 132.7 72 36.8 288 169.5
=== ===== == ==== === =====
</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, 1995 and the six months
ended June 30, 1996. Two wells were in the process of drilling at June 30, 1996.

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
JUNE 30,
YEAR ENDED DECEMBER 31, 1996
------------------------------------------- -----------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EXPLORATORY WELLS:
Productive................................ -- -- -- -- -- -- -- --
Nonproductive............................. 1 0.5 3 0.8 2 1.0 1 1.0
DEVELOPMENT WELLS:
Productive................................ 5 2.2 4 2.9 2 1.5 4 3.5
Nonproductive............................. 1 0.9 1 1.0 -- -- -- --
-- --- -- --- -- --- -- ---
Total.................................. 7 3.6 8 4.7 4 2.5 5 4.5
== === == === == === == ===
</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 all of its product as it
becomes available or in transporting its product to these markets.

38
<PAGE> 39

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 one-year
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 80% of the Company's oil production in 1995, is
primarily light sour crude and sells at a discount to the published West Texas
Intermediate posting. The balance of the oil production, Louisiana oil, is
primarily light sweet crude, which typically sells at a slight premium to the
West Texas Intermediate posting.

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 did not have any
hedge contracts in place as of September 30, 1996 although it may have such
contracts in the future.

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 operations. For the period
ended December 31, 1995, the Company sold 10% or more of its net production of
oil and natural gas to the following purchasers: Natural Gas Clearinghouse
(21%), Amerada Hess (20%), Conoco, Inc. (12%), and Brymore Energy Corp. (12%),
which as of May 1, 1996 is wholly-owned by the Company.

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.

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.

GEOGRAPHIC SEGMENTS

During 1993, the Company had $618,000 of oil and natural gas sales in
Canada and generated $1.1 million of net income in Canada, including the gain on
sale of Canadian properties of $966,000. All Canadian oil and natural gas
properties were disposed of in 1993 and thus all of the Company's operations are
now in the United States.

39
<PAGE> 40

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
the 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 in, the plugging and abandoning of wells and the disposal of fluids used
in connection with operations. The Company's operations are also subject to
various conservation laws and regulations. These include the regulation of the
size of drilling and spacing units or proration units and the density of wells
which may be drilled in and the unitization or pooling of oil and gas
properties. In addition, state conservation laws establish maximum rates of
production from oil and gas wells, generally prohibit the venting or flaring of
gas and impose certain requirements regarding the ratability of production. The
effect of these regulations may limit the amount of oil and gas the Company can
produce from its wells and may limit the number of wells or the locations at
which the Company can drill. The regulatory burden on the oil and gas industry
increases the Company's costs of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended and reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.

Federal Regulation of Sales 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

40
<PAGE> 41

as to purchase natural gas directly from third-party merchants other than the
pipelines and obtain 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 provisions 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
orders or at the FERC's own initiative.

In recent years the FERC also has pursued a number of other 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 the FERC to
streamline oil pipeline ratemaking by abandoning its old 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.

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.

41
<PAGE> 42

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.

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 Company also is subject to a variety of federal, state, and local
permitting and registration requirements relating to 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.

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 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 it (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. See Note 4 "Income Taxes" of the Consolidated Financial Statements
for additional tax disclosures.

LEGAL PROCEEDINGS

There are no material pending legal proceedings to which the Company or any
of its subsidiaries is a party or of which any of their property is the subject.
However, due to the nature of its business, certain legal or administrative
proceedings arise from time to time in the ordinary course of its business.

42
<PAGE> 43

MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The names of the directors and officers of the Company, the offices held by
them with the Company and the periods during which such offices have been held
are set forth below. Each executive 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 Company currently has a vacancy on its Board of
Directors caused by the resignation of Mr. Martin Fortier on August 30, 1996. If
replaced, this vacancy will be filled by a non-TPG nominee.

<TABLE>
<CAPTION>
NAME AGE POSITION(S)
- ----------------------------------------- ------ -----------------------------------------
<S> <C> <C>
Ronald G. Greene(1)(2)(3)(4)............. 47 Chairman of the Board
William S. Price, III(2)(3)(4)........... 40 Director
David M. Stanton(1)...................... 34 Director
Wieland F. Wettstein(1).................. 46 Director
David Bonderman.......................... 53 Director
Gareth Roberts........................... 43 President, Chief Executive Officer and
Director
Phil Rykhoek............................. 40 Chief Financial Officer and Secretary
Mark A. Worthey.......................... 38 Vice President, Operations
Matthew Deso............................. 43 Vice President, Exploration
</TABLE>

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

(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Stock Option Plan Committee.
(4) Member of the Stock Purchase Plan Committee.

Directors

Ronald G. Greene - Chairman of the Board, 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 CEO 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.

William S. Price, III has been a director of the Company since 1995. Mr.
Price is a co-founder and principal of the Texas Pacific Group, a private
investment firm that specializes in corporate acquisitions in a wide range of
industries. Prior to forming the Texas Pacific Group 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 also serves on the Board of Directors of
Continental Airlines, Inc., Continental Micronesia, Inc., PPOM, LP., and Vivra
Heart Services.

David M. Stanton has been a director of the Company since 1995. Mr. Stanton
is a managing director of the Texas Pacific Group, a private investment firm
that specializes in corporate acquisitions in a wide range of industries. From
1991 until he joined the Texas Pacific Group in 1994, Mr. Stanton was a venture
capitalist with Trinity Ventures where he specialized in information technology,
software and telecommunications investments.

Wieland F. Wettstein has been a director of the Company since 1990. Mr.
Wettstein is the Executive Vice-President 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 two public oil and natural gas companies, BXL Energy and Attock
Energy Corporation, and on the boards of a private technology firm and a private
gas marketing company.

David Bonderman became a director of the Company in May, 1996. Mr.
Bonderman is a co-founder and principal of the Texas Pacific Group, a private
investment firm that specializes in corporate acquisitions in a

43
<PAGE> 44

wide range of industries. Prior to forming the Texas Pacific Group 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 is an honor graduate from Harvard Law School and serves on the
boards of Continental Airlines, Inc., PPOM, L.P., American Savings Bank, Bell &
Howell Company, National Reinsurance and Virgin Cinemas Limited. Mr. Bonderman
also serves in general partner advisory board roles for Acadia Partners, Colony
Investors and Newbridge Investment Partners.

Executive Officers

Gareth Roberts - President, Chief Executive Officer and Director, is the
founder and President of Denbury Management, Inc. 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.

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 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.

Matthew Deso - Vice President, Exploration, has been with Denbury
Management, Inc. since October 1990, first as a consultant then, when he moved
to Dallas in January 1994, as Vice President of Exploration. 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.

Mark A. Worthey - Vice President, Operations, is a geologist and is
responsible for all aspects of operations in the field. He joined Denbury
Management, Inc. 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.

As part of the Securities Purchase Agreement that governed the TPG
Placement, 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, on a fully-diluted basis,
represent less than 20% of the outstanding Common Shares. Currently, Mr. David
M. Stanton, Mr. David Bonderman and Mr. William S. Price, III are directors of
the Company nominated by TPG. The Company currently has a vacancy on its Board
of Directors caused by the resignation of Mr. Martin Fortier on August 30, 1996.
If replaced, this vacancy will be filled by a non-TPG nominee.

COMPENSATION OF DIRECTORS AND OFFICERS

The following table sets forth certain summary information regarding
compensation paid or accrued by the Company to or on behalf of the Company's
Chief Executive Officer and each of the other three most highly compensated
executive officers ("Named Executive Officers") of the Company (determined as of
December 31, 1995) for the fiscal years ended December 31, 1993, 1994 and 1995.

44
<PAGE> 45

The Company reimburses the directors of the Company for out-of-pocket
traveling expenses in connection with each board meeting attended. There are no
other arrangements in respect of which directors of the Company receive monetary
compensation for acting in that capacity.

<TABLE>
<CAPTION> ANNUAL
COMPENSATION(1) LONG-TERM
-------------------- --------------------
COMMON SHARES
UNDERLYING
NAME AND PRINCIPAL POSITION YEAR SALARY BONUSES OPTION/SARS GRANTED
- ----------------------------------------------- ---- -------- -------- --------------------
<S> <C> <C> <C> <C>
Gareth Roberts................................. 1995 $150,000 $ 3,410 --
President and Chief Executive Officer 1994 150,000 -- --
1993 150,000 6,000 55,500
Phil Rykhoek................................... 1995 $ 55,682 $ 1,923 50,000
Chief Financial Officer and Secretary(2) 1994 -- -- --
1993 -- -- --
Mark A. Worthey................................ 1995 $100,000 $ 1,923 --
Vice President, Operations 1994 89,000 4,000 5,000
Denbury Management, Inc. 1993 89,000 4,000 89,250
Matthew Deso................................... 1995 $100,000 $ 1,923 5,000
Vice President, Exploration 1994 89,000 4,000 12,500
Denbury Management, Inc.(3) 1993 55,000 4,000 55,000
</TABLE>

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

(1) The aggregate amount of all other annual compensation as defined by
applicable securities regulations was not greater than the lesser of
$50,000 or 10% of the total annual salary and bonus of each Named Executive
Officer for each financial year.

(2) Mr. Rykhoek joined Denbury in June 1995.

(3) Mr. Deso joined Denbury in April 1993.

STOCK OPTIONS

The Company has an employee stock option plan (the "Plan") pursuant to
which stock options may be granted to full and part-time employees, officers and
directors of the Company and its subsidiaries, from time to time, as the board
of directors of the Company may determine. The Plan allows the granting of
either non-qualified or incentive stock options. Under the terms of the Plan,
the number of Common Shares reserved for issuance may not exceed 1,050,000
Common Shares. The term of options granted under the Plan are determined by the
board of directors provided that no option may be granted for a period that
exceeds 10 years from the date of the grant, or such lesser period of time as
permitted, from time to time, by the applicable rules of the TSE. The purchase
price of any shares subject to options under the Plan is fixed by the board of
directors, but may not be less than the greater of the two average closing
trading prices for the ten trading days preceding the date of grant as reported
on the TSE and NASDAQ. All option agreements granted under the Plan must be in
accordance with the policies and procedures of the TSE and NASDAQ.

At a meeting of the Board of Directors of the Company on May 16, 1996, the
Plan was amended to increase the number of options authorized to be issued under
the Plan to 1,250,000. This amendment is subject to shareholder and regulatory
approval.

As of September 30, 1996, options outstanding pursuant to the Plan were
comprised of incentive stock options covering 634,000 Common Shares held by one
officer/director, three officers and 33 employees and non-qualified stock
options covering 424,750 Common Shares held by two directors, one
officer/director, three officers, 14 employees and one former employee. These
options are exercisable at prices ranging from $3.66 to $11.36, with a weighted
average price of $7.56. Of the total outstanding options, 479,187 were currently
exercisable as of September 30, 1996. From January 1, 1996 through September 30,
1996, the Company granted 516,500 options.

45
<PAGE> 46

OPTION GRANTS IN LAST FISCAL YEAR

The following table represents the options granted to the Named Executive
Officers during 1995 and the value of such options:

<TABLE>
<CAPTION>
POTENTIAL
REALIZABLE
VALUE AT ASSUMED
ANNUAL
INDIVIDUAL GRANTS RATES OF
------------------------------------------------------ STOCK PRICE
NUMBER OF % OF APPRECIATION FOR
SECURITIES TOTAL OPTIONS EXERCISE OPTION
UNDERLYING GRANTED TO OR BASE TERM(2)
OPTIONS EMPLOYEES IN PRICE EXPIRATION -------------------
NAME GRANTED(#) FISCAL YEAR ($/SH)(1) DATE 5%($) 10%($)
- --------------------------- ---------- ------------- --------- ---------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Gareth Roberts............. -- -- -- -- -- --
Phil Rykhoek............... 25,000(3) 9% $6.08 6/22/00 $41,954 $ 92,707
25,000(4) 9% 6.02 8/18/05 94,800 240,242
Mark A. Worthey............ -- -- -- -- -- --
Matthew Deso............... 5,000(3) 2% 5.92 1/3/00 8,186 18,089
</TABLE>

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

(1) These options are denominated in Canadian dollars and are converted to U.S.
dollars for this table using an exchange rate of Cdn. $1.35 = U.S. $1.00.

(2) Calculated based on the fair market value of the Common Shares on the date
of grant. The amounts represent only certain assumed compounded annual
rates of appreciation. Actual gains, if any, on stock option exercises and
Common Share holdings cannot be predicted, and there can be no assurance
that the gains set forth in the table will be achieved. A conversion
exchange rate of Cdn. $1.35 = U.S. $1.00 was assumed in the calculation.

(3) The options vest in installments of 50% on the date of grant and 50% one
year from the date of grant.

(4) The options vest in installments of 25% six months from the date of grant,
25% one year from the date of grant, 25% two years from the date of grant,
and 25% three years from the date of grant.

OPTION EXERCISES AND HOLDINGS

The following table sets forth information with respect to the Named
Executive Officers concerning unexercised options held as of December 31, 1995.
None of the Named Executive Officers exercised any options during 1995. During
the first three quarters of 1996, the Named Executive Officers exercised a total
of 28,750 options.

AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES

<TABLE>
<CAPTION>
VALUE OF UNEXERCISED IN-THE
NUMBER OF UNEXERCISED MONEY
OPTIONS AT OPTIONS AT FISCAL
FISCAL YEAR-END YEAR-END(1)
---------------------------- ----------------------------
EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Gareth Roberts................................ 27,750 -- $21,326 $ --
Phil Rykhoek.................................. 12,500 37,500 2,199 7,708
Mark A. Worthey............................... 73,250 -- 1,620 --
Matthew Deso.................................. 60,000 2,500 4,861 810
</TABLE>

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

(1) Based on the closing sale price of the Common Shares on December 21, 1995,
the last day prior to December 31, 1995 in which there was trading
activity, of $6.25 per share as reported by NASDAQ. A conversion exchange
rate of Cdn. $1.35 = U.S. $1.00 was assumed in the calculation as the
options are denominated in Canadian dollars.

46
<PAGE> 47

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, 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.

FINANCIAL ADVISORY FEE

In October 1993, the Company paid a management fee of $75,000 to Finex
Financial Corporation Ltd. a Company indirectly controlled by Mr. Martin G.
Fortier, a then director of the Company, and Mr. Wieland F. Wettstein, a
director of the Company, for services rendered and assistance provided in
raising equity and in the sale of its Canadian operations.

TPG PLACEMENT

In December 1995, the Company closed a $40.0 million private placement of
securities with partnerships that are affiliated with TPG. 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 holder to
purchase 625,000 Common Shares at $7.40 per share; and (iii) 1.5 million shares
of $10 stated value Convertible Preferred. The Convertible Preferred shares are
initially convertible at $7.40 of stated value per Common Share with such
conversion rate declining 2.5% per quarter. The Convertible Preferred do not
have any cash or other stated dividend requirement. The Convertible Preferred
have a mandatory redemption at a 63.86% premium at December 21, 2000, but also
originally provided that the Company can cause a mandatory conversion after
January 1, 1999 if the price of the Common Stock exceeds $10.00 per share for a
period of 40 consecutive trading days. The terms of the Convertible Preferred
were amended at a Special Meeting on October 9, 1996 to allow the Company to
require a conversion of the Convertible Preferred at any time. See
"-- Conversion of Convertible Preferred and Debentures." The Company intends to
convert the Convertible Preferred simultaneously with the closing of the
Offerings. The Company may also force conversion of the warrants after December
21, 1997, if the price of the Common Stock exceeds $10.00 per share for a period
of 40 consecutive trading days. As of October 15, 1996, TPG either owns or has
the current right to acquire 7,608,038 Common Shares, which represents 48.4% of
the outstanding Common Shares prior to the Offerings. See "Security Ownership of
Certain Beneficial Owners and Management."

In connection with the TPG Placement, TPG received the right to nominate
three of the seven directors of the Company. See "Management -- Executive
Officers and Directors." In addition, for a period of two years TPG has 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 that period. Beginning 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
(after the assumed exercise of its warrants and Convertible Preferred) 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. This right, however, expires should TPG's share holdings represent
less than 20% of the outstanding Common Shares. TPG has waived its registration
rights and its right to maintain its pro rata ownership with regard to the
Public Offering.

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. Mr. Greene was not a director of

47
<PAGE> 48

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.

TPG OFFERING

Concurrent with the Public Offering, the Company will sell an additional
800,000 Common Shares to TPG at the price to the public per share less the
underwriting discounts and commissions. See "Concurrent Offerings." In
connection with the TPG Offering, the Company will grant the same registration
rights to TPG with respect to the Common Shares purchased as described above
under "-- TPG Placement."

CONVERSION OF CONVERTIBLE PREFERRED AND DEBENTURES

In order to position the Company for the Public Offering, the Board of
Directors and its financial advisors determined that it was in the best
interests of the Company to: (i) increase the market price per Common Share to
levels significantly above U.S. $5.00, the level below which certain stocks are
subject to the penny stock rules; (ii) simplify the capital structure of the
Company; and (iii) reduce the overhang that exists as a result of existing
convertible securities. The Board of Directors believed that these goals would
be best achieved by taking the following actions: (i) consolidating the number
of Common Shares through a one-for-two reverse split of the Common Shares; (ii)
modifying the terms of the Convertible Preferred such that the Convertible
Preferred may be converted to Common Shares at the election of the Company prior
to January 1, 1999; and (iii) issuing Common Shares in lieu of interest to the
holders of the Debentures in order to induce such holders to convert their
Debentures to Common Shares prior to the mandatory redemption date. Accordingly,
the Company held a Special Meeting of the shareholders on October 9, 1996, at
which resolutions effecting the foregoing were approved.

Subject to, and simultaneously with, the completion of the Offerings, the
Company intends to require a conversion of the Convertible Preferred, thereby
increasing the number of Common Shares of the Company by 2,816,373 and
eliminating the outstanding Convertible Preferred. TPG, which either owns or has
the current right to acquire 48.4% of the outstanding Common Shares, is the sole
holder of the Convertible Preferred.

Effective October 15, 1996, the Company issued a total of 7,948 Common
Shares in lieu of interest on the Debentures, plus an additional 308,642 Common
Shares for the principal amount in accordance with the existing terms of the
Debentures. 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. Mr. Greene also purchased Cdn. $1,500,000 of
the 6 3/4% Convertible Debentures at market value prior to his election to the
Board of Directors, which 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 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 using a 15% discount rate. The acquisition was 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.

48
<PAGE> 49

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information, as of October 15, 1996,
concerning beneficial ownership of the Common Shares by: (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
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 shares.

<TABLE>
<CAPTION>
BENEFICIAL BENEFICIAL
OWNERSHIP PRIOR OWNERSHIP AFTER
TO OFFERINGS OFFERINGS(1)
NAME AND ADDRESS OF ----------------------- ---------------
BENEFICIAL OWNER SHARES PERCENT PERCENT
- ----------------------------------------------------- --------- ------- ---------------
<S> <C> <C> <C>
Ronald G. Greene..................................... 866,130(2) 5.7%(2) 4.4%(2)
Suite 700, 407 -- 2nd Street
Calgary, Alberta T2P 2Y3
David Bonderman...................................... 7,608,038(3) 48.4%(3) 41.8%(3)
201 Main Street, Suite 2420
Ft. Worth, TX 76102
William S. Price, III................................ 7,608,038(3) 48.4%(3) 41.8%(3)
600 California Street, Suite 1850
San Francisco, CA 94108
David M. Stanton..................................... --(4) * *
Wieland F. Wettstein................................. 161,414(5) 1.1%(5) *
Gareth Roberts....................................... 514,239(6) 3.4%(6) 2.6%
Phil Rykhoek......................................... 13,818(7) * *
Mark A. Worthey...................................... 76,369(7) * *
Matthew Deso......................................... 66,569(7) * *
All of the executive officers and directors as a
group (9 persons).................................. 9,306,577(8) 58.5%(8) 49.7%(8)
TPG Advisors, Inc.................................... 7,608,038(3) 48.4%(3) 41.8%(3)
201 Main Street, Suite 2420
Ft. Worth, TX 76102
</TABLE>

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

* Less than 1%.

(1) After giving effect to the issuance of an aggregate of 4,400,000 Common
Shares in the Offerings.

(2) After giving effect to the conversion of Cdn. $2,000,000 of the 9 1/2%
Convertible Debentures into an aggregate of 253,272 Common Shares. Includes
30,150 Common Shares held by Mr. Greene's spouse in her retirement plan and
520,833 Common Shares held by Tortuga Investment Corp., which is solely
owned by Mr. Greene.

(3) After giving effect to: (i) the pro forma conversion of the 1,500,000
Convertible Preferred into 2,816,372 Common Shares, and (ii) the pro forma
exercise of the 625,000 Common Share purchase warrants. Neither Mr.
Bonderman, Mr. Price nor TPG Advisors, Inc. are the owner of record of any
securities of the Company. However, Mr. Bonderman and Mr. Price 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 Offerings," includes 800,000 Common Shares which the Company will sell
to TPG in the TPG Offering.

(4) Although Mr. Stanton is not considered to be a "beneficial owner" as that
term is defined by the Securities and Exchange Commission, Mr. Stanton is a
managing director of TPG Partners, L.P.

49
<PAGE> 50

(5) After giving effect to the pro forma exercise of the 18,000 Common Shares
which Mr. Wettstein has the right to acquire pursuant to vested stock
options. Also includes 110,489 Common Shares held by S.P. Hunt Holdings
Ltd., which is solely owned by a trust of which Mr. Wettstein is a trustee,
and 19,600 Common Shares owned by his spouse.

(6) After giving effect to the pro forma exercise of the 27,750 Common Shares
which Mr. Roberts has the right to acquire pursuant to vested stock options.
Also includes 138,330 Common Shares held by Ashley Petroleum, Inc., which is
solely owned by Mr. Roberts, and 1,426 Common Shares held by his wife.

(7) After giving effect to the pro forma exercise, as applicable, of the 13,438,
73,250 and 62,500 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 the next sixty days.

(8) After giving effect to: (i) the conversion of Cdn. $2,000,000 of the 9 1/2%
Convertible Debentures into an aggregate of 253,272 Common Shares, (ii) the
pro forma conversion of the 1,500,000 Convertible Preferred into 2,816,372
Common Shares, (iii) the pro forma exercise of the 625,000 Common Share
purchase warrants, and (iv) the pro forma exercise of the 194,938 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
the next sixty days. Ownership does include the shares held by 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 same securities. The "Beneficial Ownership
after Offerings," includes 800,000 Common Shares which the Company will sell
to TPG in the TPG Offering.

DESCRIPTION OF CAPITAL STOCK

GENERAL

The authorized share capital of Denbury consists of an unlimited number of
Common Shares, of which 12,281,897 were issued and outstanding as of October 15,
1996, and two classes of preferred shares, unlimited in number and issuable in
series, none of which will be outstanding after the completion of the Offerings.
In addition to the issued and outstanding Common Shares, options to purchase
Common Shares and other forms of convertible securities for Common Shares are
outstanding.

There are no limitations imposed by Canadian legislation or regulations or
by the Articles of Continuance or Bylaws of the Company 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 to one vote for each Common
Share held at all meetings of shareholders of the Company, 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; are entitled to
any dividends that may be declared by the board of directors thereon; and in the
event of liquidation, dissolution or winding-up of the Company, are entitled,
subject to the rights of the holders of shares ranking prior to the Common
Shares, to share rateably in such assets of the Company as are available for
distribution. The holders of Common Shares have no pre-emptive rights under
Canadian law or the Articles of Continuance.

At October 15, 1995, 75,000 warrants were outstanding at an exercise price
of Cdn. $8.40 expiring on May 5, 2000 and 625,000 warrants were outstanding at
an exercise price of U.S. $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. The Company has the option after December 21, 1997 to
require exercise of the

50
<PAGE> 51

625,000 warrants if the weighted average trading price of the Common Stock
exceeds $10.00 per share for a period of 40 consecutive trading days.

The Company 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 150,000 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.

The Company has granted TPG certain demand and "piggyback" 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 "piggyback" registration rights and preemptive
rights in connection with the Public Offering. Concurrent with the Public
Offering, the Company will sell an additional 800,000 Common Shares to TPG at
the price to the public per share less underwriting discounts and commissions.
See "Concurrent Offerings." TPG will also have demand and "piggyback"
registration rights with respect to the Common Shares purchased in the TPG
Offering.

PREFERRED SHARES

The Company'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 the Company'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 the Company 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.
As of the close of the Offerings, no Preferred Shares will be outstanding. For a
description of the currently outstanding Convertible Preferred, see "Interests
of Management in Certain Transactions."

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

51
<PAGE> 52

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 base of the Common Shares, must be included
in income as a taxable capital gain, to be taxed at prevailing federal Canadian
rates, which range from approximately 26% to 39%.

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
of.

Pursuant to the U.S. -- Canada Income Tax Convention (the "Convention"),
shareholders of the Company who are resident in the U.S. for the purposes of the
Convention and whose shares might 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.

DIVIDENDS

Under the Act, 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 6% for dividends received in 1996 and 5%
thereafter 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.

52
<PAGE> 53

SHARES ELIGIBLE FOR FUTURE SALE

After giving effect to the Offerings and the Capitalization Adjustments,
the Company would have had 19,498,269 Common Shares outstanding as of October
15, 1996 (20,038,269 shares assuming exercise of the Underwriters'
over-allotment option in full). The Common Shares sold in the Public Offering
will be freely tradable without restrictions or further registration under the
Securities Act. Of the 8,408,038 Common Shares beneficially held by TPG upon the
close of the TPG Offering, 7,608,038 Common Shares will be "restricted"
securities within the meaning of the Securities Act as a result of the issuance
thereof in a private transaction. 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 those provided by Rule
144 promulgated under the Securities Act.

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 two
years, 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
(approximately 194,983 Common Shares immediately after the Offerings). 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 three years, would be entitled to sell such shares under Rule 144 without
regard to the volume limitations described above. The Company believes that
7,608,038 shares owned by TPG will be eligible for sale in the public market
pursuant to Rule 144 after December 21, 1997, and the remaining shares
beneficially held by TPG will be eligible for sale in the public market pursuant
to Rule 144 immediately upon close of the TPG Offering. The Company is unable to
estimate the number of shares, if any, that TPG may sell from time to time under
Rule 144, since such number will depend on the future market price, trading
volume for the Common Shares and the number of Common Shares outstanding, as
well as other factors beyond the Company's control.

In connection with the Public Offering, the Company, each of its directors
and executive officers and TPG, subject to certain exceptions, have agreed not
to offer, sell or otherwise dispose of any Common Shares, or any shares
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 Donaldson,
Lufkin & Jenrette Securities Corporation on behalf of the Underwriters. See
"Underwriting."

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 "piggyback" registration rights and
preemptive rights in connection with the Public 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.

53
<PAGE> 54

UNDERWRITING

Subject to the terms and conditions contained in an underwriting agreement
(the "Underwriting Agreement"), a syndicate of underwriters named below (the
"Underwriters"), for whom Donaldson, Lufkin & Jenrette Securities Corporation,
Prudential Securities Incorporated and Johnson Rice & Company L.L.C., are acting
as representatives (the "Representatives"), have severally agreed to purchase
3,600,000 Common Shares from the Company. The number of Common Shares that each
Underwriter have severally agreed to purchase is set forth opposite its name
below:

<TABLE>
<CAPTION>
NUMBER
UNDERWRITERS OF SHARES
- ---------------------------------------------------------------------------------- ----------
<S> <C>
Donaldson, Lufkin & Jenrette Securities Corporation............................... 1,095,200
Prudential Securities Incorporated................................................ 1,095,200
Johnson Rice & Company L.L.C...................................................... 547,600
Bear, Stearns & Co. Inc. ......................................................... 45,000
Dean Witter Reynolds Inc. ........................................................ 45,000
Goldman, Sachs & Co. ............................................................. 45,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated................................ 45,000
Morgan Stanley & Co. Incorporated................................................. 45,000
Oppenheimer & Co., Inc. .......................................................... 45,000
PaineWebber Incorporated.......................................................... 45,000
Salomon Brothers Inc.............................................................. 45,000
Smith Barney Inc. ................................................................ 45,000
Wasserstein Perella Securities, Inc. ............................................. 45,000
Petrie Parkman & Co. ............................................................. 45,000
Southcoast Capital Corporation.................................................... 45,000
FirstEnergy Capital Corp. ........................................................ 23,000
First Southwest Company........................................................... 23,000
Hanifen, Imhoff Inc. ............................................................. 23,000
Hoak Breedlove Wesneski & Co. .................................................... 23,000
Interstate/Johnson Lane Corporation............................................... 23,000
Jefferies & Company Inc. ......................................................... 23,000
McDonald & Company Securities, Inc. .............................................. 23,000
Morgan Keegan & Company, Inc. .................................................... 23,000
Pennsylvania Merchant Group Ltd................................................... 23,000
Principal Financial Securities, Inc. ............................................. 23,000
Rauscher Pierce Refsnes, Inc. .................................................... 23,000
Raymond James & Associates, Inc. ................................................. 23,000
RBC Dominion Securities Corporation............................................... 23,000
Southwest Securities, Inc. ....................................................... 23,000
----------
Total................................................................... 3,600,000
==========
</TABLE>

The Underwriting Agreement provides that the obligation of the several
Underwriters to pay for and accept delivery of the Common Shares are subject to
certain 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 the
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
$0.50 per share. The Underwriters may allow, and such dealers may re-allow, a
discount not in excess of $0.10 per share to any other Underwriter and certain
other dealers.

The Company has granted to the Underwriters an option to purchase up to
540,000 additional Common Shares at the public offering price set forth on the
cover page hereof less underwriting discounts and

54
<PAGE> 55

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 option shares
proportionate to such Underwriter's initial commitment as indicated in the
preceding table.

The Company, each of its directors and executive officers and TPG, subject
to certain exceptions, have agreed not to offer, sell or otherwise dispose of
any Common Shares, or any shares exercisable for or convertible into Common
Shares, prior to the expiration of 120 days from the date of this Prospectus,
without the prior written consent of Donaldson, Lufkin & Jenrette Securities
Corporation on behalf of the Underwriters.

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

In connection with the Public Offering, certain Underwriters may engage in
passive market making transactions in the Common Shares on the Nasdaq National
Market immediately prior to the commencement of sales in the offering made
hereby, in accordance with Rule 10b-6A under the Securities Exchange Act of
1934, as amended. Passive market making consists of displaying bids on the
Nasdaq National Market limited by the bid prices of independent market makers
and purchases limited by such prices and effected in response to order flow. Net
purchases by a passive market maker on each day are limited to a specified
percentage of the passive market maker's average daily trading volume in the
Common Shares during a specified prior period and must be discontinued when such
limit is reached. Passive market making may stabilize the market price of the
Common Shares at a level above that which might otherwise prevail and, if
commenced, may be discontinued at any time.

PLAN OF DISTRIBUTION FOR THE TPG OFFERING

Pursuant to a Stock Purchase Agreement (the "Stock Purchase Agreement")
entered into by TPG and the Company, TPG has irrevocably agreed to purchase
800,000 Common Shares at a price equal to the price to the public per share in
the Public Offering less the underwriting discounts and commissions. Pursuant to
the Stock Purchase Agreement, TPG has represented and warranted that the
execution, delivery and performance of the Stock Purchase Agreement by it has
been duly and validly authorized by all necessary actions and that the Stock
Purchase Agreement is the legal, valid and binding obligation of TPG. The
Company has represented that the execution, delivery and performance of the
Stock Purchase Agreement by it has been duly and validly authorized by all
necessary corporate actions and that the Stock Purchase Agreement is the legal,
valid and binding obligation of the Company.

The TPG Offering is being made directly by the Company to TPG. The TPG
Offering is not being made on an underwritten basis, and the Underwriters of the
Public 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 Offering, an undertaking to the TSE not to sell any of the
Common Shares acquired pursuant to the TPG Offering for a period of six months
following the acquisition of such Common Shares without prior written consent of
the TSE.

The closing of the purchase of Common Shares pursuant to the Stock Purchase
Agreement is conditioned upon, and will occur concurrently with, the closing of
the Public Offering.

55
<PAGE> 56

SERVICE AND ENFORCEMENT OF LEGAL PROCESS

The Company is incorporated under the laws of Canada. Some of the
directors, controlling persons and officers of the Company, 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 the 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 the Company
predicated upon civil liability under the United States federal securities laws.
The Company has been advised by its counsel, Burnet, Duckworth & Palmer,
Calgary, Alberta, that there is doubt as to the enforceability in Canada against
the Company 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.

LEGAL MATTERS

The legality of the Common Shares offered hereby have been passed upon for
the Company by Burnet, Duckworth & Palmer, Calgary, Alberta. Certain matters in
connection with the Public Offering will be passed upon for the Company by
Jenkens & Gilchrist, a Professional Corporation, Houston, Texas, and for the
Underwriters by Baker & Botts, L.L.P., Dallas, Texas.

EXPERTS

The consolidated financial statements and financial statement schedule of
the Company for each of the three years ended December 31, 1995 and the
statements of revenues and direct operating expenses attributable to certain oil
and natural gas properties (Ottawa Properties) acquired by the Company for the
year ended December 31, 1995 included 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 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 attributable to
certain oil and natural gas properties (Amerada Hess Properties) acquired by the
Company for the years ended December 31, 1995, 1994 and 1993 included in this
Prospectus and Registration Statement have been audited by Deloitte & Touche
LLP, independent auditors, as stated in their report appearing herein and have
been so included in reliance upon the report of such firm given upon their
authority as experts in accounting and auditing.

The reference to the reports of Netherland, Sewell & Associates, Inc. and
The Scotia Group, Inc., both 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.

56
<PAGE> 57

AVAILABLE INFORMATION

The Company is subject to the information requirements of the Securities
Exchange Act of 1934, as amended, and in accordance therewith files reports,
proxy statements and other information with the Securities and Exchange
Commission (the "SEC"). Such reports, proxy statements and other information can
be inspected and copied at the public reference facilities maintained by the SEC
at 450 5th Street, N.W., Room 1024, Washington, D.C. 20549, and at the following
regional offices of the SEC: 7 World Trade Center, 13th Floor, New York, New
York 10048 and Northwestern Atrium 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 Company's Common
Stock is traded on the Nasdaq National Market and such reports, proxy statements
and other information may be inspected at the Nasdaq Stock Market, 1735 K
Street, N.W., Washington, D.C. 20006.

The Company has filed with the SEC a Registration Statement on Form S-1
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 SEC. 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 SEC.

57
<PAGE> 58

GLOSSARY

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

ADJUSTED EBITDA. Adjusted 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.

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.

CDN. Canadian.

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.

DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

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 in 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.

58
<PAGE> 59

MBTU. One thousand Btus.

MCF. One thousand cubic feet of natural gas.

MCF/D. One thousand cubic of natural gas produced per day.

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

MMBOE. One million BOEs.

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 using an annual discount
rate of 10% in accordance with the guidelines of the SEC.

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
through 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 operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property as well as to a
share of production.

59
<PAGE> 60

INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
SIX MONTHS ENDED JUNE 30, 1996 AND 1995 (UNAUDITED)

<TABLE>
<CAPTION>
PAGE
----------------
<S> <C>
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 the Consolidated Financial Statements.............................. F-7 thru F-23

Statement of Revenues and Direct Operating Expenses of Ottawa Properties

Independent Auditors' Report.............................................. F-24

Statement of Revenues and Direct Operating Expenses....................... F-25

Notes to Statement of Revenues and Direct Operating Expenses.............. F-26 thru F-27

Statements of Revenues and Direct Operating Expenses of Amerada Hess

Properties

Independent Auditors' Report.............................................. F-28

Statements of Revenues and Direct Operating Expenses...................... F-29

Notes to Statements of Revenues and Direct Operating Expenses............. F-30 thru F-32
</TABLE>

F-1
<PAGE> 61

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Denbury Resources Inc.
(formerly Newscope Resources Ltd.)

We have audited the consolidated balance sheets of Denbury Resources Inc.
(formerly Newscope Resources Ltd.) as at December 31, 1995 and 1994 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, 1995.
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 1994 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, 1995, in accordance with accounting principles generally accepted
in Canada.

DELOITTE & TOUCHE

Chartered Accountants
Calgary, Alberta
February 23, 1996 (October 15, 1996 as to Note 11)

F-2
<PAGE> 62

DENBURY RESOURCES INC. AND SUBSIDIARIES

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

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- JUNE 30,
1994 1995 1996
-------- -------- -----------
(UNAUDITED)
<S> <C> <C> <C>
CURRENT ASSETS
Cash and cash equivalents.................................. $ 712 $ 6,553 $ 3,085
Accrued production receivable.............................. 1,909 3,212 6,307
Trade and other receivables................................ 993 1,160 2,837
------- -------- --------
Total current assets............................... 3,614 10,925 12,229
------- -------- --------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties............................. 44,820 72,510 133,442
Unevaluated oil and natural gas properties................. 6,251 7,085 6,571
Less accumulated depreciation and depletion................ (6,149) (13,982) (21,140)
------- -------- --------
Net property and equipment......................... 44,922 65,613 118,873
------- -------- --------
OTHER ASSETS................................................. 428 1,103 1,798
------- -------- --------
TOTAL ASSETS....................................... $ 48,964 $ 77,641 $ 132,900
======= ======== ========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities................... $ 5,056 $ 3,886 $ 13,288
Current portion of long-term debt.......................... 178 177 125
------- -------- --------
Total current liabilities.......................... 5,234 4,063 13,413
------- -------- --------
LONG-TERM LIABILITIES
Senior bank debt........................................... 14,950 75 40,000
Subordinated debt and other notes payable.................. 1,586 3,399 2,964
Provision for site reclamation costs....................... 138 242 340
Deferred income taxes and other............................ 1,094 1,361 3,166
------- -------- --------
Total long-term liabilities........................ 17,768 5,077 46,470
------- -------- --------
CONVERTIBLE FIRST PREFERRED SHARES, SERIES A
1,500,000 shares authorized, issued and outstanding
at December 31, 1995.................................... -- 15,000 15,759
------- -------- --------
SHAREHOLDERS' EQUITY
Common shares, no par value unlimited shares authorized;
outstanding -- 6,304,667, 11,428,809 and 11,632,215
shares at December 31, 1994, December 31, 1995 and June
30, 1996, respectively.................................. 23,239 50,064 51,226
Retained earnings.......................................... 2,723 3,437 6,032
------- -------- --------
Total shareholders' equity.............................. 25,962 53,501 57,258
------- -------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY......... $ 48,964 $ 77,641 $ 132,900
======= ======== ========
</TABLE>

See Notes to Consolidated Financial Statements.

Approved by the Board:
/s/ Gareth Roberts /s/ Wieland F. Wettstein
-------------------------- --------------------------------
Gareth Roberts Wieland F. Wettstein
Director Director

F-3
<PAGE> 63

DENBURY RESOURCES INC. AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------- ------------------
1993 1994 1995 1995 1996
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
(UNAUDITED)
REVENUES
Oil, natural gas and related product
sales.................................... $ 5,868 $12,692 $20,032 $ 8,997 $20,650
Interest income............................. 76 23 77 21 124
------ ------- ------- ------ -------
Total revenues........................... 5,944 12,715 20,109 9,018 20,774
------ ------- ------- ------ -------
EXPENSES
Production.................................. 2,067 4,309 6,789 3,128 5,350
General and administrative.................. 782 1,105 1,832 935 1,656
Interest.................................... 83 1,146 2,085 927 681
Imputed preferred dividends................. -- -- -- -- 759
Loss on early extinguishment of debt........ -- -- 200 200 440
Depletion and depreciation.................. 1,898 4,209 8,022 3,075 7,382
Franchise taxes............................. -- 65 100 42 107
------ ------- ------- ------ -------
Total expenses...................... 4,830 10,834 19,028 8,307 16,375
------ ------- ------- ------ -------
Income before the following: 1,114 1,881 1,081 711 4,399
Gain on sale of Canadian properties......... 966 -- -- -- --
------ ------- ------- ------ -------
Income before income taxes.................... 2,080 1,881 1,081 711 4,399
Provision for federal income taxes............ (345) (718) (367) (242) (1,804)
------ ------- ------- ------ -------
NET INCOME.................................... $ 1,735 $ 1,163 $ 714 $ 469 $ 2,595
====== ======= ======= ====== =======
NET INCOME PER COMMON SHARE................... $ .35 $ .19 $ .10 $ .07 $ .23
====== ======= ======= ====== =======
Average number of common shares outstanding... 4,990 6,240 6,870 6,536 11,512
====== ======= ======= ====== =======
</TABLE>

See Notes to Consolidated Financial Statements

F-4
<PAGE> 64

DENBURY RESOURCES INC. AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
-------------------------------- --------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income............................ $ 1,735 $ 1,163 $ 714 $ 469 $ 2,595
Adjustments needed to reconcile to net
cash flow provided by operations:
Depreciation, depletion and
amortization..................... 1,916 4,304 8,113 3,075 7,382
Deferred income taxes.............. 345 718 367 242 1,804
Gain on sale of Canadian
properties....................... (966) -- -- -- --
Imputed preferred dividend......... -- -- -- -- 759
Loss on early extinguishment of
debt............................. -- -- 200 200 440
Other.............................. -- -- -- 39 323
-------- -------- -------- -------- --------
3,030 6,185 9,394 4,025 13,303
Changes in working capital items
relating to operations:
Accrued production receivable...... (586) (986) (1,303) (481) (3,096)
Trade and other receivables........ (260) (124) (168) (261) (702)
Accounts payable and accrued
liabilities...................... 2,742 1,842 (1,170) (664) 8,082
-------- -------- -------- -------- --------
NET CASH FLOW PROVIDED BY OPERATIONS.... 4,926 6,917 6,753 2,619 17,587
-------- -------- -------- -------- --------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures... (9,779) (10,297) (11,761) (4,001) (12,759)
Acquisition of oil and natural gas
properties....................... (20,076) (6,606) (16,763) (6,505) (47,974)
Proceeds on disposal of Canadian
properties....................... 3,129 -- -- -- --
Net purchases of other assets...... (157) (122) (560) (227) (754)
Acquisition of subsidiary, net of
cash acquired.................... -- -- -- -- 209
-------- -------- -------- -------- --------
NET CASH USED FOR INVESTING
ACTIVITIES............................ (26,883) (17,025) (29,084) (10,733) (61,278)
-------- -------- -------- -------- --------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank borrowings.................... 7,600 9,835 19,350 5,750 39,900
Bank repayments.................... -- (2,485) (34,200) (2,100) --
Issuance of subordinated debt...... -- 1,451 1,772 1,772 --
Issuance of common stock........... 15,148 367 26,825 2,460 796
Issuance of preferred stock........ -- -- 15,000 -- --
Costs of debt financing............ (251) (122) (493) (269) (378)
Other.............................. 277 62 (82) (36) (95)
-------- -------- -------- -------- --------
NET CASH PROVIDED BY FINANCING
ACTIVITIES............................ 22,774 9,108 28,172 7,577 40,223
-------- -------- -------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS........................... 817 (1,000) 5,841 (537) (3,468)
Cash and cash equivalents at beginning
of year............................... 895 1,712 712 712 6,553
-------- -------- -------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF
PERIOD................................ $ 1,712 $ 712 $ 6,553 $ 175 $ 3,085
======== ======== ======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid during the period for
interest......................... $ 64 $ 1,027 $ 2,127 $ 1,009 $ 271
SUPPLEMENTAL DISCLOSURE OF FINANCING
ACTIVITIES:
Conversion of subordinated debt to
common stock..................... -- -- -- -- $ 366
Assumption of liabilities in
acquisition...................... -- -- -- -- 1,321
</TABLE>

See Notes to Consolidated Financial Statements

F-5
<PAGE> 65

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, 1993........................... 3,789,730 $ 7,724 $ (175) $ 7,549
Issued pursuant to employee stock option plan........ 276,187 1,033 -- 1,033
Private placement of Special Warrants exchanged...... 942,500 5,866 -- 5,866
Private placement of Special Warrants exchanged...... 500,000 4,356 -- 4,356
Private placement of Special Warrants exchanged...... 700,000 3,893 -- 3,893
Net income........................................... -- -- 1,735 1,735
---------- ------- ------ -------
BALANCE -- DECEMBER 31, 1993......................... 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
---------- ------- ------ -------
(Unaudited)
Issued pursuant to employee stock option plan........ 125,750 656 -- 656
Issued pursuant to employee stock purchase plan...... 15,156 140 -- 140
Conversion of subordinated debt...................... 62,500 366 -- 366
Net income........................................... -- -- 2,595 2,595
---------- ------- ------ -------
BALANCE -- JUNE 30, 1996 (UNAUDITED)................. 11,632,215 $51,226 $6,032 $57,258
========== ======= ====== =======
</TABLE>

See Notes to Consolidated Financial Statements

F-6
<PAGE> 66

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995 AND FOR THE SIX MONTHS
ENDED JUNE 30, 1995 AND 1996 (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, Brymore Energy Corporation ("Brymore").
The Company acquired the remaining 50% of Brymore effective May 1, 1996 and
began consolidating all of Brymore as of that date.

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 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.

d) Ceiling test

The capitalized costs less accumulated depletion, depreciation and deferred
taxes 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

F-7
<PAGE> 67

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 is 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. The stock options, warrants, convertible debt and the
conversion of the Convertible First Preferred Shares, Series A ("Convertible
Preferred") were anti-dilutive or immaterial and were not included in the
calculation of earnings per share.

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 original
maturities 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, 1994 and 1995 and June 30, 1996, the Company's aggregate oil and
natural gas imbalances were not material to its financial statements.

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.

F-8
<PAGE> 68

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 financial position as of
June 30, 1996, and the results of operations and changes in financial position
for the six months ended June 30, 1995 and 1996.

2. PROPERTY AND EQUIPMENT

UNEVALUATED OIL AND NATURAL GAS PROPERTIES EXCLUDED FROM DEPLETION

Under full cost accounting, the Company may exclude certain unevaluated
costs from the amortization base pending determination of whether proved
reserves have been discovered or impairment has occurred. A summary of the
unevaluated properties excluded from oil and natural gas properties being
amortized at December 31, 1994 and 1995 and June 30, 1996 and the year in which
they were incurred follows:

<TABLE>
<CAPTION>
DECEMBER 31, 1994 DECEMBER 31, 1995
---------------------------------- ------------------------------------
INCURRED IN INCURRED IN
------------------------ --------------------------
1992 1993 1994 TOTAL 1993 1994 1995 TOTAL
---- ------ ------ ------ ------ ------ ------ ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Property acquisition
cost..................... $11 $3,696 $1,230 $4,937 $1,151 $1,230 $2,909 $5,290
Exploration costs.......... 128 1,186 1,314 -- 1,146 649 1,795
--- ------ ------ ------ ------ ------ ------ ------
Total............ $11 $3,824 $2,416 $6,251 $1,151 $2,376 $3,558 $7,085
=== ====== ====== ====== ====== ====== ====== ======
</TABLE>

<TABLE>
<CAPTION>
JUNE 30, 1996
----------------------------
(UNAUDITED)
INCURRED IN
----------------------------
1994 1995 1996 TOTAL
------ ------ ------ ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
Property acquisition cost............................... $ 606 $ 590 $2,379 $3,575
Exploration costs....................................... 1,101 581 1,314 2,996
------ ------ ------ ------
Total......................................... $1,707 $1,171 $3,693 $6,571
====== ====== ====== ======
</TABLE>

Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
Pending determination of proved reserves attributable to the above costs, the
Company cannot assess the future impact on the amortization rate.

General and administrative costs that directly relate to exploration and
development activities that were capitalized during the period totaled $480,000,
$480,000 and $630,000 for the years ended December 31, 1993, 1994 and 1995 and
$260,000 and $516,000 for the six months ended June 30, 1995 and 1996,
respectively.

Amortization per BOE was $4.36, $4.03, $5.22 and $6.10 for the years ended
December 31, 1993, 1994 and 1995 and six months ended June 30, 1996,
respectively.

F-9
<PAGE> 69

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------ JUNE 30,
1994 1995 1996
------- ------ -----------
(AMOUNTS IN THOUSANDS)

<S> <C> <C> <C>
Senior bank loan..................................... $14,950 $ 100 $40,000
Convertible debentures............................... 1,426 3,296 2,930
Other notes payable.................................. 338 255 159
------- ------ -------
16,714 3,651 43,089
Less portion due within one year..................... 178 177 125
------- ------ -------
Total long-term debt....................... $16,536 $3,474 $42,964
======= ====== =======
</TABLE>

BANKS

On May 5, 1995, the Company refinanced and on November 14, 1995 amended its
revolving credit facility with a new lender, ING Capital Corporation, expanding
its credit line to $25,000,000 from $15,000,000. The new credit facility,
denominated in U.S. dollars, is a senior secured one-year revolving facility
converting to a four year term loan in April 1996, unless renewed or extended.
The total outstanding principal balance may at no time exceed a borrowing base
as determined semi-annually by the lender and is secured by all of the Company's
current and future oil and natural gas properties. Interest is payable at the
Company's option at the bank prime base rate plus 1% or the LIBOR rate plus
2.75%. The credit facility also has certain other restrictions, including: (i) a
requirement to maintain positive working capital, (ii) a minimum equity balance
of $25 million after certain adjustments, (iii) a prohibition on the payment of
dividends, (iv) a maximum of $2 million per year on general and administrative
expenses and (v) a prohibition of most other debt and corporate guarantees. As
of December 31, 1995, the Company had $100,000 outstanding on the line of
credit, with an available borrowing base of $25 million.

On May 30, 1996, the Company refinanced its revolving credit facility with
NationsBank of Texas as agent. See Note 11 for additional disclosures.

SUBORDINATED DEBT

On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of
unsecured convertible debentures. The debentures are due in five years, have an
interest rate of 6 3/4% per annum, and are convertible at any time by the
holders into Common Shares at a conversion price of Cdn. $8.00 per Common Share.
Under certain conditions after July 15, 1996, the Company has the right to
require an early redemption.

On January 17, 1995, Denbury issued Cdn. $2,500,000 principal amount of
unsecured convertible debentures. The debentures are due in five years, have an
interest rate of 9 1/2% per annum, and are convertible at any time by the
holders into Common Shares at a conversion price of Cdn. $8.10 per Common Share.
Under certain conditions after April 13, 1997, the Company has the right to
require an early redemption.

F-10
<PAGE> 70

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INDEBTEDNESS REPAYMENT SCHEDULE

The Company's indebtedness is repayable as follows:

<TABLE>
<CAPTION>
DECEMBER 31, 1995
-------------------------------------------------
CONVERTIBLE OTHER NOTES
YEAR BANK LOAN DEBENTURES PAYABLE TOTAL
------------------------------------------- --------- ----------- ----------- ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
1996....................................... $ 25 $ -- $ 152 $ 177
1997....................................... 33 -- 79 112
1998....................................... 33 -- 22 55
1999....................................... 9 1,465 2 1,476
2000....................................... -- 1,831 -- 1,831
---- ------ ---- ------
$ 100 $ 3,296 $ 255 $3,651
==== ====== ==== ======
</TABLE>

<TABLE>
<CAPTION>
JUNE 30, 1996 (UNAUDITED)
--------------------------------------------------
CONVERTIBLE OTHER NOTES
YEAR BANK LOAN DEBENTURES PAYABLE TOTAL
------------------------------------------ --------- ----------- ----------- -------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
1996...................................... $ -- $ -- $ 56 $ 56
1997...................................... -- -- 79 79
1998...................................... 6,667 -- 22 6,689
1999...................................... 13,333 1,099 2 14,434
2000...................................... 13,333 1,831 -- 15,164
2001...................................... 6,667 -- -- 6,667
------- ------ ---- -------
$40,000 $ 2,930 $ 159 $43,089
======= ====== ==== =======
</TABLE>

4. INCOME TAXES

The Company's tax provision is as follows:

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED ENDED
DECEMBER 31, JUNE 30,
-------------------- --------------
1993 1994 1995 1995 1996
---- ---- ---- ---- ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
(UNAUDITED)
Deferred
Federal....................................... $345 $718 $367 $242 $1,804
State......................................... -- -- -- -- --
---- ---- ---- ---- ------
Total................................. $345 $718 $367 $242 $1,804
==== ==== ==== ==== ======
</TABLE>

F-11
<PAGE> 71

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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>
SIX MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------- --------------
1993 1994 1995 1995 1996
----- ----- ----- ---- ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
(UNAUDITED)
Deferred income tax provision calculated
using the Canadian federal and provincial
statutory combined tax rate of 44.34%...... $ 922 $ 834 $ 479 $315 $2,287
Decrease resulting from:
Effect of lower income tax rates on United
States income.............................. (105) (116) (112) (73) (483)
Utilization of prior years' losses........... (472) -- -- -- --
----- ----- ----- ---- ------
$ 345 $ 718 $ 367 $242 $1,804
===== ===== ===== ==== ======
</TABLE>

The Company at December 31, 1995 had net operating loss carryforwards for
U.S. tax purposes of approximately $12,366,000 and approximately $10,875,000 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>
2005.................................. $ 39 $ --
2006.................................. 11 --
2007.................................. 1,358 599
2008.................................. 5,016 4,889
2009.................................. 3,377 2,868
2010.................................. 2,565 2,519
</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 STOCK

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 Stock by its bank loan agreements.

F-12
<PAGE> 72

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONVERTIBLE DEBENTURES

The Company has reserved 558,642 Common Shares for issuance upon the
conversion of Convertible Debentures which have been issued (See Note 3).

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 and (iii) 1.5 million shares of $10 stated value Convertible First
Preferred Shares, Series A ("Convertible Preferred"). The Convertible Preferred
shares are initially convertible at $7.40 of stated value per common share with
such conversion rate declining 2.5% per quarter. The shares also have a
mandatory redemption at a 63.86% premium at December 21, 2000, but also provide
that the Company can cause a mandatory conversion after January 1, 1999 if the
price of the Common Stock exceeds $10.00 per share for a period of 40
consecutive trading days. The Convertible Preferred do not have any cash or
other stated dividend requirements although the Company is making an accrual
each year to account for the mandatory redemption premium quarterly accretion.
This accrual correspondingly reduces the net income available to the common
shareholders and is considered in the Company's primary earnings per share
calculation. The Company may also force conversion of the warrants after
December 21, 1997, if the price of the Common Stock exceeds $10.00 per share for
a period of 40 consecutive trading days. See Note 11 "Subsequent Events"
concerning a special meeting of shareholders at which the terms of the
Convertible Preferred were modified.

In addition, for a period of two years TPG has 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 that period.
Furthermore, after the initial two years 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 1933, as
amended, for 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 and Convertible Preferred) 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 has waived its registration rights and
right to maintain its pro rata ownership with regard to the Public 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, 1995, 150,000 warrants were outstanding at an exercise
price of Cdn. $8.40 expiring on May 5, 2000 and 625,000 warrants were
outstanding at an exercise price of U.S. $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. The Company has the option after December 21,
1997, to require exercise of the 625,000 warrants if the weighted average
trading price of the Common Stock exceeds $10.00 per share for a period of 40
consecutive trading days.

F-13
<PAGE> 73

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

On April 6, 1993, Denbury issued 942,500 Special Warrants at a price of
Cdn. $8.50 per Special Warrant for gross and net proceeds of $6,348,000 and
$5,866,000 respectively. On June 22, 1993, Denbury issued 500,000 Special
Warrants at a price of Cdn. $12.00 per Special Warrant for gross and net
proceeds of $4,693,000 and $4,356,000 respectively. On December 10, 1993,
Denbury issued an additional 700,000 Special Warrants at a price of Cdn. $8.00
per Special Warrant for gross and net proceeds of $4,208,000 and $3,893,000
respectively. Each of these Special Warrants was exchanged, at no additional
cost, for one Common Share resulting in the issue of 2,142,500 Common Shares.

STOCK OPTIONS AND STOCK PURCHASE PLAN

The Company maintains a Stock Option Plan which authorizes the grant of
options of up to 1,050,000 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. At December
31, 1995, a total of 731,925 options had been granted under the plan, of which
539,625 shares were exercisable as of that date. 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. This plan is
administered by the Stock Purchase Plan Committee of the Board.

Following is a summary of stock option activity during the years ended
December 31, 1993, 1994 and 1995 and the six months ended June 30, 1996:

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
----------------------------------- JUNE 30,
SHARES UNDER OPTION 1993 1994 1995 1996
---------------------------------------- --------- --------- --------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C>
Outstanding at beginning of year........ 329,500 541,312 557,312 731,925
Granted................................. 500,500 138,750 274,500 444,000
Terminated.............................. (12,500) (26,500) (89,887) (6,750)
Exercised............................... (276,188) (96,250) (10,000) (125,750)
Expired................................. -- -- -- --
--------- --------- --------- ---------
Outstanding at end of period
(exercisable at $1.25 to $5.68 per
share)................................ 541,312 557,312 731,925 1,043,425
========= ========= ========= =========
</TABLE>

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.

F-14
<PAGE> 74

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

The Company does not have any hedge contracts in place as of September 30,
1996.

7. COMMITMENTS AND CONTINGENCIES

The Company has operating leases for the rental of office space, office
equipment, and vehicles. At June 30, 1996 and December 31, 1995, long-term
commitments for these items require the following future minimum rental
payments:

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1995 1996
------------ -----------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C>
1996........................................ $304 $ 320
1997........................................ 251 428
1998........................................ 239 409
1999........................................ 86 166
2000........................................ -- --
---- ------
$880 $ 1,323
==== ======
</TABLE>

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 difference between Canadian and U.S. GAAP affecting
the Company's 1995 financial statements results from the fact that under U.S.
GAAP the loss on early extinguishment of debt during 1995 would be an
extraordinary item while under Canadian GAAP, it is not extraordinary.

Net income, net income per share and all balance sheet amounts for the year
ended December 31, 1995 are not effected by the difference in GAAP; however, the
net income before extraordinary items would be $846,000 ($.12 per common share)
as compared to the $714,000 ($.10 per common share) as reported under Canadian
GAAP.

The primary differences between Canadian and U.S. GAAP affecting the
Company's 1996 consolidated financial statements relate to the presentation of
the early extinguishment of debt and the imputed dividend on

F-15
<PAGE> 75

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the Convertible Preferred. During the first six months of 1996, the Company
expensed $759,000 relating to the imputed preferred dividend, as required under
Canadian GAAP. Under U.S. GAAP, this dividend would be deducted after 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
agreement with ING Capital Corporation totaling $440,000. 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 for the first six months of 1996 under U.S. GAAP would be
$3,354,000, while under Canadian GAAP the amount reported was $2,595,000.

In addition, the methodology for computing earnings per common share is not
consistent between the two countries. However, for the first six months of 1996
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. Therefore the
difference in methodology had no effect on the earnings per common share
reported in the Consolidated Financial Statements.

In 1995, the United States Financial Accounting Standards Board issued
Statement of Financial Accounting Standard ("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 does
not intend to recognize compensation expense as calculated under SFAS No. 123 in
the future and intends to continue recognizing expense as prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed under
SFAS No. 123. As such, the adoption of SFAS No. 123 during 1996 will not have
any effect on the Company's consolidated financial statements.

As of June 30, 1996, the Company has two stock-based compensation plans. In
the stock purchase plan which was implemented on February 1, 1996, an employee
can elect to contribute up to 10% of their base earnings. The Company matches
75% of these contributions and the combined funds are used to purchase
previously unissued Common Shares based upon the current market price. The
Company recognizes compensation expense for the 75% Company matching portion,
which during the six months ended June 30, 1996 totaled $60,000.

F-16
<PAGE> 76

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company also has a stock option plan as more fully described in Note 5.
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:

YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
1995 1996
------------ --------------
(UNAUDITED)
<S> <C> <C>
Net income:
As reported (thousands)................................. $ 714 $2,595
Pro forma (thousands)................................... 503 2,435
Net income per common share:
As reported............................................. $ .10 $ .23
Pro forma............................................... .07 .21
Stock options issued during period (thousands)............ 275 444
Weighted average exercise price........................... $ 5.90 $ 8.64
Average per option compensation value of options
granted(1).............................................. 2.34 2.88
Compensation cost (thousands)............................. 320 243
</TABLE>

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

(1) 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 37% 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 relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1994 and 1995 and June 30, 1996
balance sheet dates. At December 31, 1994, and 1995 and June 30, 1996, all
deferred tax assets and liabilities were computed based on Canadian GAAP amounts
and were noncurrent as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------- JUNE 30,
1994 1995 1996
------- ------- -----------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
Deferred tax assets:
Loss carryforwards.......................................... $(3,332) $(4,205) $(5,380)
Deferred tax liabilities:
Exploration and intangible development costs................ 4,396 5,636 8,615
------- ------- -------
Net deferred tax liability.................................... $ 1,064 $ 1,431 $ 3,235
======= ======= =======
</TABLE>

9. SUPPLEMENTAL INFORMATION

GEOGRAPHIC SEGMENTS

During 1993, the Company had $618,000 of oil and natural gas sales in
Canada and generated $1,065,000 of net income in Canada, including the gain on
sale of Canadian properties of $966,000. All Canadian oil and natural gas
properties were disposed of in 1993 and thus, all of the Company's operations
are now in the United States.

F-17
<PAGE> 77

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1995, the Company sold 10% or more of its net
production of oil and natural gas to the following purchasers: Natural Gas
Clearinghouse (21%), Amerada Hess (20%), Conoco, Inc. (12%), and Brymore Energy
Corp. (12%).

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.

Costs incurred in oil and natural gas activities for the years ended
December 31, 1993, 1994 and 1995 and the six months ended June 30, 1996 are as
follows:

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------------- JUNE 30,
1993 1994 1995 1996
------- ------- ------- -----------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C>
Property acquisition................... $21,604 $ 6,736 $17,198 $48,179
Exploration............................ 608 1,796 1,687 1,841
Development............................ 7,643 8,371 9,639 10,713
------- ------- ------- -------
$29,855 $16,903 $28,524 $60,733
======= ======= ======= =======
</TABLE>

PROPERTY ACQUISITIONS

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

The 1995 acquisition was accounted for under purchase accounting and the
results of operations were consolidated beginning October 1, 1995. Unaudited pro
forma results of operations of the Company as if the acquisition had occurred at
the beginning of each respective period are as follows:

<TABLE>
<CAPTION>
PRO FORMA
YEAR ENDED
DECEMBER 31,
---------------------
1994 1995
------- -------
(IN THOUSANDS
EXCEPT PER SHARE
AMOUNTS)
(UNAUDITED)
<S> <C> <C>
Revenues....................................................... $14,587 $22,235
Net income..................................................... 767 587
Net income per common share.................................... .12 .09
</TABLE>

F-18
<PAGE> 78

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 that bank debt that was
required to fund the acquisition.

No additional general and administrative expense was expected as the
Company could absorb these operations without additional personnel.

The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Gibson/Humphreys field 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
------ ------
(AMOUNTS IN
THOUSANDS)
<S> <C> <C>
Revenues:
Oil, natural gas and related product sales..................... $1,872 $2,849
------ ------
Direct operating expenses:
Lease operating expense........................................ 495 420
Severance and property taxes................................... 87 154
------ ------
582 574
------ ------
Excess of revenues over direct operating expenses................ $1,290 $2,275
====== ======
</TABLE>

See Note 11 for additional property acquisition disclosures.

10. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

Net proved oil and natural gas reserve estimates as of July 1, 1996 and
December 31, 1995 were prepared by Netherland & Sewell and the net oil and
natural gas reserve estimates as of December 31, 1994 and 1993 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-19
<PAGE> 79

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ESTIMATED QUANTITIES OF RESERVES

YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
-------------------------------------------------------- JUNE 30,
1993 1994 1995 1996
---------------- ---------------- ---------------- ----------------
OIL GAS OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE BEGINNING OF YEAR... 565 2,383 3,583 13,029 4,230 42,047 6,292 48,116
Revisions of previous
estimates.............. (254) 234 (48) 2,827 830 (1,620) (259) (238)
Extensions, discoveries
and other additions.... 299 -- 640 14,978 732 -- 10 3,134
Production................ (272) (673) (489) (3,326) (728) (4,844) (527) (4,098)
Acquisition of minerals in
place.................. 3,245 11,084 544 14,539 1,228 12,533 6,209 18,893
----- ------ ----- ------ ----- ------ ------ ------
BALANCE AT END OF PERIOD.... 3,583 13,029 4,230 42,047 6,292 48,116 11,725 65,807
===== ====== ===== ====== ===== ====== ====== ======
PROVED DEVELOPED RESERVES:
Balance at beginning of
year................... 425 1,755 3,418 12,303 3,755 35,578 5,290 34,894
Balance at end of
period................. 3,418 12,303 3,755 35,578 5,290 34,894 10,439 58,052
</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.

F-20
<PAGE> 80

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------ JULY 1,
1993 1994 1995 1996
-------- -------- -------- ---------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
Future cash inflows................................... $ 67,279 $126,129 $214,932 $ 392,385
Future production costs............................... (20,587) (35,069) (56,323) (105,280)
Future development costs.............................. (3,408) (7,369) (16,154) (24,117)
------- -------- -------- ---------
Future net cash flows before taxes.................... 43,284 83,691 142,455 262,988
10% annual discount for estimated timing of cash
flows............................................ (14,646) (31,000) (45,490) (87,733)
------- -------- -------- ---------
Discounted future net cash flows before taxes......... 28,638 52,691 96,965 175,255
Discounted future income taxes........................ (173) (5,763) (15,801) (25,095)
------- -------- -------- ---------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS............................................... $ 28,465 $ 46,928 $ 81,164 $ 150,160
======= ======== ======== =========
</TABLE>

The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
---------------------------- JUNE 30,
1993 1994 1995 1996
------- ------- -------- ----------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
Beginning of year.................................. $ 4,584 $28,465 $ 46,928 $ 81,164
Sales of oil and natural gas produced, net of
production costs................................. (3,801) (8,383) (13,243) (15,300)
Net changes in sales prices........................ (937) 863 23,037 20,556
Extensions and discoveries, less applicable future
development costs................................ 579 13,416 1,926 2,239
Previously estimated development costs incurred.... 709 2,492 2,193 3,331
Revisions of previous estimates, including revised
estimates of development costs, reserves and
rates of production.............................. (996) (2,914) 3,958 (3,975)
Accretion of discount.............................. 458 2,847 4,693 4,058
Purchase of minerals in place...................... 27,304 15,732 21,710 67,381
Net change in income taxes......................... 565 (5,590) (10,038) (9,294)
------- ------- -------- --------
End of period...................................... $28,465 $46,928 $ 81,164 $150,160
======= ======= ======== ========
</TABLE>

11. SUBSEQUENT EVENTS

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 owns an interest, plus certain overriding royalty interests in
other areas for approximately $7.5 million. 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 acquisition included 439 wells (110
net working interest wells), of which 129 wells are Company operated with the
balance consisting of 124 non-operated working interest wells and 186 royalty
interests wells. Of the 439 total acquired wells, 37 operated, 37 non-operated
and 21 royalty interest wells are currently non-producing. The Company funded
this acquisition with bank financing from a new credit facility and closed this
transaction during June 1996.

F-21
<PAGE> 81

DENBURY RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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>
SIX MONTHS ENDED
YEAR ENDED JUNE 30,
DECEMBER 31, -------------------
1995 1995 1996
------------ ------- -------
(IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)
<S> <C> <C> <C>
Revenues............................................ $ 41,273 $18,913 $28,698
Net income.......................................... 899 878 3,516
Net income per common share......................... .13 .13 .31
</TABLE>

In order to fund these two acquisitions and also to generally improve the
terms and increase the size of its existing credit facility, the Company has
entered into a new $150 million credit facility with NationsBank of Texas
("NationsBank"). This refinancing closed on May 31, 1996 and has a borrowing
base as of October 15, 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. 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.

At a meeting of the Board of Directors of the Company on May 16, 1996, the
Company's Stock Option Plan was amended to increase the number of option shares
authorized to be issued under the Plan from 1,050,000 to 1,250,000. This
amendment is subject to shareholder and regulatory approval.

On July 31, 1996, the Company issued 187,500 Common Shares for the
conversion of the remaining 6 3/4% Convertible Debentures of the Company and on
August 27, 1996, issued 75,000 Common Shares for the exercise of 75,000 Cdn.
$8.40 warrants.

The Company held a Special Meeting of its shareholders on October 9, 1996
and passed three resolutions. The first resolution ratified and approved an
amendment to the Articles of Continuance to consolidate the number of issued and
outstanding Common Shares on the basis of one (1) Common Share for each two (2)
Common Shares outstanding. All applicable shares and per share data have been
adjusted for the stock split. The second resolution ratified and approved an
amendment to the Articles of Continuance which governs the conversion provision
attaching to the Convertible Preferred Shares which gave the Company the right
to require the holders of the Preferred Shares to convert their Preferred Shares
into Common Shares at any time, provided that the conversion rate in effect as
of January 1, 1999 would be used for any required conversion prior to that date.
Prior to this Preferred Amendment, the Company could not require a conversion of
these Preferred Shares prior to January 1, 1999. Subject to, and simultaneously
with, the completion of the Offerings, the Company plans to require a
conversion, thereby increasing the number of Common Shares of the Company by
2,816,372 and eliminating the outstanding Preferred Shares.

The third resolution passed provides for the Company to issue Common Shares
at an issue price of Cdn. $14.72 per share in payment of the interest that would
be due on the 9 1/2% Convertible Debentures from the conversion date through and
including April 13, 1997, if the holders of the debentures convert their
debentures into Common Shares prior to April 13, 1997. On October 15, 1996,
these debentures were converted by the holders in accordance with their terms
into 308,642 Common Shares along with an additional 7,948 Common Shares for the
interim interest.

F-22
<PAGE> 82

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 1994 and 1995 and the first two quarters of 1996 (in
thousands except per share amounts).

<TABLE>
<CAPTION>
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
<S> <C> <C> <C> <C>
1994
Revenues................................................ $2,574 $ 2,951 $3,400 $ 3,790
Expenses................................................ 2,011 2,351 2,829 3,643
Net income.............................................. 365 369 350 79
Net income per share.................................... .06 .06 .06 .01
Cash flow from operations(a)............................ 1,361 1,514 1,665 1,645
1995
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.................................... .08 0.00 .02 0.00
Cash flow from operations(a)............................ 2,112 1,913 2,234 3,135
1996
Revenues................................................ $9,092 $11,682
Expenses................................................ 6,767 9,608
Net income.............................................. 1,380 1,215
Net income per share.................................... .12 .11
Cash flow from operations(a)............................ 6,065 7,238
</TABLE>

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

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

F-23
<PAGE> 83

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of
Denbury Resources Inc.

We have audited the accompanying statement of revenues and direct operating
expenses attributable to certain oil and natural gas properties ("Ottawa
Properties") (see Note 1) acquired by Denbury Resources Inc. for the year ended
December 31, 1995. This statement is the responsibility of the management of
Ottawa Energy, Inc., as operator of the properties. Our responsibility is to
express an opinion on this statement based on our audit.

We conducted our audit 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
statement is free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the statement. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.

The accompanying statement of revenues and direct operating expenses
reflect the revenues and direct operating expenses attributable to the Ottawa
Properties as described in Note 1 to the statement and is not intended to be a
complete presentation of the revenues and expenses of the Ottawa Properties.

In our opinion, the accompanying statement presents fairly, in all material
respects, the revenues and direct operating expenses described in Note 1 of the
Ottawa Properties for the year ended December 31, 1995, in accordance with
generally accepted accounting principles.

DELOITTE & TOUCHE

Chartered Accountants
Calgary, Alberta
April 9, 1996 (April 15, 1996 as to Note 1)

F-24
<PAGE> 84

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF OTTAWA PROPERTIES

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED JUNE 30,
DECEMBER 31, -----------------
1995 1995 1996
------------ ------- -------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product sales................... $2,954 $ 1,492 $ 1,766
Direct operating expenses:
Lease operating expense...................................... 659 297 320
------ ------ ------
Excess of revenue over direct operating expenses............... $2,295 $ 1,195 $ 1,446
====== ====== ======
</TABLE>

The accompanying notes are an integral part of these statements.

F-25
<PAGE> 85

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF OTTAWA PROPERTIES

1. THE PROPERTIES

The accompanying statements represent the revenues and direct operating
expenses attributable to the net interest in producing wells and certain
non-producing leases sold to Denbury Resources Inc. ("Denbury"), by Ottawa
Energy, Inc. ("Ottawa") for approximately $8.0 million, before adjustments.
Denbury closed on $5.6 million of the acquisition on April 15, 1996 and closed
on the remainder at the end of April. The properties are located in the states
of Texas, Louisiana, and Mississippi. These acquired properties and related
operations were included in the Company's consolidated financial statements
effective April 1, 1996.

2. BASIS OF PRESENTATION

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, these statements of revenue and direct operating expenses are
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X. All of the statements and
disclosures are stated in U.S. dollars.

The accompanying statements of revenues and direct operating expenses
represent Ottawa's net ownership interest in the properties acquired by Denbury
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
Denbury.

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 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.

3. CONTINGENT LIABILITIES

Given the nature of the properties acquired and as stipulated in the
purchase agreement, Denbury is subject to loss contingencies pursuant to
existing or expected environmental laws, regulations, and leases covering the
acquired properties.

4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED)

Unaudited reserve information as of December 31, 1994 and December 31, 1995
related to the properties being acquired is presented in the table below.

<TABLE>
<CAPTION>
OIL GAS
OIL AND NATURAL GAS RESERVE QUANTITIES (MBBL) (MMCF)
----------------------------------------------------------------- ------- -------
<S> <C> <C>
Proved Developed and Undeveloped Reserves:
December 31, 1994.............................................. 1,049.2 3,228.0
Production.................................................. (144.8) (615.5)
------- -------
December 31, 1995.............................................. 904.4 2,612.5
======= =======
Proved Developed Reserves:
As of December 31, 1994........................................ 514.5 3,228.0
As of December 31, 1995........................................ 743.3 2,612.5
</TABLE>

F-26
<PAGE> 86

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF OTTAWA PROPERTIES -- (CONTINUED)

<TABLE>
<CAPTION>
DECEMBER 31, 1995
-----------------
(AMOUNTS IN
THOUSANDS)
-----------------
<S> <C>
Future cash inflows.................................................. $21,593.7
Future production and development costs.............................. (5,381.4)
---------
Future net cash flows undiscounted................................... 16,212.3
10% Annual discount for estimated timing of cash flows............... (5,149.8)
---------
Discounted future net cash flows before taxes........................ 11,062.5
Discounted future income taxes....................................... (1,211.0)
---------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS............. $ 9,851.5
=========
</TABLE>

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

<TABLE>
<CAPTION>
DECEMBER 31, 1995
-----------------
(AMOUNTS IN
THOUSANDS)
-----------------
<S> <C>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AT BEGINNING
OF PERIOD.......................................................... $ 9,035.6
Changes resulting from:
Net change in prices............................................... 2,548.6
Sales of oil and natural gas produced.............................. (2,295.2)
Net change in income taxes......................................... (420.0)
Accretion of discount.............................................. 982.6
---------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AT END OF
PERIOD............................................................. $ 9,851.6
=========
</TABLE>

F-27
<PAGE> 87

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of
Denbury Resources Inc.

We have audited the accompanying statements of revenues and direct
operating expenses attributable to certain oil and natural gas properties
("Amerada Hess Properties") (see Note 1) acquired by Denbury Resources Inc. for
the years ended December 31, 1995, 1994 and 1993. These statements are the
responsibility of the management of Amerada Hess Corporation, as owner of the
properties. Our responsibility is to express an opinion on these statements
based on our audits.

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

The accompanying statements of revenues and direct operating expenses
reflect the revenues and direct operating expenses attributable to the Amerada
Hess Properties as described in Note 1 to the statements and is not intended to
be a complete presentation of the revenues and expenses of the Amerada Hess
Properties.

In our opinion, the accompanying statements present fairly, in all material
respects, the revenues and direct operating expenses of the Amerada Hess
Properties described in Note 1 for the years ended December 31, 1995, 1994 and
1993 in accordance with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Dallas, Texas
May 22, 1996 (June 21, 1996 as to Note 1)

F-28
<PAGE> 88

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF
AMERADA HESS PROPERTIES
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------- ----------------
1993 1994 1995 1995 1996
------- ------- ------- ------ ------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and related product sales... $26,087 $17,787 $18,210 $8,403 $9,893
Direct operating expenses:
Lease operating expense...................... 7,908 6,598 7,888 3,497 3,476
------- ------- ------- ------ ------
Excess of revenues over direct operating
expense...................................... $18,179 $11,189 $10,322 $4,906 $6,417
======= ======= ======= ====== ======
</TABLE>

The accompanying notes are an integral part of these statements.

F-29
<PAGE> 89

NOTES TO STATEMENT OF REVENUES
AND DIRECT OPERATING
EXPENSES OF AMERADA HESS PROPERTIES

1. THE PROPERTIES

The accompanying statements represent the revenues and direct operating
expenses attributable to the net interest in producing wells and certain
non-producing leases sold to Denbury Resources Inc. ("Denbury"), by Amerada Hess
Corporation ("Amerada Hess") for approximately $42.0 million, before adjustments
totaling approximately $5 million which included a purchase price reduction for
interim net cash flow from January 1, 1996, the effective date. The properties
are located in the states of Louisiana, Mississippi, Alabama, and Ohio. The
acquisition closed in June 1996. These acquired properties and related
operations were included in the Company's consolidated financial statements
effective May 1, 1996.

2. BASIS OF PRESENTATION

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, these statements of revenues and direct operating expenses are
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X. All of the statements and
disclosures are stated in U.S. dollars.

The accompanying statements of revenues and direct operating expenses
represent Amerada Hess's net ownership interest in the properties acquired by
Denbury 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 Denbury.

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 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.

3. CONTINGENT LIABILITIES

Given the nature of the properties acquired and as stipulated in the
purchase agreement, Denbury is subject to loss contingencies, if any, pursuant
to existing or expected environmental laws, regulations, and leases covering the
acquired properties.

F-30
<PAGE> 90

NOTES TO STATEMENT OF REVENUES
AND DIRECT OPERATING
EXPENSES OF AMERADA HESS PROPERTIES -- (CONTINUED)

4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED)

Unaudited reserve information related to the properties being acquired is
presented in the table below and is derived from the July 1, 1996 oil and
natural gas reserve report prepared by Netherland & Sewell, and calculated as of
December 31, 1995, 1994 and 1993 and January 1, 1993 by adding production for
1996, 1995, 1994 and 1993 to the July 1, 1996 amount.

<TABLE>
<CAPTION>
OIL GAS
ESTIMATED QUANTITIES OF PROVED RESERVES (MBBL) (MMCF)
---------------------------------------------------------------- -------- --------
<S> <C> <C>
January 1, 1993............................................... 8,528.7 15,060.5
Production................................................. (1,219.0) (3,391.4)
-------- --------
December 31, 1993............................................. 7,309.7 11,669.1
Production................................................. (965.9) (2,303.6)
-------- --------
December 31, 1994............................................. 6,343.8 9,365.5
Production................................................. (939.7) (2,540.7)
-------- --------
December 31, 1995............................................. 5,404.1 6,824.8
======== ========
Proved Developed Reserves:
As of January 1, 1993......................................... 7,948.7 14,994.9
As of December 31, 1993....................................... 6,729.7 11,603.5
As of December 31, 1994....................................... 5,763.8 9,299.9
As of December 31, 1995....................................... 4,824.1 6,759.2
</TABLE>

F-31
<PAGE> 91

NOTES TO STATEMENT OF REVENUES
AND DIRECT OPERATING
EXPENSES OF AMERADA HESS PROPERTIES -- (CONTINUED)

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 being acquired is calculated
in accordance with Statement of Financial Accounting Standards No. 69. The
Standardized Measure has been prepared assuming year-end selling prices adjusted
for future fixed and determinable contractual price changes, year-end
development and production costs and a 10% annual discount rate. The reserves
and the related Standardized Measure at December 31, 1995, derived from the July
1, 1996 oil and natural gas reserve report prepared by Netherland & Sewell, were
adjusted for production during 1996, 1995, 1994, and 1993 and, in addition, the
Standardized Measure was also adjusted for price changes to derive reserves and
the Standardized Measure as of December 31, 1995, 1994 and 1993. 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. Since the purchase price is approximately equal to the
Standardized Measure of discounted future net cash flows, a tax provision has
not been included.

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows.................................. $147,473 $129,686 $111,476
Future production and development costs.............. (61,493) (54,895) (47,007)
-------- -------- --------
Future net cash flows undiscounted................... 85,980 74,791 64,469
10% annual discount for estimated timing of cash
flows.............................................. (34,497) (27,683) (14,978)
-------- -------- --------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS.............................................. $ 51,483 $ 47,108 $ 49,491
======== ======== ========
</TABLE>

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS AT BEGINNING OF PERIOD....................... $ 81,869 $ 51,483 $ 47,108
Changes resulting from:
Net change in prices............................... (20,393) 1,666 7,993
Sales of oil and natural gas produced.............. (18,179) (11,189) (10,321)
Accretion of discount.............................. 8,186 5,148 4,711
-------- -------- --------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS AT END OF PERIOD............................. $ 51,483 $ 47,108 $ 49,491
======== ======== ========
</TABLE>

F-32
<PAGE> 92

August 10, 1996

Mr. Matthew W. Deso
Denbury Management, Inc.
Suite 200
17304 Preston Road
Dallas, Texas 75252

Dear Mr. Deso:

In accordance with your request, we have estimated the proved reserves and
future revenue, as of July 1, 1996, to the Denbury Management, Inc. (DMI)
interest in certain oil and gas properties located in Alabama, Louisiana,
Mississippi, Ohio, and Texas as listed in the accompanying tabulations. These
properties include those acquired from Amerada Hess Corporation (AHC) effective
January 1, 1996, as well as those acquired in other transactions during the
first half of 1996. For the purposes of this report, all DMI properties except
those acquired from AHC are referred to as the Corporate Properties. This report
has been prepared using constant prices and costs and conforms to the guidelines
of the Securities and Exchange Commission (SEC).

As presented in the accompanying summary projections, Tables I through IV,
we estimate the net reserves and future net revenue to the DMI interest, as of
July 1, 1996, 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...................... 5,787,264 21,115,993 $104,619,100 $ 83,585,700
Non-Producing.................. 4,651,331 36,935,535 131,825,700 74,257,900
Proved Undeveloped............... 1,285,964 7,755,584 26,543,100 17,411,800
---------- ---------- ------------ ------------
Total Proved........... 11,724,559 65,807,112 $262,987,900 $ 175,255,400
</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.

This report includes summary projections of reserves and revenue for each
reserve category. For the purposes of this report, the term "lease" refers to a
single economic projection.

A-1

<PAGE> 93

The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, and proved
undeveloped reserves. In accordance with SEC guidelines, our estimates do not
include any value for probable or possible reserves which may exist 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.

As requested, oil prices used in this report are based on a July 1, 1996
NYMEX Cushing West Texas Intermediate posted price of $20.00 per barrel,
adjusted by lease for gravity, transportation fees, and regional posted price
differentials. The sulfur and natural gas liquids prices used for the Lambeth
7-14 located in Big Escambia Creek Field, Alabama, are $43.30 per long ton and
$14.60 per barrel, respectively. The natural gas liquids price for Gibson Field,
Louisiana, is $14.97 barrel. Gas prices used in this report are based on a July
1, 1996 NYMEX Henry Hub price of $2.65 per MMBTU, adjusted by lease for
transportation fees and regional spot market price differentials. Oil, sulfur,
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 AHC. 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;

A-2

<PAGE> 94

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. 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.

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.; 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
Frederic D. Sewell

A-3

DMA:MMD
<PAGE> 95
================================================================================

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 THE SELLING
SHAREHOLDER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES TO
WHICH IT RELATES NOR DOES IT CONSTITUTE AN OFFER OR SOLICITATION BY ANYONE IN
ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION WOULD BE UNLAWFUL OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY OFFER OR SALE MADE HEREUNDER AT ANY TIME
SHALL IMPLY THAT INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE
DATE HEREOF.
---------------------

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 10
Concurrent Offerings.................. 15
Use of Proceeds....................... 15
Price Range of Common Shares and
Dividend Policy..................... 16
Capitalization........................ 17
Pro Forma Operating Results........... 18
Selected Consolidated Financial
Data................................ 21
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 22
Business and Properties............... 28
Management............................ 43
Interests of Management in Certain
Transactions........................ 47
Security Ownership of Certain
Beneficial Owners and Management.... 49
Description of Capital Stock.......... 50
Canadian Taxation and the Investment
Canada Act.......................... 51
Shares Eligible for Future Sale....... 53
Underwriting.......................... 54
Plan of Distribution for the TPG
Offering............................ 55
Service and Enforcement of Legal
Process............................. 56
Legal Matters......................... 56
Experts............................... 56
Available Information................. 57
Glossary.............................. 58
Index to Consolidated Financial
Statements.......................... F-1
Letter of Netherland, Sewell &
Associates, Inc. ................... A-1
</TABLE>

================================================================================

4,400,000 SHARES

[DRI LOGO]

DENBURY RESOURCES INC.

COMMON STOCK

----------
PROSPECTUS
----------

DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION

PRUDENTIAL SECURITIES INCORPORATED

JOHNSON RICE & COMPANY L.L.C.

REPRESENTATIVES OF THE UNDERWRITERS

================================================================================