SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 1998
OR
|_| Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _________ to________
Commission file number 33-93722
-------------------------------
DENBURY RESOURCES INC.
DENBURY MANAGEMENT, INC.
(Exact name of Registrants as specified in its charter)
Canada Not applicable
Texas 75-2294373
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
17304 Preston Rd., Suite 200
Dallas, TX 75252
(Address of principal executive offices) (Zipcode)
Registrant's telephone number, including area code: (972)673-2000
Securities registered pursuant to Section 12(b) of the Act:
================================================================================
Title of Each Class Name of Each Exchange on Which Registered
- --------------------------------------------------------------------------------
Common Shares ( No Par Value) New York Stock Exchange
================================================================================
Securities registered pursuant to
Section 12(g) of the Act: 9% Senior Subordinated Notes Due 2008
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of February 22, 1999, the aggregate market value of the registrant's
Common Shares held by non-affiliates was approximately $78,000,000.
The number of shares outstanding of the registrant's Common Shares as of
February 22, 1999, was 26,801,680.
DOCUMENTS INCORPORATED BY REFERENCE
Document Incorporated as to
1. Notice and Proxy Statement 1. Part III, Items 10, 11, 12,
for the Annual Meeting of and 13
Shareholders to be held May 19, 1999
<PAGE>
Denbury Resources Inc.
1998 Annual Report on Form 10-K
Table of Contents
Item Page
- ---- ----
PART 1
1. Business.....................................................1
2. Properties..................................................15
3. Legal Proceedings...........................................15
4. Submission of Matters to a Vote of Security Holders.........15
PART II
5. Market for Common Stock and Related Matters.................15
6. Selected Financial Data.....................................16
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................17
7A. Quantitative and Qualitative Disclosures About Market Risk..32
8. Financial Statements and Supplementary Data.................32
Index to Financial Statements and Schedules.......F-1
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................33
PART III
10. Directors and Executive Officers of the Company.............33
11. Executive Compensation......................................33
12. Security Ownership of Certain Beneficial Owners
and Management.....................................33
13. Certain Relationships and Related Transactions..............34
PART IV
14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K................................34
<PAGE>
PART I
Item 1. Business
- ----------------
The Company
Denbury Resources Inc. ("Denbury" or the "Company") is a Canadian
corporation organized under the Canada Business Corporations Act engaged in the
acquisition, development, operation and exploration of oil and gas properties
primarily in the Gulf Coast region of the United States through its wholly-owned
subsidiary, Denbury Management, Inc., a Texas corporation. Denbury's corporate
headquarters is located at Suite 200, 17304 Preston Road, Dallas, Texas 75252,
U.S.A., phone number 972-673-2000, and its Canadian office is located at 2550,
140--4th Avenue S.W., Calgary, Alberta T2P 3N3, phone number 403-266-1101. The
Company's headquarters will move, effective March 29, 1999, to 5100 Tennison
Parkway, Plano, Texas 75024 although the phone number is not expected to change.
At December 31, 1998, the Company had 205 employees, 92 of which were employed
in field operations.
Incorporation and Organization
Denbury was originally incorporated under the laws of Manitoba as a
specially limited company on March 7, 1951, under the name "Kay Lake Mines
Limited (N.P.L.)". In September 1984, the Company was continued under the Canada
Business Corporations Act and changed its name to "Newscope Resources Limited."
The Company has subsequently changed its name three times, including the most
recent change in December, 1995 from "Newscope Resources Ltd." to its current
name of "Denbury Resources Inc.".
The Company has one wholly owned subsidiary, Denbury Management, Inc.
("Denbury Management"). Another wholly owned subsidiary, Denbury Holdings Ltd.,
was merged into the parent company in December 1997. Denbury Management has two
active wholly owned subsidiaries, Denbury Marine, L.L.C. and Denbury Energy
Services. The Company's consolidated financial statements include the accounts
of the parent company and all wholly owned subsidiaries.
History
The Company acquired all of the outstanding shares of Denbury Management
in a multi-step transaction in July 1992, in exchange for 1,385,765 Common
Shares (the "Denbury Acquisition"). Upon completion of the Denbury Acquisition,
Mr. Gareth Roberts, the then president of Denbury Management, was appointed the
President and Chief Executive Officer of the Company and was elected to the
Company's board of directors. He has served in that capacity since that time.
Subsequent to the merger, in September 1993, Denbury sold all of its remaining
Canadian oil and gas operations for approximately $3.1 million. As a result,
100% of Denbury's oil and gas operations are now conducted in the Southern
United States, primarily onshore Louisiana and Mississippi, through its
subsidiary, Denbury Management.
Proposed Change in Legal Domicile
The board of directors has approved Denbury changing its legal domicile
from Canada to the United States. The Company has filed a registration statement
with the SEC containing a form of proxy statement to be used to solicit
shareholder approval of such action. A special meeting of shareholders is likely
to be held during April of 1999 to vote upon this proposal. If approved by the
shareholders and completed, this transaction would not have any impact on the
general operations or business of the Company. However, it would give the
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Company more flexibility with regard to its corporate and capital structure,
reduce the tax costs of certain transactions and increase the Company's ability
to make acquisitions. If approved, the Company and its wholly owned subsidiary,
Denbury Management will merge after the move of corporate domicile, leaving
Denbury Resources Inc., the Delaware corporation, as the surviving entity. A
detailed description of the transaction can be found in Form S-4 Registration
Statement No. 333-69577 filed with the Securities and Exchange Commission
("SEC") and available over the Internet at the SEC's web site at
http://www.sec.gov. However, if management determines that such change of
domicile will result in a significant amount of tax being paid by the Company or
its shareholders, which is not expected, then such proposal may be delayed or
abandoned.
Recent Events
LOW OIL PRICES. Between 1997 and 1998, the Company's net oil product
prices decreased 40% ($6.96 per Bbl) and its natural gas product prices declined
by 14% ($0.37 per Mcf). This drop in oil and natural gas prices has caused the
Company's cash flow and results of operations to drop substantially during 1998
and has contributed to an increase in our debt levels during the year.
Furthermore, at these oil price levels, most of the Company's oil development
and exploration projects are uneconomical. Thus starting in mid-1998, the
Company significantly curtailed its development expenditures and shifted its
focus to potential acquisition opportunities. However, if oil prices do recover
to a more normalized level, the Company has built a significant inventory of oil
development projects that will then be economic, subject to the availability of
capital.
FULL COST POOL WRITEDOWNS. As a result of the low oil prices, at June 30,
1998 the Company had a $165 million non-cash writedown of its full cost pool.
This writedown was computed based on a NYMEX oil price of $14.00 per barrel. As
of December 31, 1998, oil prices had deteriorated further to a NYMEX price of
approximately $12.00 per Bbl and an average net realized price of $7.37 per Bbl,
a drop of $7.06 in the average net realized price since December 31, 1997. As a
result of this decrease in product prices, along with some downward revisions in
the Company's proven reserves, the Company incurred an additional writedown of
$115 million at December 31, 1998, or a total writedown for the year of $280
million.
BASIS OF PRESENTATION. As of December 31, 1998, the current net present
value (using the year-end oil and natural gas prices) of the Company's reserves
are insufficient to repay the senior bank loan, the 9% Senior Subordinated Notes
due 2008 and the related interest costs, which casts doubt upon the ability of
the Company to continue operations in the foreseeable future and to be able to
realize assets and satisfy liabilities in the normal course of business. The
Company's ability to continue as a going concern is dependent upon the
completion of the sale of stock to the Texas Pacific Group ("TPG") discussed
below (also see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Proposed $100 Million Sale of Shares to TPG") or an
increase in oil and natural gas prices. If this proposed sale of stock does not
close or oil and natural gas prices do not increase to enable the repayment of
the debt and interest costs, the Company will be in default of its bank credit
agreement and may not be able to service its debt. If the Company were unable to
continue as a going concern, then significant adjustments would be necessary to
the Company's financial statements to properly reflect a need to liquidate
assets in order to repay debt, to reflect all debt as current and other
potential adjustments due to the changes in operations.
PROPOSED SALE OF STOCK TO TPG. The Company believes the low price
environment makes this a good time to pursue acquisitions. However, without
additional capital, the Company's high debt levels make it difficult for the
Company to make any meaningful acquisitions. During the last quarter of 1998,
the Company began to seek out additional sources of capital and in December,
1998, the Company negotiated a stock purchase by its largest shareholder, TPG,
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of 18,552,876 common shares of the Company at $5.39 per share for an aggregate
consideration of $100 million. The consummation of this stock sale is
conditioned upon the approval of the sale by the shareholders of the Company,
completion of an amendment to the Company's bank agreement, the absence of a
material adverse change, as that term is defined in the agreement, plus
satisfaction of other conditions. The Company completed an amendment to its bank
credit facility as of February 19, 1999 and is seeking shareholder approval of
the sale of stock to TPG at a special meeting of the shareholders currently
expected to be held in April, 1999. If this sale of stock is consummated, TPG
will gain control of the Company with ownership that will increase from
approximately 32% to approximately 60%.
AMENDMENT TO CREDIT FACILITY. On February 19, 1999, the Company completed
an amendment to its credit facility with Bank of America, as agent for a group
of eight other banks, thereby meeting one of the required conditions for the
sale of stock to TPG. This amendment sets the borrowing base at $110 million, of
which $60 million was considered by the banks to be within their normal credit
guidelines. The amendment:
o provides relief on certain debt covenants;
o changes the facility to one that is fully secured;
o sets restrictions on the use of funds;
o increases the interest rate; and
o provides that a failure to close the TPG stock sale before
June 16, 1999 would be an event of default.
All of these recent events, plus other 1998 activities, are more fully
described in Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
Business Strategy
As part of its corporate strategy, the Company believes in the following
fundamental principles:
o Remain focused in specific regions;
o Acquire properties where the Company believes additional value
can be created through a combination of exploitation, develop-
ment, exploration and marketing;
o Acquire properties that give the Company a majority working
interest and operational control or where the Company believes
they can ultimately obtain it;
o Maximize the value of the Company's properties by increasing
production and reserves while reducing costs; and
o Maintain a highly competitive team of experienced and incenti-
vized personnel.
Acquisitions of Oil and Gas Properties
Acquisitions have historically been an integral part of the Company's
strategy and are expected to become even more important during 1999 due to the
low price environment. As part this strategy, the Company strives to acquire
properties where it believes significant additional value can be created. Such
properties are typically characterized by: (i) long production histories; (ii)
complex geological formations with multiple producing horizons and substantial
exploitation potential; (iii) a history of limited operational focus and capital
investment, often due to their relatively small size and limited strategic
importance to the previous owner; and (iv) the potential for the Company to gain
control of operations. Due to the low price environment and its affect on debt
levels, cash flow, and personnel levels, the Company believes that this is an
excellent time to pursue acquisitions. Although it is primarily interested in
acquiring good properties at good prices, if possible, the Company tries 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 attempts to improve its profitability by consolidating its
ownership in core properties over which it can exercise operational control and
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<PAGE>
focus technical expertise. Consequently, the Company may purchase small working
interest positions, primarily through negotiated transactions, and sell or trade
its non-core assets. The consolidation of ownership allows the Company to: (i)
enhance the effectiveness of its technical staff by concentrating on relatively
few wells; (ii) increase production while adding virtually no additional
personnel; and (iii) increase ownership in a property so that the potential
benefits of value enhancement activities justify the allocation of its
resources.
Prior to the December 1997 acquisition of Heidelberg Field, the Company's
oil and gas reserves were obtained almost equally from acquisitions and
development activities. Generally speaking, the Company has emphasized drilling
when commodity prices are relatively high and focused on acquisitions when
commodity prices are low. From 1993, when the Company focused its attention
exclusively in the United States, through December 31, 1995, the Company spent a
total of $43.4 million on acquisitions. Since then, the Company has made two key
acquisitions, the first in May 1996. At that time, the Company acquired
properties in its core areas of Mississippi and Louisiana from Amerada Hess
Corporation for approximately $37.2 million. In December 1997, the Company
acquired oil properties in the Heidelberg Field from Chevron U.S.A., Inc. for
approximately $202 million.
1996 HESS ACQUISITION. During May and June, 1996, the first two months of
ownership, the properties acquired from Amerada Hess produced approximately
2,945 BOE per day and as of June 30, 1996, had proved reserves of approximately
5.9 MMBOE. After acquiring the properties, the Company did extensive development
and exploitation on these properties and as a result, increased the production
230% to a peak of 9,731 BOE per day during the second quarter of 1998 and
increased the reserves 141% to 14.2 MMBOE as of December 31, 1997. This
acquisition has been profitable even though production has peaked and oil prices
have dropped during 1998 to one of the lowest levels in recent history.
Production for the third and fourth quarters of 1998 averaged approximately
7,600 and 5,730 BOE per day, respectively. These production declines primarily
occurred because of production decreases on the horizontal oil wells drilled
late in 1997 and early 1998 and the lack of drilling and other development
activity on these properties during the latter half of 1998 due to the low oil
prices.
There are additional potential development projects on these properties,
plus some exploration potential, once oil prices recover to a more normalized
level. During 1998, the Company shot a 92 square mile 3-D shoot over Eucutta
Field, the largest property in this acquisition, which has highlighted some
additional exploration potential. The Company plans further drilling during 1999
based on data from this 3-D survey, although the plans may be modified,
depending on the oil prices at the time. As of December 31, 1998, the proved
reserves on an SEC basis had dropped to 6.0 MMBOE, primarily due to the effect
of low oil prices.
1997 CHEVRON ACQUISITION. The Heidelberg Field in Jasper County,
Mississippi, acquired in the Chevron acquisition is located approximately nine
miles from the Eucutta Field, the property with the highest estimated future net
cash flow from proved reserves discounted at an annual discount rate of 10% in
accordance with the guidelines of the SEC ("PV10 Value") of those acquired in
the Hess acquisition. The Company has an average working interest of 91% and an
average net revenue interest of 77% in this field, the majority of which was
acquired from Chevron and the remainder of which was acquired through $19.3
million of other incremental acquisitions in this field. The estimated proved
reserves as of January 1, 1998 for the Chevron Acquisition properties were
approximately 27.6 MMBOE, with average net daily production of approximately
2,900 BOE per day for the fourth quarter of 1997. Due to the low oil price
throughout 1998, the Company has not developed this field as quickly as it
originally planned. During the year, the Company did drill 17 wells, of which 10
were horizontal wells, significantly less than in the original plan to drill 11
vertical wells and 32 horizontal wells. During the second half of the year, the
development activity virtually ceased, except for the continued development of
facilities for the waterfloods currently in process.
In spite of the scaled back development plan, production at this field
averaged approximately 4,200 and 4,250 BOE per day during the third and fourth
quarters of 1998, respectively, which is a 45% and 47% increase from the fourth
quarter of 1997. As of December 31, 1998, the proved reserves on an SEC basis
had dropped to 19.9 MMBOE, primarily due to the effect of a $6.92 per barrel
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verage field price being received and used to price reserves in the Company's
year-end reserve report.
OIL AND GAS OPERATIONS
Denbury operates in two core areas, Louisiana and Mississippi. Its eight
largest fields constitute approximately 88% and 78%, respectively, of its total
proved reserves on a BOE and PV10 Value basis. Within these eight fields the
Company owns an average 91% working interest and operate 95% of the wells which
comprise 65% of our PV10 Value. These eight largest fields are located in three
adjacent counties in Mississippi and one parish in Louisiana. The 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 in Houma, Louisiana and Laurel, Mississippi.
<TABLE>
<CAPTION>
1998
Proved Reserves as of December 31, 1998 (1) Average Production (2)
-------------------------------------------------- ----------------------
Gross Average Net
Oil Natural Gas PV10 Value PV10 Value Oil Natural Gas Productive Revenue
(MBbls) (MMcf) (000's) % of Total (Bbls/d) (Mcf/d) Wells (2) Interest(2)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Louisiana
Lirette.......... 168 18,751 $ 20,633 17.9% 149 9,100 14 58.3%
Bayou Rambio..... 36 5,005 6,722 5.8% 19 4,435 5 55.6%
Gibson........... 72 4,669 5,957 5.2% 156 4,188 2 53.2%
South Chauvin.... 98 5,062 5,152 4.5% 67 3,152 4 65.4%
Other Louisiana.. 221 5,743 9,272 8.1% 895 13,169 51 46.4%
-------- ---------- ---------- ---------- ------- --------- ---------- ---------
Total Louisiaiana 595 39,230 47,736 41.5% 1,286 34,044 76 50.4%
-------- ---------- ---------- ---------- ------- --------- ---------- ---------
Mississippi
Heidelberg....... 19,502 2,256 36,777 32.0% 3,681 493 156 77.1%
Eucutta.......... 3,926 - 9,987 8.7% 5,097 129 56 77.4%
Quitman.......... 1,154 - 2,841 2.5% 1,222 - 22 76.8%
Davis............ 1,024 - 1,860 1.6% 789 - 24 90.3%
Other Mississippi 1,868 6,325 13,687 11.8% 1,456 1,493 96 52.3%
-------- ---------- ---------- ---------- ------- --------- ----------- ---------
Total Mississippi 27,474 8,581 65,152 56.6% 12,245 2,115 354 71.3%
-------- ---------- ---------- ---------- ------- --------- ----------- ---------
Other............... 181 992 2,131 1.9% 72 446 - -
-------- ---------- ---------- ---------- ------- --------- ----------- ---------
Company Total....... 28,250 48,803 $ 115,019 100.0% 13,603 36,605 430 67.6%
======== ========== ========== ========== ======= ========= ========== =========
<FN>
(1) The reserves were prepared using constant prices and costs in
accordance with the guidelines of the SEC based on the prices
received on a field-by-field basis as of December 31, 1998.
The oil price at that date was a NYMEX price of $12.00 per Bbl
adjusted by field and a NYMEX natural gas price average of $2.15
per MMBtu also adjusted by field.
(2) Includes only productive wells in which the Company has a working
interest as of December 31, 1998.
</FN>
</TABLE>
Mississippi
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.
During 1997 and early 1998, the Company increased its emphasis in
horizontal drilling based on its apparent success. The Company drilled its first
horizontal well in 1995 at the South Thompson Creek Field in Mississippi and
drilled a subsequent horizontal well in this field during 1996. Both of these
wells were completed as producers. Although horizontal wells typically decline
rapidly from their initial production rates, they typically have a higher
internal rate of return than a comparable vertical well, reduce operating costs
per BOE and reduce the number of wells required to drain the reservoir.
Through December 31, 1998, the Company has drilled a total of 37
horizontal wells at an average cost of $1.0 million as compared to an average
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cost of $1.6 million per well on the first two South Thompson Creek wells. The
initial average production rate during the first month of production on these
wells was 400 Bbls/d. Even though the Company has had continued success with its
horizontal drilling, during the second half of 1998 the Company stopped drilling
these wells due to the low oil prices. The Company hopes to commence drilling
additional horizontal wells, particularly at Heidelberg Field, as soon as oil
prices return to a more normalized level.
Southern Louisiana
The Company's southern Louisiana producing fields are typically large
structural features containing multiple sandstone reservoirs. Current production
depths range from 7,000 feet to 16,000 feet with potential throughout the area
for even deeper production. The region produces predominantly natural gas, with
most reservoirs producing with a water-drive mechanism.
The majority of the Company's southern Louisiana fields lie in the Houma
embayment area of Terrebonne and LaFourche Parishes. The area is characterized
by complex geological structures which have produced prolific reserves, typical
of the lower Gulf Coast geosyncline. Use of the 3-D seismic has become a
valuable tool in exploration and development throughout the onshore Gulf Coast
and has been pivotal in discovering significant reserves. The Company currently
owns or has license to work on over 345 square miles of 3-D seismic data and
plans to continue to expand its data ownership.
During 1995, the Company acquired approximately 75 square miles of 3-D
seismic data over five of its existing fields in Southern Louisiana, namely
Bayou Rambio, De Large, North Deep Lake, Gibson and Humphreys. During 1996, the
Company entered into a joint venture agreement with two industry partners and
shot approximately 158 square miles of 3-D seismic data in the Terrebonne Parish
area, which includes three of its existing fields, Lirette, Lapeyrouse and North
Lapeyrouse. The Company's existing productive zones are excluded from the joint
venture. Denbury owns a one-third interest in any new prospects discovered
through this joint venture that currently owns rights to over 35,000 acres
within the survey area. The 3-D seismic survey is complete and four wells have
been drilled to date based on the results of the survey with two dry holes and
two successful wells in the Lirette Field area. By the end of 1998, the Company
had identified 12 to 16 other drilling prospects from this survey. The Company's
participation in these wells during 1999 will depend on the availability of
capital and participation of the other working interest owners.
Proved Oil and Gas Reserves
The Company's reserves at December 31, 1998, 1997 and 1996 were estimated
by Netherland, Sewell & Associates, Inc., an independent Dallas-based
engineering firm. The reserves were prepared using constant prices and costs in
accordance with the guidelines of the Securities and Exchange Commission
("SEC"), based on the prices received on a field-by-field basis as of December
31 of each year. The reserves do not include any value for probable or possible
reserves which may exist, nor do they include any value for undeveloped acreage.
The reserve estimates represent the Company's net revenue interest in its
properties.
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<PAGE>
<TABLE>
<CAPTION>
As of December 31,
-------------------------------------------
1998 1997 1996
------------- ------------ ------------
<S> <C> <C> <C>
Estimated proved reserves:
Oil (MBbls)................................................ 28,250 52,108 15,052
Natural Gas (MMcf)......................................... 48,803 77,191 74,102
Oil Equivalent (MBOE)...................................... 36,383 64,883 27,403
Percentage of MBOE:
Proved producing........................................... 39% 40% 45%
Proved non-producing....................................... 38% 26% 39%
Proved undeveloped......................................... 23% 34% 16%
Representative oil and gas prices: (1)
NYMEX .....................................................$ 12.00 $ 18.32 $ 25.92
NYMEX Henry Hub............................................ 2.15 2.58 3.90
Present Values:
Discounted estimated future net cash flow before
income taxes (PV10 Value) (thousands) (2)..............$ 115,019 $ 361,329 $ 316,098
Standardized measure of discounted estimated future net cash
flow after net income taxes (thousands)................$ 115,019 $ 335,308 $ 241,872
<FN>
(1) The oil prices as of each respective year-end were based on NYMEX prices
per barrel and NYMEX Henry Hub prices per MMBtu, with these representative
prices adjusted by field to arrive at the appropriate corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance
with the guidelines of the SEC, discounted at 10% per annum.
See also Note 12. "Supplemental Reserve Information" of the Consolidated
Financial Statements for disclosure of other reserve data and such information
is incorporated herein by reference.
</FN>
</TABLE>
Oil and Gas Acreage
The following table sets forth Denbury's acreage position at December 31,
1998:
<TABLE>
<CAPTION>
Developed Undeveloped
----------------------------------- ---------------------------------
Gross Net Gross Net
--------------- --------------- --------------- -------------
<S> <C> <C> <C> <C>
Louisiana.............. 22,301 14,260 22,969 8,282
Mississippi............ 20,547 15,580 28,434 15,038
--------------- --------------- --------------- -------------
Total...... 42,848 29,840 51,403 23,320
=============== =============== =============== =============
</TABLE>
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<PAGE>
Productive Wells
This table sets forth both the gross and net productive wells of the
Company at December 31, 1998:
<TABLE>
<CAPTION>
Producing Oil Producing Gas
Wells Wells Total
--------------------------- --------------------------- --------------------------
Gross Net Gross Net Gross Net
----------- ---------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Louisiana.......... 15 9.0 61 29.4 76 38.4
Mississippi........ 332 243.4 22 9.0 354 252.4
----------- ---------- ----------- ----------- ----------- ----------
Total....... 347 252.4 83 38.4 430 290.8
=========== ========== =========== =========== =========== ==========
</TABLE>
Drilling Activity
The following table sets forth the results of drilling activities during
each of the three fiscal years in the period ended December 31, 1998.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------
1998 1997 1996
------------------- ------------------ -------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells: (1)
Productive (2)........................ - - 2 0.7 - -
Nonproductive (3)..................... 1 0.4 7 2.3 1 1.0
Development Wells: (1)
Productive (2)........................ 33 26.7 33 22.5 9 7.9
Nonproductive (3)..................... 1 0.8 2 0.8 - -
-------- -------- -------- -------- -------- --------
Total........................... 35 27.9 44 26.3 10 8.9
======== ======== ======== ======== ======== ========
<FN>
(1) An exploratory well is a well drilled either in search of a new, as-yet
undiscovered oil or gas reservoir or to greatly extend the known limits
of a previously discovered reservoir. A developmental well is a well
drilled within the presently proved productive area of an oil or gas
reservoir, as indicated by reasonable interpretation of available data,
with the objective of completing in that reservoir.
(2) A productive well is an exploratory or development well found to be
capable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas well.
(3) A nonproductive well is an exploratory or development well that is not a
producing well.
</FN>
</TABLE>
There were also six water injection wells drilled during 1998 and one
well was in the process of being drilled at December 31, 1998.
Title to Properties
Customarily in the oil and gas industry, only a perfunctory title
examination is conducted at the time properties believed to be suitable for
drilling operations are first acquired. Prior to commencement of drilling
operations, a thorough drill site title examination is normally conducted, and
curative work is performed with respect to significant defects. During
acquisitions, title reviews are performed on all properties; however, formal
title opinions are obtained on only the higher value properties. The Company
believes that it has good title to its oil and natural gas properties, some of
which are subject to minor encumbrances, easements and restrictions.
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Production
The following tables summarize sales volume, sales price and production
cost information for the Company's net oil and gas production for each year of
the three-year period ended December 31, 1998. "Net" production is production
that is owned by the Company and produced for its interest after deducting
royalties and other similar interests.
Year Ended December 31,
--------------------------------------
1998 1997 1996
----------- ---------- ----------
Net production volume
Crude oil - (Mbbls)................. 4,965 2,884 1,500
Natural gas - (Mmcf)................ 13,361 13,257 8,933
Equivalent - MBOE (1)............... 7,192 5,094 2,989
Average sales price
Crude oil - ($/Bbl)................. $ 10.29 $ 17.25 $ 18.98
Natural gas - ($/Mcf)............... 2.31 2.68 2.73
Per equivalent BOE (1).............. 11.38 16.75 17.69
Average production cost
Per equivalent BOE (1)............... $ 4.05 $ 4.36 $ 4.51
(1) Based on a 6 Mcf to 1 Bbl gas to oil conversion ratio.
Significant Oil and Gas Purchasers
Oil and gas sales are made on a day-to-day basis under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon the Company. For the year
ended December 31, 1998, the Company sold 10% or more of its net production of
oil and gas to the following purchasers: Hunt Refining (34%), Natural Gas
Clearinghouse (17%) and Genesis Crude Oil (11%).
Geographic Segments
All Canadian oil and gas properties were disposed of in 1993 and thus,
all of the Company's operations are now in the United States.
Competition
The oil and 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.
Price Volatility
The revenues generated by the Company are highly dependent upon the
prices of oil and natural gas. The marketing of oil and natural gas is affected
by numerous factors beyond the control of the Company. These factors include
crude oil imports, the availability of adequate pipeline and other
transportation facilities, the marketing of competitive fuels, and other factors
affecting the availability of a ready market, such as fluctuating supply and
demand.
-9-
<PAGE>
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.
Oil Marketing
Denbury markets its oil to a variety of purchasers, most of which are
large, established companies. The oil is generally sold under a short-term
contract with the sales price based on an applicable posted price, plus a
negotiated premium. This price is determined on a well-by-well basis and the
purchaser generally takes delivery at the wellhead. Mississippi oil, which
accounted for approximately 90% of the Company's oil production in 1998, 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.
In the fourth quarter of 1998, the Company entered into new contracts on
virtually all of its Mississippi oil production. These new contracts, which are
generally for a period of twelve to twenty-four months, changed the price
methodology on which the contracts are based and provides for protection to the
Company against any further widening of the gap between the local posted price
and NYMEX. Certain of the contracts also implemented a price floor of between
$8.00 and $10.00 per Bbl which equates to a NYMEX oil price of between $15.00
and $16.00 per Bbl. As compensation for the price floors, the contracts provide
that the premiums received on the posted prices decrease as oil prices rise. The
contracts with floor prices covered approximately 45% of the Company's oil
production, as of January 31, 1999. The Company may not be able to renew these
contracts in the future or may not be able to obtain terms as favorable as those
in the existing contracts.
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
During June and July, 1998, the Company entered into two no-cost
financial contracts ("collars") to hedge a total of 40 million cubic feet of
natural gas per day ("MMcf/d"). The first natural gas contract for 35 MMcf/d
covers the period from July 1998 to June 1999 and has a floor price of $1.90 per
million British Thermal Units ("MMBtu") and a ceiling price of $2.96 per MMBtu.
The second natural gas contract for five MMcf/d covers the period from September
1998 to August 1999 and has a floor price of $1.90 per MMBtu and a ceiling price
of $2.89 per MMBtu. During December, 1998, the Company extended these natural
gas hedges through December 2000 by entering into an additional no-cost collar
with a floor price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu for
the period of July 1999 through December 2000. This contract hedges 25 MMcf/d
for the months of July and August 1999 and 30 MMcf/d for each month thereafter.
The Company collected $175,200 on these financial contracts during 1998. These
three contracts cover over 100% of the Company's current net natural gas
production.
-10-
<PAGE>
Regulations
The availability of a ready market for oil and gas production depends
upon numerous factors beyond the Company's control. These factors include
regulation of natural gas and oil production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by well or proration unit, the amount of natural gas and oil
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
State and federal regulations generally are intended to prevent waste of natural
gas and oil, protect rights to produce natural gas and oil between owners in a
common reservoir, control the amount of natural gas and oil produced by
assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies. The following discussion summarizes the regulation of the
United States oil and gas industry and is not intended to constitute a complete
discussion of the various statutes, rules, regulations and governmental orders
to which the Company's operations may be subject.
Regulation of Natural Gas and Oil Exploration and Production
The Company's operations are subject to various types of regulation at
the federal, state and local levels. Such regulation includes requiring permits
for drilling wells, maintaining bonding requirements in order to drill or
operate wells and regulating the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used in
connection with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in and the unitization or pooling of oil and gas properties. In
addition, state conservation laws establish maximum rates of production from oil
and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and gas the Company can produce from its
wells and may limit the number of wells or the locations at which the Company
can drill. 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
-11-
<PAGE>
and storage, and to offer these services individually to their customers. By
requiring interstate pipelines to "unbundle" their services and to provide their
customers with direct access to pipeline capacity held by them, Order No. 636
has enabled pipeline customers to choose the levels of transportation and
storage service they require, as well as to purchase natural gas directly from
third-party merchants other than the pipelines and obtain transportation of such
gas on a non-discriminatory basis. The effect of Order No. 636 has been to
enable the Company to market its natural gas production to a wider variety of
potential purchasers. The Company believes that these changes generally have
improved the Company's access to transportation and have enhanced the
marketability of its natural gas production. To date, Order No. 636 has not had
any material adverse effect on the Company's ability to market and transport its
natural gas production. However, the Company cannot predict what new regulations
may be adopted by the FERC and other regulatory authorities, or what effect
subsequent regulations may have on the Company's activities. In addition, Order
No. 636 and a number of related orders were appealed. Recently, the United
States Court of Appeals for the District of Columbia Circuit issued an opinion
largely upholding the basic features and provision of Order No. 636. However,
even though Order No. 636 itself has been judicially approved, several related
FERC orders remain subject to pending appellate review and further changes could
occur as a result of court order or at the FERC's own initiative.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate natural gas
pipeline-owned gathering facilities to pipeline affiliates, (ii) the completion
of a rulemaking involving the regulation of interstate natural gas pipelines
with marketing affiliates under Order No. 497, (iii) FERC's on-going efforts to
promulgate standards for pipeline electronic bulletin boards and electronic data
exchange, (iv) a generic inquiry into the pricing of interstate pipeline
capacity, (v) efforts to refine FERC's regulations controlling the operation of
the secondary market for released interstate natural gas pipeline capacity, and
(vi) a policy statement regarding market-based rates and other non-cost-based
rates for interstate pipeline transmission and storage capacity. Several of
these initiatives are intended to enhance competition in natural gas markets.
While any resulting FERC action would affect the Company only indirectly, the
ongoing, or, in some instances, preliminary evolving nature of these regulatory
initiatives makes it impossible at this time to predict their ultimate impact
upon the Company's activities.
Oil Price Controls and Transportation Rates
Sales of crude oil, condensate and gas liquids by the Company are not
currently regulated and are made at market prices. Commencing in October 1993,
the FERC has modified its regulation of oil pipeline rates and services in order
to comply with the Energy Policy Act of 1992. That Act mandated the FERC to
streamline oil pipeline ratemaking by abandoning its old, cumbersome procedures
and issue new procedures to be effective January 1, 1995. In response, the FERC
issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing
system under which oil pipelines will be able to change their transportation
rates, subject to prescribed ceiling levels. The FERC's new oil pipeline
ratemaking methodology was recently affirmed by the Court. The Company is not
able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on
the transportation costs associated with oil production from the Company's oil
producing operations.
Gathering Regulations
Under the Natural Gas Act (the "NGA"), facilities used for and operations
involving the production and gathering of natural gas are exempt from FERC
-12-
<PAGE>
jurisdiction, while facilities used for and operations involving interstate
transmission are not. Under current law even facilities which otherwise would
have been classified as gathering may be subject to the FERC's rate and service
jurisdiction when owned by an interstate pipeline company and when such
regulation is necessary in order to effectuate FERC's Order No. 636 open-access
initiatives. FERC has reaffirmed that it does not have jurisdiction over natural
gas gathering facilities and services and that such facilities and services are
properly regulated by state authorities. As a result, natural gas gathering may
receive greater regulatory scrutiny by state agencies. In addition, the FERC has
approved several transfers by interstate pipelines of gathering facilities to
unregulated gathering companies, including affiliates. This could allow such
companies to compete more effectively with independent gatherers.
State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements. While some states provide for the rate regulation of pipelines
engaged in the intrastate transportation of natural gas, such regulation has not
generally been applied against gatherers of natural gas. Natural gas gathering
may receive greater regulatory scrutiny following the pipeline industry
restructuring under Order No. 636. Thus the Company's gathering operations could
be adversely affected should they be subject in the future to the application of
state or federal regulation of rates and services.
Environmental Regulations
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Public interest in the protection of the
environment has increased dramatically in recent years. The trend of more
expansive and stricter environmental legislation and regulations could continue.
To the extent laws are enacted or other governmental action is taken that
restricts drilling or imposes environmental protection requirements that result
in increased costs to the oil and gas industry in general, the business and
prospects of the Company could be adversely affected.
The EPA and various state agencies have limited the approved methods of
disposal for certain hazardous and nonhazardous wastes. Certain wastes generated
by the Company's oil and natural gas operations that are currently exempt from
treatment as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Most of
these properties have been operated by prior owners, operators and third parties
whose treatment and disposal or release of hydrocarbons or other wastes was not
under the Company's control. These properties and the wastes disposed thereon
may be subject to Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), Federal Resource Conservation and Recovery Act and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Certain provisions of CAA may result in
the gradual imposition of certain pollution control requirements with respect to
air emissions from the operations of the Company. The EPA and states have been
developing regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several years for air
pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues.
However, the Company does not believe its operations will be materially
adversely affected by any such requirements.
-13-
<PAGE>
Federal regulations require certain owners or operators of facilities
that store or otherwise handle oil, such as the Company, to prepare and
implement spill prevention, control, countermeasure and response plans relating
to the possible discharge of oil into surface waters. The Oil Pollution Act of
1990 ("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from a spill, including but not
limited to, the costs of responding to a release of oil to surface waters.
Regulations are currently being developed under the OPA and state laws
concerning oil pollution prevention and other matters that may impose additional
regulatory burdens on the Company.
The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as nonhazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or modifications of this exemption by administrative, legislative or judicial
process, or through changes in applicable state statutes, would increase the
volume of hazardous waste to be managed and disposed of by the Company.
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Any such change in the applicable statues may
require the Company to make additional capital expenditures or incur increased
operating expenses.
Some states have enacted statutes governing the handling, treatment,
storage and disposal of naturally occurring radioactive material ("NORM"). NORM
is present in varying concentrations in subsurface and hydrocarbon reservoirs
around the world and may be concentrated in scale, film and sludge in equipment
that comes in contact with crude oil and natural gas production and processing
streams. Mississippi legislation prohibits the transfer of property for
residential or other unrestricted use if the property contains NORM above
prescribed levels.
The Company also is subject to a variety of federal, state, and local
permitting and registration requirements relating to 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 5 "Income Taxes" of the Consolidated Financial Statements
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<PAGE>
for additional tax disclosures and such information is incorporated herein by
reference.
Item 2. Properties
- -------------------
See Item 1. Business - "Oil and Gas Operations." The Company also has
various operating leases for rental of office space, office equipment, and
vehicles. See Note 8 "Commitments and Contingencies" of the Consolidated
Financial Statements for the future minimum rental payments and such information
is incorporated herein by reference.
Item 3. Legal Proceedings
- --------------------------
In June of 1997, a well blow-out occurred at the Lake Chicot Field, for
which the Company is operator, in St. Martin Parish, Louisiana in which four
individuals that were employees of third party entities were killed, none of
whom were employees or contractors of the Company. In connection with this
blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al.v. Mallard
Bay Drilling L.L.C., Parker Drilling Company and Denbury Management, Inc., Case
No. 58226-G in the 16th Judicial District court in St. Martin Parish, Louisiana
alleging various defective and dangerous conditions, violation of certain rules
and regulations and acts of negligence. The Company believes that all litigation
relating to this matter to which it is a party is covered by insurance and none
of such legal proceedings can be reasonable expected to have a material adverse
effect on the Company's financial condition, results of operations, or cash
flows.
There are no other potentially 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.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted for a vote of security holders during the
fourth quarter of 1998.
PART II
Item 5. Market for the Common Stock and Related Matters
- --------------------------------------------------------
Information as to the markets in which the Company's Common Stock is
traded, the quarterly high and low prices for such stock, the dividends declared
with respect to the Common Stock during the last two years, and the approximate
number of stockholders of record at February 1, 1999, is set forth under "Common
Stock Trading Summary" in the Consolidated Financial Statements." Information as
to restrictions on the payment of dividends with respect to the Company's Common
Stock is set forth in Note 6 "Shareholders' Equity" of the Consolidated
Financial Statements. Such information is incorporated herein by reference. The
closing price of the Company's stock on The New York Stock Exchange and The
Toronto Stock Exchange on February 24, 1999 was $3.94 and Cdn. $5.50,
respectively.
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<PAGE>
Item 6. Selected Financial Data
- --------------------------------
The following table sets forth five years of selected financial data:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------
Amounts in thousands unless noted 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Data:
- ---------------
Production (daily)
Oil (Bbls)...................................... 13,603 7,902 4,099 1,995 1,340
Gas (Mcf)....................................... 36,605 36,319 24,406 13,271 9,113
BOE (6:1)....................................... 19,704 13,955 8,167 4,207 2,858
Revenue (net of royalties)
Oil sales....................................... $ 51,080 $ 49,748 $ 28,475 $ 10,852 $ 6,767
Gas sales....................................... 30,803 35,585 24,405 9,180 5,925
- ----------------------------------------------------------------------------------------------------------------------
Total...................................... $ 81,883 $ 85,333 $ 52,880 $ 20,032 $ 12,692
- ----------------------------------------------------------------------------------------------------------------------
Unit sales price
Oil (per Bbl)................................... $ 10.29 $ 17.25 $ 18.98 $ 14.90 $ 13.84
Gas (per Mcf)................................... 2.31 2.68 2.73 1.90 1.78
Net income (loss).................................... $(287,145) $ 14,903 $ 8,744 $ 714 $ 116
Income (loss) per share:
Basic........................................... $ (11.08) $ 0.74 $ 0.67 $ 0.10 $ 0.19
Fully diluted................................... (11.08) 0.70 0.62 0.10 0.19
Average common shares outstanding.................... 25,926 20,224 13,104 6,870 6,240
Cash Flow Data:
- ---------------
Cash flow from operations (1)........................ $ 30,096 $ 56,607 $ 34,140 $ 9,394 $ 6,185
Cash flow used for investing activities ............. 103,797 307,559 88,374 29,084 17,025
Cash flow provided by financing activities........... 76,235 241,115 60,089 28,172 9,108
Balance Sheet Data:
- -------------------
Total assets......................................... $ 212,859 $ 447,548 $ 166,505 $ 77,641 $ 48,964
Long-term liabilities................................ 226,436 256,637 7,481 5,077 17,768
Shareholders' equity (deficit) and
preferred stock................................ (32,265) 160,223 142,504 68,501 25,962
Per BOE data (6:1)
- ------------------
Revenue......................................... $ 11.38 $ 16.75 $ 17.69 $ 13.05 $ 12.17
Production expenses............................. (4.05) (4.36) (4.51) (4.42) (4.13)
- ----------------------------------------------------------------------------------------------------------------------
Production netback.............................. 7.33 12.39 13.18 8.63 8.04
General and administrative expenses............. (1.02) (1.30) (1.50) (1.25) (1.12)
Interest expenses............................... (2.13) 0.02 (0.26) (1.26) (0.99)
- ----------------------------------------------------------------------------------------------------------------------
Cash flow (1) $ 4.18 $ 11.11 $ 11.42 $ 6.12 $ 5.93
- ----------------------------------------------------------------------------------------------------------------------
<FN>
(1) Exclusive of the net change in non-cash working capital balances.
</FN>
</TABLE>
-16-
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
-----------------------------------------------------------------------
of Operations
-------------
Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. Denbury's primary strategy is to acquire
properties which it believes have significant upside potential and increases the
value of these properties through the efficient development, enhancement and
operation of those properties. Denbury's corporate headquarters is in Dallas,
Texas and it has two primary field offices in Houma, Louisiana and Laurel,
Mississippi.
OVERVIEW. The Company's current financial condition and 1998 operating
results have been defined by the deep and rapid fall in oil prices during 1998.
This price decline has significantly reduced the Company's cash flow and results
of operations and increased the Company's debt levels. While oil prices are at
one of the lowest levels in recent history, as a multiple of cash flow the
Company's debt is at an historic high. In response to these rapid changes,
during the second half of 1998 the Company eliminated its horizontal drilling
program and exploration expenditures and significantly reduced its overall
expenditure level. This reduction in expenditures included its planned
development program of the Heidelberg Field acquired from Chevron in December
1997 as low prices made the drilling of new oil wells uneconomical. Starting in
June of 1998, the Company entered into financial collars to hedge its gas
production, and in the fourth quarter of 1998 renegotiated its Mississippi oil
sales contracts. Furthermore, the Company reached an agreement to sell $100
million of stock to the Texas Pacific Group ("TPG"), its largest shareholder,
which is expected to close in April 1999, subject to shareholder approval. Funds
made available by this sale should enable the Company to make favorable
acquisitions in an environment in which capital resources are limited.
1998 Activity
CHEVRON HEIDELBERG FIELD ACQUISITION. In late December 1997, the Company
acquired oil properties in the Heidelberg Field, Jasper County, Mississippi,
from Chevron for approximately $202 million, the largest acquisition by the
Company to date. To fund the acquisition, the Company amended and restated its
bank credit facility and at the same time increased the facility size from $150
million to $300 million. As of December 31, 1997, the Company owed $240 million
on this facility with a borrowing base of $260 million.
FEBRUARY 1998 PUBLIC DEBT AND EQUITY OFFERING. To obtain permanent
financing for the Chevron acquisition, the Company made a public debt and equity
offering which closed in late February. The Company sold 5,240,780 common shares
at a price of $16.75 per share ($15.955 per share net to the Company) to the
public and concurrently sold the Texas Pacific Group ("TPG"), the Company's
largest shareholder, 313,400 common shares. The net proceeds to the Company from
the equity offering and TPG purchase were approximately $88.6 million, before
offering expenses.
At the same time, the Company sold $125 million in aggregate principal
amount of 9% Senior Subordinated Notes Due 2008, which were issued by its wholly
owned subsidiary, Denbury Management, Inc. These notes contain typical debt
covenants, including covenants that limit (i) indebtedness, (ii) certain
payments including dividends, (iii) sale/leaseback transactions, (iv)
transactions with affiliates, (v) liens, (vi) asset sales, and (vii) mergers and
consolidations. The net proceeds to the Company from the debt offering were
approximately $121.8 million, before offering expenses.
The total net proceeds from the debt and equity offerings were
approximately $209.5 million after deducting total offering expenses of
$900,000. These proceeds were used to reduce the amount borrowed under the
Company's bank credit facility, leaving an outstanding balance of $40 million as
of the end of February, after an additional $9.5 million was borrowed during the
first two months of 1998. Simultaneously, the Company's bank borrowing base was
reduced to $165 million, leaving $125 million available on the line.
-17-
<PAGE>
FIRST QUARTER CEILING TEST. Oil prices were on a steady decline throughout
most of 1998. The oil prices used in the December 31, 1997 reserve report were
based on a NYMEX price of $18.32 per barrel of oil ("Bbl"). By March 31, 1998,
the comparable price was $15.61.
Line graph showing three respective oil price postings from January 1996 through
December 1998 by month:
Jan-96 Feb-96 Mar-96 Apr-96 May-96 Jun-96 Jul-96 Aug-96
NYMEX 18.70 18.78 21.18 23.29 21.09 20.43 21.25 21.91
KOCH WTI 17.35 17.21 19.59 21.77 19.52 18.84 19.74 20.37
EOTT MS LT SR 14.82 14.70 17.09 19.27 17.02 16.33 17.20 17.85
Sep-96 Oct-96 Nov-96 Dec-96 Jan-97 Feb-97 Mar-97 Apr-97 May-97 Jun-97
23.93 24.89 23.55 25.12 25.18 22.17 20.97 19.73 20.87 19.22
22.25 22.85 21.99 23.39 23.48 20.47 19.08 18.11 18.98 17.18
19.75 20.84 19.49 20.89 20.98 17.97 16.08 15.03 15.96 14.17
Jul-97 Aug-97 Sep-97 Oct-97 Nov-97 Dec-97 Jan-98 Feb-98 Mar-98 Apr-98
19.66 19.95 19.78 21.28 20.22 18.32 16.73 16.08 15.05 15.47
17.52 17.76 17.63 19.17 17.99 16.18 14.56 13.88 12.76 13.13
14.52 14.76 14.63 16.17 14.99 13.17 11.55 10.71 9.44 9.63
May-98 Jun-98 Jul-98 Aug-98 Sep-98 Oct-98 Nov-98 Dec-98
14.93 13.67 14.08 13.38 14.98 14.46 12.96 11.24
12.52 11.06 11.51 10.88 12.39 11.87 10.34 8.60
9.02 7.53 8.00 7.38 8.89 8.37 6.84 5.10
Under full cost accounting rules, each quarter the Company is required to
perform a ceiling test calculation. Although the Canadian accounting approach is
slightly different, the Securities and Exchange Commission ("SEC") requires that
the full cost pool carrying values do not exceed a company's future net revenues
from its proved reserves discounted at 10% per annum using constant current
product prices. The Company excluded the Heidelberg Field from the full cost
ceiling test as of March 31, 1998 as it believed that, based on its success with
similar properties in Mississippi, the value of this property was at least equal
to its carrying cost. As of March 31, 1998, inclusion of the Heidelberg Field in
the ceiling test would have resulted in a $35 million writedown.
SECOND QUARTER. During the second quarter of 1998, oil prices continued to
decline, with a drop of approximately $1.50 in the NYMEX oil price from March 31
to June 30, 1998. Furthermore, the gap between the NYMEX oil price and the net
realized price widened, causing the net realized price at Heidelberg Field to
drop approximately $1.00 per Bbl more than the decline in the NYMEX price. In
response to the decline in oil prices, the Company announced in June 1998 that
it was curtailing the horizontal drilling program on its oil properties and
would generally focus on projects that could impact future years, such as
expenditures on facilities, waterflood units, and a few higher potential
projects. This included the postponement of 22 of 32 originally scheduled
horizontal wells at Heidelberg Field. However, by June 30, 1998, the Company had
already spent a total of $76.3 million on capital expenditures, of which $13.2
million related to acquisitions. The exploration and development expenditures
included approximately $38.0 million spent on drilling, $14.1 million spent on
geological, geophysical and acreage expenditures and $11.0 million spent on
workover costs.
WRITEDOWN AT JUNE 30, 1998. This curtailment in activity included the
recently acquired Heidelberg Field. As a result of this curtailment, it was
unlikely that the proved reserves and production from this property would
increase as quickly as originally anticipated, thus causing a decline in the
current value of this property. Therefore, as of June 30, 1998, the Company
included the Heidelberg Field in the full cost pool for its ceiling test, which
coupled with the reduction in oil prices, resulted in a $165 million writedown
of the full cost pool as of that date. This ceiling test was computed using June
30, 1998 prices, which were equivalent to a NYMEX oil price of $14.00 per Bbl
and an average net realized oil price of $8.90 per Bbl, a drop of approximately
$5.53 per Bbl from the net prices used in the December 31, 1997 reserve report.
PRODUCT PRICE HEDGES. In further response to the decline in oil prices and
to mitigate additional price-related negative effects on the Company's cash
flow, in June and July 1998, the Company entered into two no-cost financial
contracts ("collars") to hedge a total of 40 million cubic feet of natural gas
per day ("MMcf/d"). The first natural gas contract for 35 MMcf/d covers the
period from July 1998 to June 1999 and has a floor price of $1.90 per million
-18-
<PAGE>
British Thermal Units ("MMBtu") and a ceiling price of $2.96 per MMBtu. The
second natural gas contract for five MMcf/d covers the period from September
1998 to August 1999 and has a floor price of $1.90 per MMBtu and a ceiling price
of $2.89 per MMBtu. During December 1998, the Company extended these natural gas
hedges through December 2000 by entering into an additional no-cost collar with
a floor price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu for the
period of July 1999 through December 2000. This contract hedges 25 MMcf/d for
the months of July and August 1999 and 30 MMcf/d for each month thereafter. The
Company collected $175,200 on these financial contracts during 1998 and these
contracts cover over 100% of the Company's current net natural gas production.
For 1998, the Company's natural gas production made up 31% of the Company's
total production on a BOE basis. Based on the futures market prices at December
31, 1998, the Company would not receive or pay any amounts under these commodity
contracts even though they covered more than the Company's production because
prices at December 31, 1998 were within the contract collars.
Bar graph showing bank debt in millions of dollars as of the dates shown.
3/31/98 6/30/98 9/30/98 12/31/98
------- ------- ------- --------
Bank debt 40.0 70.0 90.0 100.0
The Company also reviewed its oil purchase contracts and in the fourth
quarter entered into new contracts on virtually all of its Mississippi oil
production. These new contracts, which are generally for a period of twelve to
twenty-four months, changed the price methodology on which the contracts are
based and provided for protection to the Company against any further widening of
the gap between the local posted price and NYMEX. Certain of the contracts also
implemented a price floor of between $8.00 and $10.00 per Bbl which equates to a
NYMEX oil price of between $15.00 and $16.00 per Bbl. As compensation for the
price floors, the contracts provide that the premiums received on the posted
prices decrease as oil prices rise. The contracts with floor prices covered
approximately 45% of the Company's oil production, as of January 31, 1999.
$35 MILLION REDUCTION OF BORROWING BASE AS OF OCTOBER 1. The Company's
borrowing base was also affected by the drop in price. The credit agreement
stipulates that the borrowing base will be reviewed every six months and a new
borrowing base set each April 1 and October 1. The banks made their semi-annual
review in September, based on the June 30, 1998 proved reserves and other
assets, and reduced the borrowing base from $165 million to $130 million with
the reduction almost entirely due to the lower product prices. This left the
Company with $40 million of borrowing capacity as of September 30.
Bar and line graph showing capital expenditures and cash flow from operations
in millions of dollars for each of the four quarters ended December 31, 1998.
3/31/98 6/30/98 9/30/98 12/31/98
------- ------- ------- --------
Capital expend. 26.4 49.8 17.4 9.0
Cash flow 11.5 9.1 6.8 2.8
CAPITAL EXPENDITURES - SECOND HALF OF 1998. During the third quarter of
1998, the Company reduced spending to a total of $17.4 million (compared to
$76.3 million during the first six months) and also shifted the focus from
Mississippi oil properties to Louisiana gas properties. Approximately 62% of the
third quarter capital expenditures were in Louisiana, as compared to
approximately 16% during the prior six months. However, the overall results of
the Louisiana development program were disappointing due to an unsuccessful
development well and faster than anticipated production declines on certain
other properties. With the continued low oil prices, reduced cash flow and
rising debt levels, during the latter part of the third quarter the Company took
additional steps to reduce its capital expenditures. For the fourth quarter,
expenditures dropped to $9.0 million, or $36.0 million on an annualized basis, a
level that more closely approximated available cash flow.
-19-
<PAGE>
In addition to its internal capital expenditure program, the Company has
historically required capital for acquisitions of producing properties, which
have been a major factor in the Company's growth during recent years. Because of
the downturn in the oil and gas industry during 1998 as a result of the
decreases in oil and natural gas prices, the Company believes that 1999 is an
excellent time to make attractive acquisitions. However without additional
capital, it is doubtful that the Company could make any meaningful acquisitions.
As of September 30, 1998, the Company had minimal working capital with $90
million of bank debt outstanding and $125 million outstanding on its 9% Senior
Subordinated Notes Due 2008. Although the Company had a bank borrowing base of
$130 million as determined by the banks in their October 1, 1998
redetermination, the Company expected this borrowing base to be reduced again at
the next scheduled redetermination on April 1, 1999.
PROPOSED $100 MILLION SALE OF SHARES TO TPG. During the last quarter of
1998, the Company began to seek out additional sources of capital and in
December 1998, the Company negotiated a stock purchase by its largest
shareholder, TPG of 18,552,876 common shares of the Company at $5.39 per share
for an aggregate consideration of $100 million. The consummation of this stock
sale is conditioned upon the approval of the sale by the shareholders of the
Company, completion of an amendment to the Company's bank agreement, the absence
of a material adverse change, as that term is defined in the agreement, plus
satisfaction of other conditions. The Company completed an amendment to its bank
credit facility as of February 19, 1999 (see "February 1999 Amendment to Bank
Credit Facility" below) and is seeking shareholder approval at a special meeting
of the shareholders currently expected to be held in April 1999. The Company
anticipates that all other conditions will be satisfied by the date of the
special shareholders meeting.
If this sale of stock is consummated, TPG will gain control of the Company
with ownership that will increase from approximately 32% to approximately 60%.
Although the Company does not expect this transaction to result in any immediate
changes to its directors, management or operations, TPG will have adequate
voting power to control the election of directors, to determine the corporate
and management policies of the Company and to effect the shareholder approval of
a merger, consolidation or sale of all or substantially all of the assets of the
Company.
The Company expects to close this stock sale in April 1999 and plans to
pursue acquisitions with funds made available under its credit facility as a
result of the sale. However, there can be no assurance that the stock sale will
close. In addition, there is no assurance that the Company will have enough
capital available to fund desired acquisitions, that funds will still be
available from the banks by the time the Company locates acceptable
acquisitions, or that suitable acquisitions can even be identified and
completed. If acquisitions are made, they may not be successful in achieving the
Company's desired profitability objectives. In the current price environment,
without suitable acquisitions or the capital to fund such acquisitions, the
Company's future growth could be limited or even eliminated.
ADDITIONAL WRITEDOWN AT DECEMBER 31, 1998. As of December 31, 1998, oil
prices had deteriorated further to a NYMEX price of approximately $12.00 per Bbl
and an average net realized price of $7.37 per Bbl, a drop of $7.06 in the
average net realized price since December 31, 1997. As a result of this decrease
in product prices, along with some downward revisions in the Company's proven
reserves (see "Results of Operations - Depreciation, Depletion and Site
Restoration") the current value (using the year-end oil and natural gas prices)
of the Company's reserves as of December 31, 1998 are not sufficient to repay
debt. Based on this reserve forecast and after considering the effects of
administrative and financing costs, under Canadian GAAP the full balance of oil
and gas properties would be written off. As it is expected by management that
the prices realized over the remaining life of the reserves will be higher than
the year-end prices, an average NYMEX oil price of $14.00 per Bbl (a price
slightly less than the 1998 average price) was used in determining the Canadian
GAAP ceiling test at year-end. Based on this $14.00 NYMEX price and using
undiscounted future net revenues after considering the effects of administrative
and interest costs, an additional writedown of $115 million was recognized for
the fourth quarter, or a total writedown for the year of $280 million. This
-20-
<PAGE>
writedown is the same as that required under U.S. GAAP using the year-end $12.00
NYMEX price and the net present value of the reserves without consideration of
administrative and interest costs. Although this writedown reduced the Company's
capital below the threshold required by the Company's banks, the bank amendment
(see "February 1999 Amendment to Bank Credit Facility") completed on February
19, 1999, modified this test such that the Company is now in compliance. These
charges are non-cash items and should not have any direct impact on the
Company's liquidity.
FEBRUARY 1999 AMENDMENT TO BANK CREDIT FACILITY. On February 19, 1999, the
Company completed an amendment to its credit facility with Bank of America, as
agent for a group of eight other banks, thereby meeting one of the required
conditions for the sale of stock to TPG. This amendment sets the borrowing base
at $110 million, of which $60 million was considered by the banks to be within
their normal credit guidelines. The credit facility continues with its other
restrictions such as a prohibition on the payment of dividends and a prohibition
on most debt, lien and corporate guarantees. This amendment:
o provided certain relief on the minimum equity and interest coverage
tests;
o changed the facility to one secured by substantially all of the
Company's oil and natural gas properties;
o requires that as long as the borrowing base is larger than a borrowing
base that conforms to normal credit guidelines (currently $60
million), that at least 75% of the funds borrowed subsequent to the
closing of the proposed TPG purchase must be used for either qualify-
ing acquisitions or capital expenditures made to maintain, enhance or
develop its proved reserves;
o increased the interest rate to a range from LIBOR plus 1.0% to LIBOR
plus 1.75% depending on the amounts outstanding and LIBOR plus 2.125%
if the outstanding debt exceeds the borrowing base under normal credit
guidelines, currently set at $60 million; and
o provided that a failure to close the TPG stock sale before June 16,
1999 would be an event of default.
The Company expects that approximately $10 million will be outstanding on
the facility after the proposed sale of stock to TPG, leaving a total borrowing
capacity of $100 million, an amount approximately equal to the anticipated
proceeds from the TPG stock sale. The next scheduled re-determination of the
borrowing base will be as of October 1, 1999, based on June 30, 1999 assets and
proven reserves. If prices remain low or deteriorate further, it is possible
that the banks could further reduce the borrowing base at that time. Although
the Company is not in default of any of its debt covenants at the present time
and has been afforded certain relief on the covenants as part of the amendment,
it is possible that a continued low oil price for an extended period of time
could cause the Company to violate its agreements in the future.
CAPITAL RESOURCES AND LIQUIDITY
As more fully described under "Results of Operations" below, between 1997
and 1998, the Company's average net oil product prices decreased 40% ($6.96 per
Bbl) and natural gas product prices declined by 14% ($0.37 per Mcf). Based on
the 1998 production levels, these reduced product prices caused 1998 oil revenue
to decrease by approximately $35 million over what it would have been using 1997
average prices and 1998 gas revenue to decrease by approximately $5 million
based on the same assumptions. Due to this drop in oil and natural gas prices,
the Company's cash flow and results of operations have been significantly
reduced during 1998. This reduction in cash flow has also contributed to an
increase in the Company's debt levels during the year. While oil prices are at
one of the lowest levels in recent history, as a multiple of cash flow the
Company's debt is at an historic high.
Because of the downturn in the oil and gas industry during 1998 as a result
of the decreases in oil and natural gas prices, the Company believes that 1999
is an excellent time to make attractive acquisitions. However without additional
-21-
<PAGE>
capital, it is doubtful that the Company could make any meaningful acquisitions.
In late 1998, the Company sought additional capital in order to have funds to
pursue acquisitions and entered into an agreement to sell $100 million of common
shares to TPG (see "Proposed $100 Million Sale of Shares to TPG" above).
As compared to 1998, the Company's 1999 development budget has been sharply
reduced in order to bring expenditures more in line with available cash flow.
Currently, the capital budget for 1999, excluding acquisitions, is between $20
million and $35 million, depending on the product prices at the time. The
drilling portion of the budget is the biggest variable, as it is not economical
to do development drilling on oil properties at the current price level.
However, should prices improve, the Company has built a significant inventory of
oil projects that it can commence, subject to the availability of capital.
Although the level of the Company's projected cash flow is highly variable
and difficult to predict as it is dependent on product prices, the success of
its drilling and other developmental work and other factors, the Company does
not expect its 1999 development spending to cause debt to increase
substantially. However, this reduced spending level will cause a corresponding
reduction in the previously anticipated production levels and related cash flow
and it is possible that the Company will not be able to maintain its current
production levels or replace its reserves with this reduced level of capital
expenditures. Although oil prices have fallen substantially during 1998, the
Company does not believe that oil prices will remain this low indefinitely. Any
increase in price would have a positive effect on both results of operations and
cash flow and the quantity and value of the Company's proved reserves.
As of December 31, 1998, the current net present value (using the year-end
oil and natural gas prices) of the Company's reserves are insufficient to repay
the senior bank loan, the 9% Senior Subordinated Notes due 2008 and the related
interest costs, which casts doubt upon the ability to continue operation in the
foreseeable future and to be able to realize assets and satisfy liabilities in
the normal course of business. The Company's ability to continue as a going
concern is dependent upon the completion of the sale of stock to TPG (see
"Proposed $100 Million Sale of Shares to TPG") or an increase in oil and natural
gas prices. If this proposed sale of stock does not close or oil and natural gas
prices do not increase to enable the repayment of the debt and interest costs,
the Company will be in default of its bank credit agreement and may not be able
to service its debt. If the Company were unable to continue as a going concern,
then significant adjustments would be necessary to the Company's financial
statements to properly reflect a need to liquidate assets in order to repay
debt, to reflect all debt as current and other potential adjustments due to the
changes in operations.
Sources and Uses of Funds
During 1998, the Company spent approximately $89.0 million on exploration
and development activities and approximately $13.7 million on acquisitions. The
exploration and development expenditures included approximately $53.0 million
spent on drilling, $17.8 million on geological, geophysical and acreage
expenditures and $18.2 million on workover costs. These expenditures were funded
by bank debt ($60.0 million), cash flow from operations ($20.3 million) and from
cash and other sources ($22.4 million). Of the total 1998 expenditures of $102.7
million, approximately 26% or $27 million of the development expenditures were
directed to long term projects such as production facilities and waterflood
units, plus undeveloped properties such as acreage and seismic. Expenditures on
these types of projects were not expected to benefit the Company until 1999 or
beyond.
Bar graph showing development and acquisition expenditures by year in millions
of dollars for the three years ended December 31, 1998
1996 1997 1998
---- ---- ----
Development 38.5 81.3 89.0
Acquisitions 48.4 224.1 13.7
---- ----- -----
Total 86.9 305.4 102.7
==== ===== =====
During 1997, the Company spent approximately $81.3 million on oil and
natural gas exploration and development activities and approximately $224.1
million on acquisitions, the majority of which related to the $202 million
acquisition from Chevron in December. The exploration and development
expenditures included approximately $55.9 million spent on drilling, $9.0
-22-
<PAGE>
million on geological, geophysical and acreage expenditures and the balance of
$16.4 million was spent on workover costs. These expenditures were funded by
available cash ($3.2 million), cash flow from operations ($62.3 million) and
bank debt ($239.9 million).
During 1996, the Company spent approximately $33.4 million on oil and
natural gas exploration and development expenditures, $37.2 million on the
acquisition of properties from Amerada Hess, $11.2 million on other oil and
natural gas acquisitions, and approximately $5.1 million on geological,
geophysical and acreage expenditures. The exploration and development
expenditures included $15.5 million spent on drilling and the balance of $17.9
million was spent on workover costs. These expenditures were funded during the
year by bank debt, available cash and cash flow from operations, although the
bank debt was retired with the proceeds from a public offering of common shares
in October 1996.
RESULTS OF OPERATIONS
Operating Income
While production volumes have increased substantially each year for the
past three years and were 41% higher on a BOE basis during 1998 as compared to
1997, operating income decreased slightly between 1997 and 1998 due to a 32%
decline in product prices (on a BOE basis), as outlined in the following chart.
<TABLE>
<CAPTION>
Year Ended December 31
- ------------------------------------------------------------------------------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Average daily production volume:
Bbls 13,603 7,902 4,099
Mcf 36,605 36,319 24,406
BOE 19,704 13,955 8,167
- ------------------------------------------------------------------------------------------------------
Unit prices
Oil price per Bbl $ 10.29 $ 17.25 $ 18.98
Gas price per Mcf 2.31 2.68 2.73
- ------------------------------------------------------------------------------------------------------
Netback per BOE
Sales price 11.38 16.75 17.69
Production expenses (4.05) (4.36) (4.51)
- -----------------------------------------------------------------------------------------------------
$ 7.33 $ 12.39 $ 13.18
- ------------------------------------------------------------------------------------------------------
Operating income (thousands)
Oil sales $ 51,080 $ 49,748 $ 28,475
Natural gas sales 30,803 35,585 24,405
Less production expenses (29,162) (22,218) (13,495)
- ------------------------------------------------------------------------------------------------------
Operating income $ 52,721 $ 63,115 $ 39,385
- ------------------------------------------------------------------------------------------------------
<FN>
(1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of
natural gas ("BOE").
</FN>
</TABLE>
-23-
<PAGE>
PRODUCTION. The production increases have been fueled by a combination of
internal growth and acquisitions. During the last three years, the Company has
made two key acquisitions, one for $37 million from Amerada Hess in May 1996 and
the latter for $202 million from Chevron in December 1997. The properties
acquired from Amerada Hess contributed an average of 2,017 BOE/d to 1996
production rates, 5,090 BOE/d in 1997 and 8,100 BOE/d in 1998. The initial
production rates on these properties was 2,945 BOE/d for the first two months of
ownership, with virtually all of the subsequent production increases coming from
internal development and exploitation of these properties. The production on
these Hess properties peaked in the second quarter of 1998 at 9,730 BOE/d.
During the third quarter of 1998, the average production on these properties
began to decline and for the fourth quarter averaged 5,730 BOE/d. The decrease
is primarily due to production declines on several horizontal oil wells drilled
at Eucutta Field in late 1997 and early 1998 and the lack of subsequent
development work to replace this production.
Bar graph showing average Company production for each of the quarters during the
three years ended December 31, 1998.
3/31/96 6/30/96 9/30/96 12/31/96 3/31/97 6/30/97 9/30/97
------- ------- ------- -------- ------- ------- -------
BOE/d 5,453 7,841 9,208 10,132 12,256 13,404 14,195
12/31/97 3/31/98 6/30/98 9/30/98 12/31/98
-------- ------- ------- ------- --------
BOE/d 15,922 21,441 21,927 19,402 16,108
The Company also increased production in 1998 from the Heidelberg Field,
acquired from Chevron in December 1997, the largest acquisition to date by the
Company. At the time of acquisition, this property was producing approximately
2,900 BOE/d. As a result of development work on this field, particularly during
the first six months of 1998, which included eight horizontal wells, production
for the year averaged 3,760 BOE/d and 4,250 BOE/d for the fourth quarter. During
the second half of 1998, due to low oil prices the Company postponed the
drilling of 14 other horizontal wells originally planned for 1998 and, unless
prices recover, is not expected to drill any horizontal wells at this field
during 1999. Because of this reduction in planned drilling expenditures, the
production is not expected to materially change at Heidelberg Field during 1999.
The Company has not halted its expenditures on the East Heidelberg waterflood
unit and other facilities, although these expenditures usually do not generate
immediate increases in production. The Company has begun to see some limited
production increases from the waterflood and expects a gradual increase in the
production response from the waterflood during 1999, although it is difficult to
predict the magnitude of such a response.
Although the Company's overall annual production rates for 1998 increased
substantially over the 1997 average, during the third and fourth quarter of 1998
the Company experienced declines in its production rates for the first time in
several years. This was due to (i) shutting in uneconomic wells, (ii) declines
on existing production, particularly the horizontal wells, and (iii) the
postponement of several oil development projects due to the low oil prices.
-24-
<PAGE>
Bar graph showing average oil prices received by the Company for each of the
three years ended December 31, 1998.
1996 1997 1998
---- ---- ----
Dollar per Bbl 18.98 17.25 10.29
REVENUE. Oil and natural gas revenue increased between 1996 and 1997 as a
result of the increase in production, although the production increase was
partially offset by a 5% decline in the average product prices (on a BOE basis).
However, between 1997 and 1998, even though production increased 41%, oil and
natural gas revenue actually dropped 32% due to a 40% drop ($6.96 per Bbl) in
the average oil prices and a 14% drop ($0.37 per Mcf) in the average natural gas
prices. Based on the 1998 production levels, these reduced product prices caused
1998 oil revenue to decrease by approximately $35 million over what it would
have been using 1997 average prices and 1998 gas revenue to decrease by
approximately $5 million based on the same assumptions.
Bar graph showing average gas prices received by the Company for each of the
three years ended December 31, 1998.
1996 1997 1998
---- ---- ----
Dollar per Mcf 2.73 2.68 2.31
OPERATING EXPENSES. The overall production and operating expenses increased
each year primarily due to an increase in the number of properties, principally
from the Hess and Chevron acquisitions. Even though the number of properties
increased, production increased at a faster pace allowing the Company to reduce
its production and operating expenses on a BOE basis by 3% between 1996 and 1997
and a further reduction of 7% between 1997 and 1998.
For the properties acquired in the Hess acquisition, the operating expenses
declined from the 1996 level of $5.35 per BOE to $4.56 per BOE for 1997 and were
further reduced to $3.39 for 1998. This reduction is largely attributable to the
Company's emphasis in 1997 and early 1998 on horizontal drilling on these
properties and the resulting increases in production. The Company was also able
to lower overall costs during the second half of 1998 by shutting in
uneconomical wells and through other general cost saving measures, although the
cost per BOE increased in the fourth quarter, when compared to the first nine
months, due to the decline in overall production rates. The Company has been
able to achieve these reductions in operating expenses per BOE even though the
Company's production has become even more weighted towards oil (which has higher
operating costs) with approximately 69% of the Company's 1998 production coming
from oil as compared to 57% during 1997 and 50% during 1996.
The operating expenses per BOE for the properties acquired in the Chevron
acquisition averaged $5.04 per BOE for 1998, a significant decline from the
average of approximately $6.38 per BOE when the properties were owned by
Chevron. This reduction was accomplished because of the increased production
levels and by general cost saving measures.
-25-
<PAGE>
General and Administrative Expenses
General and administrative ("G&A") expenses have increased as outlined
below along with the Company's growth.
<TABLE>
<CAPTION>
Year Ended December 31,
- ------------------------------------------------------------------------------------------------
1998 1997 1996
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net G&A Expenses (Thousands)
Gross expenses $ 18,962 $ 13,909 $ 8,407
State franchise taxes 785 428 213
Operator overhead charges (9,749) (5,502) (2,916)
Capitalized exploration expenses (2,657) (2,225) (1,224)
- ------------------------------------------------------------------------------------------------
Net expenses $ 7,341 $ 6,610 $ 4,480
- ------------------------------------------------------------------------------------------------
Average G&A cost per BOE $ 1.02 $ 1.30 $ 1.50
Employees as of December 31 205 157 122
- ------------------------------------------------------------------------------------------------
</TABLE>
On a BOE basis, G&A costs decreased 13% between 1996 and 1997 and declined
an additional 22% between 1997 and 1998. These savings were realized, in part
because of increased production on both an absolute and per well basis and also
from general cost saving measures, particularly during the second half of 1998.
Furthermore, the respective well operating agreements allow the Company, when it
is the operator, to charge a well with a specified overhead rate during the
drilling phase and to also charge a monthly fixed overhead rate for each
producing well. As a result of the increased drilling activity in 1997 and early
1998 and the addition of several producing wells acquired in the Chevron
acquisition in December 1997, the percentage of gross G&A recovered through
these types of allocations (listed in the above table as "Operator overhead
charges") increased when compared to prior periods. A total of 10 wells were
drilled during 1996, 44 during 1997 and 42 during 1998. During 1996,
approximately 35% of gross G&A was recovered by operator overhead charges, while
during 1997 this recovery increased to 40% and further increased to 51% during
1998. This significant increase in overhead recoveries is not expected to
continue in 1999 as a result of the curtailed drilling expenditures on oil
properties, thus reducing the amount of overhead recovered from drilling wells
which may result in a net increase in future G&A expenses.
Interest and Financing Expenses
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Unit Amounts 1998 1997 1996
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest expense $ 17,534 $ 1,111 $ 1,993
Non-cash interest expense (627) (91) (459)
- --------------------------------------------------------------------------------------------------
Cash interest expense 16,907 1,020 1,534
Interest and other income (1,623) (1,123) (769)
- --------------------------------------------------------------------------------------------------
Net interest expense (income) $ 15,284 $ (103) $ 765
- --------------------------------------------------------------------------------------------------
Average interest expense (income) per BOE $ 2.13 $ (0.02) $ 0.26
Average debt outstanding 205,087 12,700 19,500
Average interest rate 8.1% 6.9% 7.9%
- --------------------------------------------------------------------------------------------------
Imputed preferred dividend $ - $ - $ 1,281
Loss on early extinguishment of debt - - 440
- --------------------------------------------------------------------------------------------------
</TABLE>
-26-
<PAGE>
During the first half of 1996 and 1997, the Company had minimal debt
outstanding as virtually all of the bank debt had been retired during the fourth
quarters of 1995 and 1996. In 1995, the bank debt was repaid with proceeds from
the December 1995 private placement of equity with TPG and in 1996 with proceeds
from a public offering of common shares completed in October 1996. However, in
1996, the Company did incur debt late in the second quarter to fund property
acquisitions, the largest of which was the Hess acquisition, and during 1997,
the Company borrowed $202 million of its December 31, 1997 outstanding balance
of $240 million late in the fourth quarter to fund the Chevron acquisition.
The $240 million of bank debt remained outstanding for only two months. On
February 26, 1998 this bank debt was repaid with proceeds from a debt and equity
offering, leaving a bank balance of $40 million for the rest of the first
quarter of 1998, plus $125 million of public debt from the issuance of the 9%
Senior Subordinated Notes. This bank debt increased throughout the year, from
$40 million as of March 31, 1998 to $70 million as of June 30, to $90 million as
of September, to its balance of $100 million as of December 31, 1998. These
transactions resulted in substantially higher interest expense for 1998 as
compared to 1997, on both an absolute and BOE basis.
During 1996, the Company recognized $1.3 million of charges representing
the imputed preferred dividend until October 30, 1996 when the convertible
preferred was converted into 2.8 million common shares. During 1996, the Company
also had a $440,000 charge relating to a loss on early extinguishment of debt.
These costs related to the remaining unamortized debt issue costs of the
Company's prior credit facility which was replaced in May 1996.
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") has increased along with
the additional capitalized cost and increased production. DD&A per BOE,
excluding the writedown, has increased from $5.99 for 1996 to $6.42 for 1997 and
$7.26 for 1998, primarily as a result of the decline in oil price. The reduced
oil price causes wells to reach the end of their economic life much sooner and
also makes certain proved undeveloped locations uneconomical, both of which
reduce the reserve quantities. The oil prices used in the December 31, 1996
reserve report were based on a West Texas Intermediate price of $23.39 per Bbl,
with these representative prices adjusted by field to arrive at the appropriate
corporate net price in accordance with the rules of the Securities and Exchange
Commission. However, this price was reduced to $16.18 per Bbl at December 31,
1997 and further reduced to $9.50 as of December 31, 1998. The Company's average
net realized oil prices used in the December 31, 1996, 1997 and 1998 reserve
report were $21.73, $14.43 and $7.37, respectively. This reduction in the
reserves due to price amounted to approximately 1.6 million BOE between 1996 and
1997 and 15.1 million BOE between 1997 and 1998. The Company also lost
approximately 9.8 million BOE in 1998 which in part was also related to price,
in that the Company has postponed or canceled repairs and upgrades on oil wells
resulting in steeper declines. Also contributing to downward revisions in 1998
were poor performances on three of the Company's gas properties in Louisiana and
an unsuccessful development well also in Louisiana.
The loss in reserves due to price caused DD&A to increase approximately
$0.29 per BOE during 1997 and $0.89 per BOE for 1998. The DD&A rate was also
reduced in 1998 due to the reduction of depletable costs as a result of the $165
million writedown as of June 30, 1998. Under Canadian full cost accounting
rules, the Company is required to perform a ceiling test annually; however,
significant changes in estimates of reserves, prices, income taxes and other
important factors are considered on a quarterly basis. Under U.S. full cost
accounting rules, each quarter the Company is required to perform a ceiling test
calculation. See "Full Cost Ceiling Test" for a discussion of the writedowns
taken at June 30, 1998 and December 31, 1998.
-27-
<PAGE>
The Company also provides for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision is included in the DD&A expense and has
increased each year along with an increase in the number of properties owned by
the Company.
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Unit Amounts 1998 1997 1996
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Depletion and depreciation $ 51,815 $ 32,311 $ 17,533
Writedown of oil and gas properties 280,000 - -
Site restoration provision 419 408 371
- --------------------------------------------------------------------------------------------------------
Total amortization $ 332,234 $ 32,719 $ 17,904
- --------------------------------------------------------------------------------------------------------
Average DD&A cost per BOE $ 46.20 $ 6.42 $ 5.99
- --------------------------------------------------------------------------------------------------------
</TABLE>
Income Taxes
Due to a net operating loss of the U.S. subsidiary each year for tax
purposes, the Company does not have any current tax provision. The deferred
income tax provision as a percentage of net income varies slightly depending on
the mix of Canadian and U.S. expenses. The 1996 rate was the highest of the
three years as outlined below due to the non-deductible imputed preferred
dividend and interest on the subordinated debt during that year.
In addition, as a result of the previously discussed $280.0 million
writedown of its oil and natural gas properties and the resultant net pre-tax
loss of $302.8 million for the year ended December 31, 1998, an income tax
provision for 1998 using the effective tax rate of 37% would have resulted in a
$96.4 million deferred tax asset. Since the Company currently has a large tax
net operating loss, it was uncertain whether this total tax asset could
ultimately be realized, particularly in light of the low oil and natural gas
prices. As such, the Company fully impaired the deferred tax asset, resulting in
a 5% effective tax benefit rate for the year.
<TABLE>
<CAPTION>
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Deferred income tax (benefit) provision (thousands) $ (15,620) $ 8,895 $ 5,312
Average income tax costs (benefit) per BOE $ (2.17) $ 1.75 $ 1.78
Effective tax rate 5% 37% 38%
- -------------------------------------------------------------------------------------------------------
</TABLE>
Results of Operations
Bar graph showing cash flow from operations (excluding the change in working
capital items)for each of the three years ended December 31, 1998.
1996 1997 1998
---- ---- ----
Millions of Dollars 34.1 56.6 30.1
Between 1996 and 1997, the operating results showed strong improvement,
primarily due to the increases in production as previously discussed. However,
even though production was up during 1998 and most expenses, other than interest
expense, improved on a BOE basis, as a result of the decline in product prices,
net income and cash flow from operations decreased substantially on both a gross
and per share basis between 1997 and 1998 as outlined below. In addition, during
1998, the Company incurred a $280.0 million non-cash charge to operations to
writedown the carrying value of its oil and natural gas properties as previously
discussed.
-28-
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts 1998 1997 1998
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income (loss) $ (287,145) $ 14,903 $ 8,744
Net income (loss) per common share:
Basic $ (11.08) $ 0.74 $ 0.67
Fully diluted (11.08) 0.70 0.62
Cash flow from operations (1) $ 30,096 $ 56,607 $ 34,140
- -------------------------------------------------------------------------------------------------------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
The following table summarizes the cash flow, DD&A and results of
operations on a BOE basis for the comparative periods. Each of the individual
components are discussed above.
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Per BOE Data 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenue $ 11.38 $ 16.75 $ 17.69
Production expenses (4.05) (4.36) (4.51)
- ---------------------------------------------------------------------------------------------------------
Production netback 7.33 12.39 13.18
General and administrative (1.02) (1.30) (1.50)
Interest and other income (expense) (2.13) 0.02 (0.26)
- ---------------------------------------------------------------------------------------------------------
Cash flow from operations(a) 4.18 11.11 11.42
DD&A (7.26) (6.42) (5.99)
Deferred income taxes 2.17 (1.75) (1.78)
Writedown of oil and natural gas properties (38.93) - -
Other non-cash items (0.09) (0.01) (0.72)
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ (39.93) $ 2.93 $ 2.93
- ---------------------------------------------------------------------------------------------------------
<FN>
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
Market Risk Management
The Company uses fixed and variable rate debt to partially finance budgeted
expenditures. These agreements expose the Company to market risk related to
changes in interest rates. The Company does not hold or issue derivative
financial instruments for trading purposes.
The following table presents the carrying and fair value of the Company's
debt along with average interest rates. Fair values are calculated as the net
present value of the expected cash flows of the financial instrument.
<TABLE>
<CAPTION>
Expected Maturity Dates (in thousands) 1999-2001 2002 2003-2007 2008 Total Fair Value
- ---------------------------------------------------------------------------------------------------------------------------
Variable Rate Debt:
<S> <C> <C> <C> <C> <C> <C>
Bank Debt.......................... $ - $ 100,000 $ - $ - $ 100,000 $ 100,000
The average interest rate on the bank debt is 6.7%.
Fixed Rate Debt:
Subordinated Debt.................. - - - 125,000 125,000 110,000
The interest rate on the subordinated debt is a
fixed rate of 9%.
</TABLE>
-29-
<PAGE>
The Company also entered into various financial contracts to hedge its
exposure to commodity price risk associated with anticipated future gas
production. These contracts consist of price ceilings and floors (no-cost
collars). These contracts in effect at December 31, 1998 run through December
2000. Gain or loss on these derivative commodity contracts would be offset by a
corresponding gain or loss on the hedged commodity positions. Based on future
market prices at December 31, 1998, the Company would not receive or pay any
amounts under these commodity contracts. If futures market prices were to
increase 10% from those in effect at December 31, 1998, the Company would be
required to make cash payments under the commodity contracts of approximately
$120,000. If futures market prices were to decline 10% from those in effect as
December 31, 1998, the Company would receive cash payments under the commodity
contacts of approximately $1.5 million.
Year 2000 Issues
Year 2000 issues relate to the ability of computer programs or equipment to
accurately calculate, store or use dates after December 31, 1999. These dates
can be handled or interpreted in a number of different ways, but the most common
error is for the system to contain a two digit year which may cause the system
to interpret the year 2000 as 1900. Errors of this type can result in system
failures, miscalculations and the disruption of operations, including, among
other things, a temporary inability to process transactions, send invoices or
engage in similar normal business. In response to the Year 2000 issues, the
Company has developed a strategic plan divided into the following phases:
inventory, product compliance based on vendor representations and in-house
testing, third party integration and development of a contingency plan.
All of the Company's processing needs are handled by third party systems,
none of which have been substantially modified and all of which have been
purchased within the last few years. Therefore, the Company's initial review of
its in-house systems with regard to Year 2000 issues required an inventory of
its systems and a review of the vendor representations. The Company has
completed this initial review of its information systems. The licensor of the
Company's core financial software system has certified that such software is
Year 2000 compliant. Additionally, most other less critical software systems,
various types of equipment and non-information technology have been reviewed,
and based on vendor representations, are either compliant, will be compliant
with the next forthcoming software release or are systems that are not date
specific.
The Company's non-information technology consists primarily of various oil
and gas exploration and production equipment. The initial review has established
that the primary non-information technology systems functions are either not
date sensitive or are Year 2000 compliant based on vendor representations, and
are therefore predicted to operate in customary manners when faced with Year
2000 issues. However, the Company has determined that in the event such systems
are unable to address the Year 2000, employees can manually perform most, if not
all, functions.
In anticipation of Year 2000 issues, the Company is also evaluating the
Year 2000 readiness status of its third party service suppliers. In addition to
reviewing Year 2000 readiness statements issued by the third parties handling
the Company's processing needs, to date the Company has received, and is relying
upon, Year 2000 readiness reports periodically issued by its financial services
and electrical service providers, vendors and purchasers of the Company's oil
and natural gas products. The Company is continuing to review Year 2000
readiness of third party service suppliers and, based on their representations,
does not currently foresee material disruptions in the Company's business as a
result of Year 2000 issues. Unanticipated prolonged losses of certain services,
such as electrical power, could cause material disruptions for which no
economically feasible contingency plan has been developed.
The Company is continuing to conduct in-house testing of the core systems
and non-information technology, and to date either all systems tested have
adequately addressed possible Year 2000 scenarios or the Company has a plan in
place to remedy the deficiency. The Company expects testing to be completed
during the second quarter of 1999. After the completion of its Year 2000 review
and testing, the Company will further develop a contingency plan as required,
including replacing or upgrading by December 31, 1999 any system incapable of
addressing the Year 2000. This final step is expected to be completed during the
third quarter of 1999.
-30-
<PAGE>
Although the effects of Year 2000 issues cannot be predicted with
certainty, the Company believes that the potential impact, if any, of such
events will, at most, require employees to manually complete otherwise automated
tasks or calculations, other than those which might occur in a "worst case"
scenario as described below, which the Company does not anticipate will occur.
After considering Year 2000 effects on in-house operations, the Company
does not expect that any additional training would be required to perform these
tasks on a manual basis due to the level of experience of its personnel and the
routine nature of the tasks being performed. If, based on the results of its
in-house testing, the Company should determine that certain systems are not Year
2000 compliant and it appears as though the system is not likely to be compliant
within a reasonable time period, the Company will either elect to perform the
task manually or will attempt to purchase a different system for that particular
task and convert before December 31, 1999. The Company does not believe that
either option would impact the Company's ability to continue exploration,
drilling, production or sales activities, although the tasks may require
additional time and personnel to complete the same function or may require
incremental time and personnel during 1999 for a conversion to a new system.
The Company's core business consists primarily of oil and gas acquisition,
development and exploration activities. The equipment which is deemed "mission
critical" to the Company's activities requires external power sources such as
electricity supplied by third parties. Although the Company maintains limited
on-site secondary power sources such as generators, it is not economically
feasible to maintain secondary power supplies for any major component of its
"mission critical" equipment. Therefore, the most reasonably likely worst case
Year 2000 scenario for the Company would involve a disruption of third party
supplied electrical power, which would result in a substantial decrease in the
Company's oil production. Such event could result in a business interruption
that could materially affect the Company's operations, liquidity or capital
resources.
The Company has initiated the third party integration phase and will
continue to have formal communications with its significant suppliers, business
partners and key customers to determine the extent to which the Company is
vulnerable to either the third parties' or its own failure to correct their Year
2000 issues. The Company has been communicating with such third parties to keep
them informed of the Company's internal assessment of its Year 2000 review and
plans. This portion of the review and discussions with third parties is expected
to be completed during the second quarter of 1999. To date, approximately
one-half of these third parties have provided certain favorable representations
as to their Year 2000 readiness and received similar representations from the
Company. There can be no guarantee that the systems of other companies on which
the Company relies will be timely converted or that the conversion will be
compatible with the Company's systems. However, after reviewing and estimating
the effects of such events, the Company's contingency plan involves identifying
and arranging for other vendors, purchasers and third party contractors to
provide such services, if necessary, in order to maintain its normal operations.
The Company has, and will continue to, utilize both internal and external
resources to complete tasks and perform testing necessary to address the Year
2000 issue. The Company has not incurred, and does not anticipate that it will
incur, any significant costs relating to the assessment and remediation of Year
2000 issues.
-31-
<PAGE>
Forward-Looking Information
The statements contained in this Annual Report on Form 10-K that are not
historical facts, including, but not limited to, statements found in this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, are forward-looking statements, as that term is defined in Section
21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward-looking statements may be or may
concern, among other things, capital expenditures, drilling activity,
acquisition plans and proposals and dispositions, development activities, cost
savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon
prices, liquidity, Year 2000 issues, regulatory matters and competition. Such
forward-looking statements generally are accompanied by words such as "plan,"
"estimate," "expect," "predict," "anticipate," "projected," "should," "assume,"
"believe" or other words that convey the uncertainty of future events or
outcomes. Such forward-looking information is based upon management's current
plans, expectations, estimates and assumptions and is subject to a number of
risks and uncertainties that could significantly affect current plans,
anticipated actions, the timing of such actions and the Company's financial
condition and results of operations. As a consequence, actual results may differ
materially from expectations, estimates or assumptions expressed in or implied
by any forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital, general economic conditions,
competition and government regulations, as well as the risks and uncertainties
discussed in this annual report, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in the
Company's other public reports, filings and public statements.
In assessing Year 2000 issues, the Company has relied on certain
representations of third parties and has attempted to predict and address all
possible scenarios which could arise. However, uncertainties exist which could
cause Year 2000 effects to be more significant than the Company anticipates.
Such uncertainties include the success of the Company in identifying systems and
programs that are not Year 2000 compliant, the nature and amount of programming
required to up-grade or replace each of the affected programs, the availability,
rate and magnitude of related labor and consulting costs and the success of the
Company's vendors in addressing the Year 2000 issue.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
- -------------------------------------------------------------------
The information required by Item 7A is set forth under "Market Risk
Management" in Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Data
- ---------------------------------------------------
The information required by Item 8 is set forth in the Independent
Auditors' Report and Consolidated Financial Statements included herein following
the signature page hereof.
-32-
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
- -----------------------------------------------------------------------
Financial Disclosure
--------------------
None
Part III
Item 10. Directors and Executive Officers of the Company
- --------------------------------------------------------
Directors of the Company
Information as to the names, ages, positions and offices with Denbury,
terms of office, periods of service, business experience during the past five
years and certain other directorships held by each director or person nominated
to become a director of Denbury will be set forth in the "Election of Directors"
segment of the Proxy Statement for the Annual Meeting of Shareholders to be held
May 19, 1999, ("Annual Meeting") and is incorporated herein by reference.
Executive Officers of the Company
Information concerning the executive officers of Denbury will be set forth
in the "Management" section of the Proxy Statement for the Annual Meeting and is
incorporated herein by reference.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 and the rules
thereunder require the Company's executive officers and directors, and persons
who beneficially own more than ten percent (10%) of a registered class of the
Company's equity securities, to file reports of ownership and changes in
ownership with the Securities and Exchange Commission and exchanges and to
furnish the Company with copies. Based solely on its review of the copies of
such forms received by it, or written representations from such persons, the
Company is not aware of any person who failed to file any reports required by
Section 16(a) to be filed for fiscal 1998.
Item 11. Executive Compensation
- -------------------------------
Information concerning remuneration received by Denbury's executive
officers and directors will be presented under the caption "Statement of
Executive Compensation" in the Proxy Statement for the Annual Meeting and is
incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- -----------------------------------------------------------------------
Information as to the number of shares of Denbury's equity securities
beneficially owned as of March 15, 1999, by each of its directors and nominees
for director, its five most highly compensated executive officers and its
directors and executive officers as a group will be presented under the caption
"Security Ownership of Certain Beneficial Owners and Management" in the Proxy
Statement for the Annual Meeting and is incorporated herein by reference.
-33-
<PAGE>
Item 13. Certain Relationships and Related Transactions.
- --------------------------------------------------------
Information on related transactions will be presented under the caption
"Compensation Committee Interlocks and Insider Participation" and "Interests of
Insiders in Material Transactions" in the Proxy Statement for the Annual Meeting
and is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- ------------------------------------------------------------------------
(a) FINANCIAL STATEMENTS AND SCHEDULES. Financial statements and schedules
filed as a part of this report are listed in the Index to Financial
Statements appearing herein following the signature page.
EXHIBITS. The following exhibits are filed as a part of this report.
Exhibit No. Exhibit
----------- -------
3(a) Articles of Continuance of the Company, as
amended (incorporated by reference as Exhibits
3(a), 3(b), 3(c), 3(d) of the Registrant's
Registration Statement on Form F-1 dated
August 25, 1995, Exhibit 4(e) of the
Registrant's Registration Statement on Form
S-8 dated February 2, 1996 and Exhibit 3(a) of
the Pre-effective Amendment No. 2 of the
Registrant's Registration Statement on Form
S-1 dated October 22, 1996).
3(b) General By-Law No. 1: A By-Law Relating
Generally to the Conduct of the Affairs of the
Company, as amended (incorporated by reference
as Exhibit 3(e) of the Registrant's
Registration Statement on Form F-1 dated
August 25, 1995 and Exhibit 4(d) of the
Registrant's Registration Statement on Form S-
8 dated February 2, 1996).
3(c) Restated Articles of Incorporation of Denbury
Management, Inc. (incorporated by reference as
Exhibit 3(c) of Registrant's Registration
Statement on Form S-3 dated February 19, 1998)
3(d) Bylaws of Denbury Management, Inc.
(incorporated by reference as Exhibit 3(d) of
Registrant's Registration Statement on Form
S-3 dated February 19, 1998)
4(a) See Exhibits 3(a), 3(b), 3(c), and 3(d) for
provisions of the Articles of Continuance and
General By-Law No. 1 of the Company defining
the rights of the holders of Common Shares.
4(b) Form of Indenture between Denbury Management
and Chase Bank of Texas, National Association,
as trustee (incorporated by reference as
Exhibit 4(b) of Registrant's Registration
Statement on Form S-3 dated February 19, 1998)
10(a) Common Share Purchase Warrant representing
right of Internationale Nederlanden (U.S.)
Capital Corporation to purchase 150,000 Common
Shares of Newscope Resources Ltd.(incorporated
by reference as Exhibit 10(c) of the
Registrant's Registration Statement on Form
F-1 dated August 25, 1995).
10(b) Denbury Resources Inc. Stock Option Plan
(incorporated by reference as Exhibit 4(f) of
the Registrant's Registration Statement on
Form S-8 dated February 2, 1996).
10(c) Denbury Resources Inc. Stock Purchase Plan
(incorporated by reference as Exhibit 4(g) of
the Registrant's Registratio Statement on
Form S-8 dated February 2, 1996).
-34-
<PAGE>
Exhibit No. Exhibit
----------- -------
10(d) Form of indemnification agreement between
Newscope Resources Ltd. and its officers and
directors (incorporated by reference as
Exhibit 10(h) of the Registrant's Form 10-K
for the year ended December 31, 1995).
10(e) Securities Purchase Agreement and exhibits
between Newscope Resources Ltd. and TPG
Partners, L.P. as of November 13, 1995
(incorporated by reference as Exhibit 10(i) of
the Registrant's Form 10-K for the year ended
December 31, 1995).
10(f) First Amendment to the November 13, 1995
Securities Purchase Agreement between Newscope
Resources Ltd. and TPG Partners, L.P. as of
December 21, 1995 (incorporated by reference
as Exhibit 10(j) of the Registrant's Form 10-K
for the year ended December 31, 1995).
10(g) Stock Purchase Agreement between TPG Partners,
L.P. and Denbury Resources Inc. dated as of
October 2, 1996 (incorporated by reference as
Exhibit 10(k) of the Post-effective Amendment
No. 2 of the Registrant's Registration
Statement on Form S-1 dated October 22, 1996).
10(h) Form of First Restated Credit Agreement, by
and among Denbury Management, as borrower,
Denbury Resources Inc. as guarantor,
NationsBank of Texas, N.A., as administrative
agent, Nationsbanc Montgomery Securities LLC,
as syndication agent and arranger and the
financial institutions listed on Schedule I
thereto, as banks, executed on December 29,
1997 (incorporated by reference as Exhibit
10(a) of the Registrant's Registration
Statement on Form S-3 dated February 19,
1998).
10(i) First Amendment to First Restated Credit
Agreement, by and among Denbury Management, as
borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A. as
administrative agent, and NationsBank of
Texas, N.A. as bank, entered into as of
January 27, 1998 (incorporated by reference as
Exhibit 10(b) of the Registrant's Registration
Statement on Form S-3 dated February 19,
1998).
10(j) Second Amendment to First Restated Credit
Agreement, by and among Denbury Management, as
borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A., as
administrative agent, and NationsBank of
Texas, N.A., as bank, entered into as of
February 25, 1998 (incorporated by reference
as Exhibit 10(l) of the Registrant's Form 10-K
for the year ended December 31, 1997).
10(k) Third Amendment to First Restated Credit
Agreement, by and among Denbury Management, as
borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A., as
administrative agent and NationsBank of
Texas, N.A., as bank, entered into as of
August 10, 1998 (incorporated by reference as
Exhibit 10 of the Registrant's Form 10-Q for
the quarter ended June 30, 1998).
-35-
<PAGE>
Exhibit No. Exhibit
- ----------- -------
10(l) Consent letter and form of Fourth Amendment to
First Restated Credit Agreement, by and among
Denbury Management, as borrower, Denbury
Resources Inc., as guarantor, NationsBank of
Texas, N.A. as bank, dated November 30, 1998
(incorporated by reference as Exhibit 10(b) to
the Registrant's Form S-3 dated January 19,
1999).
10(m)* Fourth Amendment to First Restated Credit
Agreement, by and among Denbury Management, as
borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A., as
administrative agent, and NationsBank of
Texas, N.A., as bank, entered into as of
February 19, 1999.
10(n) Stock Purchase Agreement and Amendment to
Registration Rights Agreement between TPG
Partners, L.P. and Denbury Resources, Inc.
dated as of January 20, 1998 (incorporated by
reference as Exhibit 10(m) of the Registrant's
Form 10-K for the year ended December 31,
1997).
10(o) Stock Purchase Agreement between TPG Partners
II, L.L.C. and the Company dated as of
December 16, 1998 (incorporated by reference
as Exhibit 99.1 of the Registrant's Form 8-K
dated December 17, 1998).
11* Statement re-computation of per share
earnings.
12* Statement of Ratio of Earnings to Fixed
Charges.
21 List of Subsidiaries of Denbury Resources Inc.
(incorporated by reference as Exhibit 21 of
the Registrants Form 10-K for the year ended
December 31, 1997).
23* Consent of Deloitte & Touche LLP
27* Financial Data Schedule.
* Filed herewith.
(b) Form 8-Ks filed during the fourth quarter of 1998.
On December 2, 1998, the Company announced that it had reached an agreement
in principle with its largest shareholder, the Texas Pacific Group ("TPG")
to issue to an affiliate of TPG $100 million of common shares of the
Company at $5.39 per share, subject to certain conditions, including a
fairness opinion and shareholder approval.
On December 16, 1998, the Company and TPG Partners II, L.P. (the
"Purchaser"), entered into a Stock Purchase Agreement (the "Agreement")
pursuant to which the Purchaser agreed to purchase from the Company
18,552,876 of the Company's common shares, no par value, for $100 million.
-36-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Denbury Resources Inc. and Denbury Management, Inc. has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
DENBURY RESOURCES INC.
DENBURY MANAGEMENT, INC.
March 1, 1999 /s/ Phil Rykhoek
------------------------------------------------
Phil Rykhoek
Chief Financial Officer and Secretary
March 1, 1999 /s/ Bobby J. Bishop
------------------------------------------------
Bobby J. Bishop
Chief Accounting Officer and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of each
respective company and in the capacities and on the dates indicated.
March 1, 1999 /s/ Ronald G. Greene
------------------------------------------------
Ronald G. Greene
Chairman of the Board and Director
Denbury Resources Inc.
March 1, 1999 /s/ Gareth Roberts
------------------------------------------------
Gareth Roberts
Director, President and Chief Executive
Officer
(Principal Executive Officer)
Denbury Resources Inc.
March 1, 1999 /s/ Phil Rykhoek
------------------------------------------------
Phil Rykhoek
Chief Financial Officer and Secretary
(Principal Financial Officer)
Denbury Resources Inc.
-37-
<PAGE>
March 1, 1999 /s/ Bobby J. Bishop
------------------------------------------------
Bobby J. Bishop
Chief Accounting Officer and Controller
(Principal Accounting Officer)
Denbury Resources Inc.
March 1, 1999 /s/ Wilmot L. Matthews
------------------------------------------------
Wilmot L. Matthews
Director
Denbury Resources Inc.
March 1, 1999 /s/ Wieland F. Wettstein
------------------------------------------------
Wieland F. Wettstein
Director
Denbury Resources Inc.
March 1, 1999 /s/ Gareth Roberts
------------------------------------------------
Gareth Roberts
Director, President and Chief Executive
Officer
(Principal Executive Officer)
Denbury Management, Inc.
March 1, 1999 /s/ Phil Rykhoek
------------------------------------------------
Phil Rykhoek
Director, Chief Financial Officer and
Secretary
(Principal Financial Officer)
Denbury Management, Inc.
March 1, 1999 /s/ Bobby J. Bishop
------------------------------------------------
Bobby J. Bishop
Chief Accounting Officer and Controller
(Principal Accounting Officer)
Denbury Management, Inc.
March 1, 1999 /s/ Mark Worthey
------------------------------------------------
Mark Worthey
Director and Vice President, Operations
Denbury Management, Inc.
-38-
<PAGE>
DENBURY RESOURCES INC.
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
DECEMBER 31, 1998, 1997 AND 1996
FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
Page
----
Independent Auditors' Report F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Operations F-4
Consolidated Statements of Cash Flows F-5
Consolidated Statement of Changes in Shareholders'
Equity (Deficit) F-6
Notes to the Consolidated Financial Statements F-7 thru F-29
Schedule 1: Condensed Financial Information of Registrant F-30 thru F-36
FINANCIAL STATEMENTS AND SCHEDULES OMITTED
All other financial statement schedules are omitted because they are not
applicable or the required information is shown in the consolidated financial
statements or notes thereto.
F - 1
<PAGE>
Independent Auditors' Report
To the Shareholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc. as at
December 31, 1998 and 1997 and the consolidated statements of operations,
changes in shareholders' equity (deficit) and cash flows for each of the years
in the three year period ended December 31, 1998. 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, 1998
and 1997 and the results of its operations and the changes in shareholders'
equity (deficit) and cash flows for each of the years in the three year period
ended December 31, 1998, in accordance with accounting principles generally
accepted in Canada.
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
February 19, 1999
Note: See separate comments by auditors for U.S. Readers on Canada - U.S.
Reporting Difference on page F-29.
F - 2
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31,
------------------------------
1998 1997
------------- -------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents........................................... $ 2,049 $ 9,326
Accrued production receivable....................................... 5,495 8,692
Trade and other receivables......................................... 16,390 15,362
------------- -------------
Total current assets ..................................... 23,934 33,380
------------- -------------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties...................................... 508,571 388,766
Unevaluated oil and natural gas properties.......................... 65,645 82,798
Less accumulated depletion and depreciation......................... (393,552) (62,732)
------------- -------------
Net property and equipment................................... 180,664 408,832
------------- -------------
OTHER ASSETS........................................................... 8,261 5,336
------------- -------------
TOTAL ASSETS................................................ $ 212,859 $ 447,548
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities............................ $ 13,570 $ 24,616
Oil and gas production payable...................................... 5,118 6,052
Current portion of long-term debt .................................. - 20
------------- -------------
Total current liabilities................................... 18,688 30,688
------------- -------------
LONG-TERM LIABILITIES
Long-term debt...................................................... 225,000 240,000
Provision for site reclamation costs................................ 1,436 1,017
Deferred income taxes and other..................................... - 15,620
------------- -------------
Total long-term liabilities................................. 226,436 256,637
------------- -------------
FINANCING REQUIREMENTS (NOTE 1)
SHAREHOLDERS' EQUITY (DEFICIT)
Common shares, no par value, unlimited shares authorized;
outstanding - 26,801,680 and 20,388,683 shares at December
31, 1998 and December 31, 1997, respectively...................... 227,796 133,139
Retained earnings (accumulated deficit)............................. (260,061) 27,084
------------- -------------
Total shareholders' equity (deficit)........................ (32,265) 160,223
------------- -------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)........ $ 212,859 $ 447,548
============= =============
</TABLE>
Approved by the Board:
/s/ Gareth Roberts /s/ Wieland F. Wettstein
- ------------------ ------------------------
Gareth Roberts Wieland F. Wettstein
Director Director
See Notes to Consolidated Financial Statements.
F - 3
<PAGE>
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS (U.S. DOLLARS) 1998 1997 1996
------------- ---------- ----------
<S> <C> <C> <C>
REVENUES
Oil, natural gas and related product sales.................. $ 81,883 $ 85,333 $ 52,880
Interest income and other................................... 1,623 1,123 769
------------- ---------- ----------
Total revenues........................................ 83,506 86,456 53,649
------------- ---------- ----------
EXPENSES
Production.................................................. 29,162 22,218 13,495
General and administrative.................................. 6,556 6,182 4,267
Interest.................................................... 17,534 1,111 1,993
Imputed preferred dividends................................. - - 1,281
Loss on early extinguishment of debt........................ - - 440
Depletion and depreciation.................................. 52,234 32,719 17,904
Franchise taxes............................................. 785 428 213
Writedown of oil and natural gas properties................. 280,000 - -
------------- ---------- ----------
Total expenses....................................... 386,271 62,658 39,593
------------- ---------- ----------
Income (loss) before income taxes................................ (302,765) 23,798 14,056
Income tax benefit (provision)................................... 15,620 (8,895) (5,312)
------------- ---------- ----------
NET INCOME (LOSS)................................................ $ (287,145) $ 14,903 $ 8,744
============= ========== ==========
NET INCOME (LOSS) PER COMMON SHARE...............................
Basic....................................................... $ (11.08) $ 0.74 $ 0.67
Fully diluted............................................... $ (11.08) $ 0.70 $ 0.62
Average number of common shares outstanding...................... 25,926 20,224 13,104
============= ========== ==========
</TABLE>
See Notes to Consolidated Financial Statements
F - 4
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1998 1997 1996
------------ ----------- -----------
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss)........................................... $ (287,145) $ 14,903 $ 8,744
Adjustments needed to reconcile to net cash flow
provided by operations:
Depletion and depreciation.............................. 52,234 32,719 17,904
Writedown of oil and natural gas properties............. 280,000 - -
Deferred income taxes................................... (15,620) 8,895 5,312
Imputed preferred dividend.............................. - - 1,281
Loss on early extinguishment of debt.................... - - 440
Other................................................... 627 90 459
------------ ----------- -----------
30,096 56,607 34,140
Changes in working capital items relating to operations:
Accrued production receivable........................... 3,197 3,214 (8,694)
Trade and other receivables............................. (1,028) (11,719) (1,508)
Accounts payable and accrued liabilities................ (11,046) 13,713 6,711
Oil and gas production payable.......................... (934) 502 4,536
------------ ----------- -----------
NET CASH FLOW PROVIDED BY OPERATIONS........................... 20,285 62,317 35,185
------------ ----------- -----------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures........................ (88,978) (81,282) (38,450)
Acquisition of oil and natural gas properties........... (13,674) (224,145) (48,407)
Net purchases of other assets........................... (1,145) (2,132) (1,726)
Acquisition of subsidiary, net of cash acquired......... - - 209
------------ ----------- -----------
NET CASH USED FOR INVESTING ACTIVITIES......................... (103,797) (307,559) (88,374)
------------ ----------- -----------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments......................................... (200,000) - (47,900)
Bank borrowings......................................... 60,000 239,900 47,900
Issuance of subordinated debt........................... 125,000 - -
Issuance of common stock................................ 94,657 2,816 60,664
Costs of debt financing................................. (3,402) (1,511) (411)
Other................................................... (20) (90) (164)
------------ ----------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES...................... 76,235 241,115 60,089
------------ ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... (7,277) (4,127) 6,900
Cash and cash equivalents at beginning of year................. 9,326 13,453 6,553
------------ ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR....................... $ 2,049 $ 9,326 $ 13,453
============ =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for interest.................. $ 11,821 $ 447 $ 1,621
SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES:
Conversion of subordinated debt to common stock......... - - $ 3,314
Conversion of preferred stock to common stock........... - - 16,281
Assumption of liabilities in acquisition................ - - 1,321
</TABLE>
See Notes to Consolidated Financial Statements
F - 5
<PAGE>
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
<TABLE>
<CAPTION>
RETAINED
EARNINGS
COMMON SHARES (ACCUMULATED
(NO PAR VALUE) DEFICIT) TOTAL
--------------------------- ---------------- -------------
Dollar Amounts in Thousands of U.S. Dollars Shares Amounts
------------- -----------
<S> <C> <C> <C> <C>
BALANCE - JANUARY 1, 1996 11,428,809 $ 50,064 $ 3,437 $ 53,501
------------- ----------- ---------------- -------------
Issued pursuant to employee stock option plan...... 197,675 1,070 - 1,070
Issued pursuant to employee stock purchase plan.... 31,311 358 - 358
Public placement of common shares.................. 4,940,000 58,776 - 58,776
Conversion of preferred stock...................... 2,816,372 16,281 - 16,281
Conversion of warrants............................. 75,000 460 - 460
Conversion of subordinated debt.................... 566,590 3,314 - 3,314
Net income......................................... - - 8,744 8,744
------------- ----------- ---------------- -------------
BALANCE - DECEMBER 31, 1996 20,055,757 130,323 12,181 142,504
------------- ----------- ---------------- -------------
Issued pursuant to employee stock option plan...... 280,656 1,916 - 1,916
Issued pursuant to employee stock purchase plan.... 52,270 900 - 900
Net income......................................... - - 14,903 14,903
------------- ----------- ---------------- -------------
BALANCE - DECEMBER 31, 1997 20,388,683 133,139 27,084 160,223
------------- ----------- ---------------- -------------
Issued pursuant to employee stock option plan...... 132,256 954 - 954
Issued pursuant to employee stock purchase plan.... 101,561 1,139 - 1,139
Conversion of warrants............................. 625,000 4,625 - 4,625
Public placement of common shares.................. 5,554,180 87,939 - 87,939
Net loss........................................... - - (287,145) (287,145)
------------- ----------- ---------------- -------------
BALANCE - DECEMBER 31, 1998 26,801,680 $ 227,796 $ (260,061) $ (32,265)
============= =========== ================ =============
</TABLE>
See Notes to Consolidated Financial Statements
F - 6
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
NOTE 1. BASIS OF PRESENTATION AND FINANCING REQUIREMENTS
The consolidated financial statements have been presented using accounting
principles applicable to a going concern, which assumes that the Company will
continue operations in the foreseeable future and be able to realize assets and
satisfy liabilities in the normal course of business. As of December 31, 1998,
the current value of the Company's reserves, using the unescalated 1998 year-end
oil and natural gas prices and costs, are insufficient to repay the senior bank
loan, the 9% Senior Subordinated Notes due 2008 and the related interest costs,
which casts doubt upon the validity of the going concern assumption.
The Company's ability to continue as a going concern is dependent upon the
completion of the sale of stock to the Texas Pacific Group ("TPG") as described
in Note 6 or an increase in oil and natural gas prices. If this proposed sale of
stock does not close or oil and natural gas prices do not increase to enable the
repayment of the debt and interest costs, the Company will be in default of
covenants of its bank credit agreement.
If the going concern assumption were not appropriate for these financial
statements, then significant adjustments would be necessary in the carrying
value of assets and liabilities, the reported net loss and the balance sheet
classifications.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
The Company operated in only one business segment as its operating activities
are related to exploration, development and production of oil and natural gas in
the United States.
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, Denbury Marine L.L.C. and Denbury Energy Services ("DES").
Prior to May 1, 1996, the Company owned 50% of DES and consolidated only its
equity ownership. Denbury Holdings Ltd. was merged into Denbury Resources Inc.
in December 1997. All material intercompany balances and transactions have been
eliminated.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS The Company follows the full-cost method of accounting for
oil and natural gas properties. Under this method, all costs related to
acquisitions, exploration and development of oil and natural gas reserves are
capitalized and accumulated in a single cost center representing the Company's
activities undertaken exclusively in the United States. Such costs include lease
acquisition costs, geological and geophysical
F - 7
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
expenditures, lease rentals on undeveloped properties, costs of drilling both
productive and non-productive wells and general and administrative expenses
directly related to exploration and development activities and do not include
any costs related to production, general corporate overhead or similar
activities. Proceeds received from disposals are credited against accumulated
costs except when the sale represents a significant disposal of reserves in
which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION The costs capitalized, including production
equipment, are depleted or depreciated on the unit-of-production method, based
on proved oil and natural gas reserves as determined by independent petroleum
engineers. Oil and natural gas reserves are converted to equivalent units based
upon the relative energy content which is six thousand cubic feet of natural gas
to one barrel of crude oil.
C) SITE RECLAMATION Estimated future costs of well abandonment and site
reclamation, including the removal of production facilities at the end of their
useful life, are provided for on a unit-of-production basis. Costs are based on
engineering estimates of the anticipated method and extent of site restoration,
valued at year-end prices, net of estimated salvage value, and in accordance
with the current legislation and industry practice. The annual provision for
future site reclamation costs is included in depletion and depreciation expense.
D) CEILING TEST The capitalized costs less accumulated depletion and
depreciation, related deferred taxes and site reclamation costs are limited to
an amount which is not greater than the estimated future net revenue from proved
reserves using unescalated period-end prices less estimated future site
restoration and abandonment costs, future production-related general and
administrative expenses, financing costs and income taxes, plus the cost (net of
impairments) of undeveloped properties.
E) JOINT INTEREST OPERATIONS Substantially all of the Company's oil and natural
gas exploration and production activities are conducted jointly with others.
These financial statements reflect only the Company's proportionate interest in
such activities and any amounts due from other partners are included in the
trade receivables.
Foreign Currency Translation
In that virtually all of the Company's assets have been located in the United
States since 1993 when the Company sold its Canadian oil and natural gas
properties, the United States assets and 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 or loss per common share is computed by dividing the net income or
loss attributable to common shareholders by the weighted average number of
shares of common shares outstanding. In accordance with Canadian generally
accepted accounting principles ("GAAP"), the imputed dividend during 1996 on the
Convertible First Preferred Shares, Series A has been recorded as an operating
expense in the accompanying financial statements and this is deducted from net
income in computing earnings per share. The conversion of the Convertible First
Preferred Shares, Series A ("Convertible Preferred") was anti-dilutive and was
not included in the calculation of earnings per share. In computing fully
diluted earnings per share, the stock options, warrants
F - 8
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
and convertible debt instruments were dilutive for the years ended December 31,
1997 and 1996 and were assumed to be converted or exercised as of the beginning
of the respective period with the proceeds used to reduce interest expense. As a
result of the net loss for the year ended December 31, 1998, these instruments
were anti-dilutive. All of the Convertible Preferred and the convertible debt
were converted into common shares during 1996 and thus were not relevant to the
calculation of earnings per share after 1996.
Statement of Cash Flows
For purposes of the Statement of Cash Flows, cash equivalents include time
deposits, certificates of deposit and all liquid debt instruments with
maturities at the date of purchase of three months or less.
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any
amounts due from purchasers of oil and natural gas are included in accrued
production receivables.
The Company follows the "sales method" of accounting for its oil and natural gas
revenue whereby the Company recognizes sales revenue on all oil or natural gas
sold to its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A receivable or liability is recognized
only to the extent that the Company has an imbalance on a specific property
greater than the expected remaining proved reserves. As of December 31, 1998 and
1997 the Company's aggregate oil and natural gas imbalances were not material to
its consolidated 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.
Income Taxes
Income taxes are accounted for using the liability method under which deferred
income taxes are recognized for the tax consequences of "temporary differences"
by applying enacted statutory tax rates applicable to future years to
differences between the financial statement carrying amounts and the tax basis
of existing assets and liabilities. The effect on deferred taxes for a change in
tax rates is recognized in income in the period that includes the enactment
date. During 1997, this liability method for computing income taxes was adopted
as GAAP in Canada. This change to the liability method from the deferral method
did not have a material impact on the Company's financial statements.
Financial Instruments with Off-balance Sheet Risk
and Concentrations of Credit Risk
The Company's product price hedging activities are described in Note 7 to the
consolidated financial statements. The Company enters into financial
transactions to hedge anticipated future production. Hedge accounting is
utilized when there is a high degree of correlation between price movements in
the derivative and the underlying item designated as being hedged. The impact of
changes in the market value of the financial transactions, which serve as
hedges, is deferred until the related physical transaction is completed. The
changes, when recognized, are included in oil and gas revenues. If a financial
transaction that has been accounted for as a hedge is closed before
F - 9
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
the date of the anticipated future transaction, the accumulated change in the
value of the financial transactions is deferred until the related physical
transaction is completed. In the event it becomes likely that an anticipated
transaction will not occur or that adequate correlation no longer exists, hedge
accounting is terminated and future changes in the fair value of the derivative
are recognized as gains or losses in the statement of operations. Credit risk
relating to these hedges is minimal because of the credit risk standards
required for counter-parties and monthly settlements. The Company 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 in addition to the product price hedges discussed
above. The Company's cash equivalents and short-term investments represent
high-quality securities placed with various investment grade institutions. This
investment practice limits the Company's exposure to concentrations of credit
risk. The Company's trade and accrued production receivables are dispersed among
various customers and purchasers; therefore, concentrations of credit risk are
limited. Also, the Company's more significant purchasers are large companies
with excellent credit ratings. If customers are considered a credit risk,
letters of credit are the primary security obtained to support lines of credit.
Fair Value of Financial Instruments
As of December 31, 1998 and 1997, the carrying value of the Company's bank debt
and most other financial instruments approximates their fair market value. The
Company's bank debt is based on a floating interest rate and thus adjusts to
market as interest rates change. During 1998, the Company issued $125 million of
9% Senior Subordinated Notes due 2008. As of December 31, 1998, these notes had
a market value of approximately $110 million based on recent trading levels of
the notes. Based on market prices as of December 31, 1998, the Company's open
product price hedging contracts (See Note 7) have no deferred gain or loss. The
Company's other financial instruments are primarily cash, cash equivalents,
short-term receivables and payables which approximate fair value due to the
nature of the instrument and the relatively short maturities.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amount of certain assets, liabilities, revenues and expenses
as of and for the reporting period. Estimates and assumptions are also required
in the disclosure of contingent assets and liabilities as of the date of the
financial statements. Actual results may differ from such estimates.
F - 10
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
NOTE 3. 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
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
of the unevaluated properties excluded from oil and natural gas properties being
amortized at December 31, 1998 and 1997 and the year in which they were incurred
follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1997
------------------------------------ ---------------------------------------
Costs Incurred During: Costs Incurred During:
------------------------- -------------------------
1998 1997 Total 1997 1996 Total
------------ ----------- ---------- ------------ ----------- ----------
AMOUNTS IN THOUSANDS
<S> <C> <C> <C> <C> <C> <C>
Property acquisition costs $ 4,693 $ 48,896 $ 53,589 $ 77,238 $ 286 $ 77,524
Exploration costs......... 8,260 3,796 12,056 3,817 1,457 5,274
------------ ----------- ---------- ------------ ----------- ----------
Total................. $ 12,953 $ 52,692 $ 65,645 $ 81,055 $ 1,743 $ 82,798
============ =========== ========== ============ =========== ==========
</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.
Full Cost Ceiling Test
During the first quarter of 1998, the Company excluded the Heidelberg Field
acquired late in 1997 from the full cost ceiling test because the Company
believed, based on its success with similar properties in Mississippi, that the
value of this property was at least equal to its carrying cost. Had this
property been included in the ceiling test calculation as of March 31, 1998, the
Company would have had a writedown of the property carrying costs of
approximately $35 million for both U.S. and Canadian GAAP.
During the second quarter of 1998, oil prices continued to decline, with a drop
of approximately $1.50 in the NYMEX oil price from March 31 to June 30, 1998.
Furthermore, the gap between the NYMEX oil price and the net realized price
widened, causing the net realized price at Heidelberg Field to drop
approximately $1.00 per Bbl more than the decline in the NYMEX price. Due to the
continued low oil prices, in June 1998 the Company announced that it was
reducing its drilling activity and capital expenditure budget on its oil
properties, including Heidelberg Field, until oil product prices recover. As a
result of this curtailment, it was unlikely that the proved reserves and
production from this property would increase as quickly as originally
anticipated, thus causing a decline in the current value of this property.
Therefore, as of June 30, 1998, the Company included the Heidelberg Field in the
full cost pool for its ceiling test, which coupled with the reduction in oil
prices, resulted in a $165 million writedown of the full cost pool as of that
date. This writedown was approximately the same for both U.S. and Canadian GAAP
and was computed using June 30, 1998 prices, which were equivalent to a NYMEX
oil price of $14.00 per Bbl and an average net realized oil price of $8.90 per
Bbl, a drop of approximately $5.92 per Bbl from the net prices used in the
December 31, 1997 reserve report.
As of December 31, 1998, oil prices had deteriorated further to a NYMEX price of
approximately $12.00 per Bbl and an average net realized price of $7.37 per Bbl.
As a result of this further decrease in price, coupled with some downward
revisions in the proven reserves, the Company recognized an additional ceiling
test writedown as of December 31, 1998. As it is expected by management that the
prices realized over the remaining life of the reserves will be higher than the
year-end prices, an average NYMEX oil price of $14.00 per Bbl (a price slightly
less than the 1998 average price) was used in determining the ceiling test at
year-end. Based on this $14.00 NYMEX price and using undiscounted future net
revenues after considering the effects of administrative and
F - 11
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
interest costs, an additional writedown of $115 million was recognized for the
fourth quarter, for a total writedown for the year of $280 million. This
writedown is the same as that required under U.S. GAAP using the year-end $12.00
NYMEX price and the net present value of the reserves without consideration of
administrative and interest costs. Under Canadian GAAP, if one were to use the
unescalated reserve forecast using year-end prices, the full $115.0 million
remaining balance of the oil and natural gas properties would be written off.
Capitalized Costs
General and administrative costs that directly relate to exploration and
development activities that were capitalized during the period totaled
$2,657,000, $2,225,000 and $1,224,000 for the years ended December 31, 1998,
1997 and 1996, respectively. Amortization per BOE, excluding the full cost pool
writedown, was $7.26, $6.42 and $5.99 for the years ended December 31, 1998,
1997 and 1996, respectively.
NOTE 4. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31,
----------------------------
1998 1997
------------ ------------
AMOUNTS IN THOUSANDS
Senior bank loan...................................$ 100,000 $ 240,000
9% Senior Subordinated Notes due 2008.............. 125,000 -
Other notes payable................................ - 20
------------ ------------
225,000 240,020
Less portion due within one year................... - (20)
------------ ------------
Total long-term debt......................$ 225,000 $ 240,000
============ ============
Banks
The Company has a credit facility with Bank of America, as agent and part of a
group of eight other banks. The credit facility was increased in size from $150
million to $300 million in December 1997 and the borrowing base was increased to
$260 million in order to fund the property acquisition from Chevron. The
December 31, 1997 outstanding balance of $240 million was reduced to $40 million
as of February 26, 1998 after application of the net proceeds from the 1998 debt
and equity offerings net of $9.8 million of additional borrowings.
The credit facility consists of a five-year revolving credit facility and after
the debt and equity offerings completed in February 1998 had a borrowing base of
$165 million. This borrowing base is subject to review every six months and was
reduced to $130 million at the October 1, 1998 redetermination date as a result
of the low product prices.
F - 12
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
On February 19, 1999, the Company completed an amendment to its credit facility.
This amendment set the borrowing base at $110 million, of which $60 million was
considered to be conforming to the bank's normal credit policies. As a result of
the writedown of oil and gas properties the Company was in default under its
bank loan agreement as of December 31, 1998. The amendment modified the debt
covenant such that the Company is now in compliance. This amendment also:
o provides certain relief on the minimum equity and interest
coverage tests;
o changes the facility to one secured by substantially all of
the Company's oil and natural gas properties;
o requires that as long as the borrowing base is larger than the
conforming borrowing base, that at least 75% of the funds
borrowed under the facility subsequent to the closing of the
proposed TPG purchase be used for either qualifying
acquisitions or capital expenditures made to maintain, enhance
or develop its proved reserves;
o increases the interest rate to a range from LIBOR plus 1.0% to
LIBOR plus 1.75% depending on amounts outstanding and LIBOR
plus 2.125% if the outstanding debt exceeds the conforming
borrowing base, currently set at $60 million; and
o provides that a failure to close the sale of stock to TPG
before June 16, 1999 would be an event of default.
This credit facility has several restrictions including, among others: (i) a
prohibition on the payment of dividends, (ii) a requirement for a minimum equity
balance, (iii) a requirement to maintain positive working capital, as defined,
(iv) a minimum interest coverage test and (v) a prohibition of most debt and
corporate guarantees. As of December 31, 1998, the Company had $100 million
outstanding on this line of credit and $370,000 of letters of credit
outstanding. The next scheduled re-determination of the borrowing base will be
as of October 1, 1999, based on June 30, 1999 assets and proved reserves.
Subordinated Debt
During 1996, the Company converted all of its previously issued convertible
debentures with a total principal amount of Cdn. $4.5 million into 566,590
Common Shares.
On February 26, 1998, Denbury Management Inc., a wholly-owned subsidiary of the
Company, issued $125 million in aggregate principal amount of 9% Senior
Subordinated Notes Due 2008 which require semi-annual interest payments only
until maturity. These notes contain certain debt covenants, including covenants
that limit (i) indebtedness, (ii) certain restricted payments including
dividends, (iii) sale/leaseback transactions, (iv) transactions with affiliates,
(v) liens, (vi) asset sales and (vii) mergers and consolidations. The net
proceeds to the Company from the debt offering were approximately $121.8
million, before offering expenses.
F - 13
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
Indebtedness Repayment Schedule
The Company's indebtedness as of December 31, 1998 is repayable as follows:
AMOUNTS IN THOUSANDS
- ---------------------------------------------------------------
YEAR
1999 ........................................$ -
2000 ........................................ -
2001 ........................................ -
2002 ........................................ 100,000
Thereafter..................................... 125,000
----------------
Total indebtedness $ 225,000
================
NOTE 5. INCOME TAXES
The Company's income tax provision is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
AMOUNTS IN THOUSANDS 1998 1997 1996
----------- --------- ----------
<S> <C> <C> <C>
Deferred
Federal.........................................$ (15,620) $ 8,589 $ 5,312
State........................................... - 306 -
----------- --------- ----------
Total income tax provision (benefit)...............$ (15,620) $ 8,895 $ 5,312
=========== ========= ==========
</TABLE>
Income tax expense for the year varies from the amount that would result from
applying Canadian federal and provincial tax rates to income before income taxes
as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
AMOUNTS IN THOUSANDS 1998 1997 1996
------------ ---------- ----------
<S> <C> <C> <C>
Deferred income tax provision (benefit) calculated
using the Canadian federal and provincial statutory
combined tax rate of 44.34%......................... $ (134,245) $ 10,552 $ 6,233
Increase resulting from:
Imputed preferred dividend.......................... - - 568
Non-deductible Canadian expenses.................... - - 97
Decrease resulting from:
Valuation allowance................................. 96,402 - -
Effect of lower income tax rates on United States
income........................................... 22,223 (1,657) (1,586)
------------ ---------- ----------
Total income tax provision (benefit) $ (15,620) $ 8,895 $ 5,312
============ ========== ==========
</TABLE>
As a result of the net pre-tax loss of $302.8 million for the year ended
December 31, 1998, an income tax provision for 1998 using the effective tax rate
of 37% would have resulted in a $96.4 million deferred tax asset. Since the
Company currently has a large tax net operating loss, it was uncertain whether
this total tax asset could ultimately be realized, particularly in light of the
low oil and natural gas prices. As such, the Company fully impaired the deferred
tax asset, resulting in a 5% effective tax benefit rate for the year.
F - 14
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
The Company at December 31, 1998 had net operating loss carryforwards for U.S.
federal income tax purposes of approximately $135.0 million and approximately
$46.8 million for alternative minimum tax purposes. The net operating losses are
scheduled to expire as follows:
INCOME ALTERNATIVE
AMOUNTS IN THOUSANDS TAX MINIMUM TAX
- ----------------------------------------------------- ---------------
YEAR
2004 .................................$ 39 $ -
2005 ................................. 11 -
2006 ................................. 644 500
2007 ................................. 714 99
2008 ................................. 5,016 4,889
2009 ................................. 3,377 2,868
2010 ................................. 3,467 3,420
2011 ................................. 5,061 1,115
2012 ................................. 29,508 4,124
2018 ................................. 87,212 29,775
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1998 and 1997 balance sheet dates.
At December 31, 1998 and 1997, all deferred tax assets and liabilities were
computed based on Canadian GAAP amounts and were noncurrent as follows:
DECEMBER 31,
----------------------------
AMOUNTS IN THOUSANDS 1998 1997
------------- ------------
Deferred tax assets:
Loss carryforwards....................... $ 49,968 $ 15,699
Basis difference of exploration and
production assets.................... 46,888 (31,319)
Deferred tax liabilities:
Other.................................... (454) -
------------- ------------
Net deferred tax asset (liability)............. 96,402 (15,620)
Less: Valuation allowance................ (96,402) -
------------- ------------
Total deferred tax asset (liability). $ - $ (15,620)
============= ============
NOTE 6. 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. No stockholder has any right to convert
Common Shares 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
F - 15
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
therefore and, upon liquidation, to a pro rata share in any distribution to
stockholders, subject to prior rights of the holders of the preferred stock. The
Company is restricted from declaring or paying any cash dividend on the Common
Shares by its bank loan agreement.
Proposed Sale of Stock to the Texas Pacific Group
On December 16, 1998, the Company entered into a stock purchase agreement with
its largest shareholder, the Texas Pacific Group ("TPG"). This agreement
provides for TPG to purchase 18,552,876 common shares of the Company at $5.39
per share for an aggregate consideration of $100 million. The consummation of
this stock sale is conditioned upon the approval of the sale by the shareholders
of the Company, completion of an amendment to the Company's bank agreement, the
absence of a material adverse change, as that term is defined in the agreement,
plus satisfaction of other conditions. The Company completed an amendment to its
bank credit facility as of February 19, 1999 (see Note 4. Notes Payable and
Long-Term Indebtedness - Banks) and is seeking shareholder approval at a special
meeting of the shareholders currently expected to be held in April 1999.
As a result of this sale of stock, TPG will gain control of the Company with
ownership that will increase from approximately 32% to approximately 60%.
Although the Company does not expect this transaction to result in any immediate
changes to its directors, management or operations, TPG will have adequate
voting power to control the election of directors, to determine the corporate
and management policies of the Company and to effect the shareholder approval of
a merger, consolidation or sale of all or substantially all of the assets of the
Company.
The Company expects to close this stock sale in April 1999 and plans to pursue
acquisitions with funds made available under its bank credit facility as a
result of the sale. If this proposed sale of stock does not close by June 16,
1999, the Company will be in default of its bank credit agreement.
1998 Equity Offering
On February 26, 1998, the Company closed on a public offering of 5,240,780
Common Shares at a price to the public of $16.75 per share and a net price to
the Company of $15.955 per share (the "Equity Offering"). Concurrently with the
Equity Offering, TPG, the Company's largest shareholder, purchased 313,400
Common Shares from the Company at $15.955 per share, equal to the price to the
public per share less underwriting discounts and commissions (the "TPG
Purchase"). The net proceeds to the Company from the Equity Offering and TPG
Purchase was approximately $88.6 million, before offering expenses.
1996 Capital Adjustments
During 1996, the Company issued 250,000 Common Shares for the conversion of the
6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for the
exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10, 1996,
the Company effected a one-for-two reverse split of its outstanding Common
Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2%
Convertible Debentures ("Debentures") were converted into 316,590 Common Shares.
The Company also converted all of the 1,500,000 shares of Convertible Preferred
on October 30, 1996 into 2,816,372 Common Shares. On October 30, 1996 and
November 1, 1996, the Company also issued an aggregate of 4,940,000 Common
Shares at a net price of $12.035 per share as part of a public offering for net
proceeds to the Company of approximately $58.8 million. TPG purchased 800,000 of
these shares at $12.035 per share.
F - 15
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
Warrants
At December 31, 1998, 75,000 warrants were outstanding at an exercise price of
Cdn. $8.40 expiring on May 5, 2000. Each warrant entitles the holder thereof to
purchase one Common Share at any time prior to the expiration date.
Stock Option Plan
The Company maintains a Stock Option Plan which authorizes the grant of options
up to 4,535,000 Common Shares, of which 2,015,756 options are subject to
shareholder approval at a special meeting of the shareholders anticipated to be
held in April, 1999. Under the terms of the plan, incentive and non-qualified
options may be issued to officers, key employees and consultants. Options
generally become exercisable over a four year vesting period with the specific
terms of vesting determined by the Board of Directors at the time of grant. The
options expire over terms not to exceed ten years from the date of grant, ninety
days after termination of employment or permanent disability or one year after
the death of the optionee. The options are granted at the fair market value at
the time of grant which is generally defined as the average closing price of the
Company's Common Shares for the ten trading days prior to issuance. The plan is
administered by the Stock Option Committee of the Board.
Following is a summary of stock option activity during the years ended December
31, 1998, 1997 and 1996:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------
1998 1997 1996
--------------------------- ---------------------------- ------------------------
Weighted Weighted Weighted
Number Average Price Number Average Price Number Average Price
----------- ------------- ----------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of
year......................... 1,546,256 $ 11.06 1,053,000 $ 7.63 731,925 $ 6.11
Granted........................ 488,559 17.71 797,162 14.13 525,500 8.96
Terminated..................... (4,528) 17.25 (23,250) 11.51 (6,750) 6.28
Exercised...................... (132,256) 7.29 (280,656) 6.95 (197,675) 5.42
Expired........................ (7,500) 7.15 - - - $ -
----------- ------------- ----------- -------------- ----------- --------------
Outstanding at end of year..... 1,890,531 $ 13.04 1,546,256 $ 11.06 1,053,000 7.63
=========== ============= =========== ============== =========== ==============
Options exercisable at end of
year......................... 398,474 $ 8.85 391,872 $ 7.57 532,375 $ 6.82
=========== ============= =========== ============== =========== ==============
</TABLE>
<TABLE>
<CAPTION>
Weighted Weighted
Options Outstanding as of Options Average Weighted Average Exercisable Average
December 31, 1998: Outstanding Price Remaining Life (yrs.) Options Price
- --------------------------------- ------------ ---------- ----------------------- ------------ ----------
<S> <C> <C> <C> <C> <C>
Exercise price of:
$4.71 to $7.00 350,700 $ 6.38 5.5 171,950 $ 5.87
$7.01 to $13.37 298,048 9.95 7.5 195,313 9.97
$13.38 to $17.37 775,715 13.84 8.2 19,550 16.01
$17.38 to $22.24 466,068 18.71 9.0 11,661 22.01
</TABLE>
The Company also issued 1,627,988 stock options to all Company employees on
January 4, 1999 in accordance with the terms of the plan. These options are
subject to shareholder approval at a special meeting of shareholders anticipated
to be held in April 1999.
In 1995, the United States Financial Accounting Standards Board issued Statement
of Financial Accounting
F - 17
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation." With
regard to its stock option plan, the Company applies APB Opinion No. 25 as
allowed under SFAS 123 in accounting for this plan and accordingly no
compensation cost has been recognized. Had compensation expense been determined
based on the fair value at the grant dates for the stock option grants
consistent with the method of SFAS No. 123, the Company's net income (loss) and
net income (loss) per common share would have been reduced (increased) to the
following pro forma amounts:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
----------- ---------- --------
<S> <C> <C> <C>
NET INCOME (LOSS):
As reported (thousands)................................................$ (287,145) $ 14,903 $ 8,744
Pro forma (thousands).................................................. (289,463) 14,130 8,215
NET INCOME (LOSS) PER COMMON SHARE:
As reported:
Basic.......................................................$ (11.08) $ 0.74 $ 0.67
Fully diluted............................................... (11.08) 0.70 0.62
Pro forma:
Basic.......................................................$ (11.16) $ 0.70 $ 0.63
Fully diluted............................................... (11.16) 0.66 0.59
Stock options issued during period (thousands)............................ 489 797 526
Weighted average exercise price...........................................$ 17.71 $ 14.13 $ 8.96
Average per option compensation value of options granted (a).............. 7.64 4.02 2.95
Compensation cost (thousands)............................................. 2,318 1,227 801
<FN>
(a) Calculated in accordance with the Black-Scholes option pricing model, using
the following assumptions: expected volatility computed using, as of the
date of grant, the prior three-year monthly average of the Common Shares as
listed on the TSE, which ranged from 38% to 63%; expected dividend yield -
0%; expected option term - 5 years; and risk-free rate of return as of the
date of grant which ranged from 4.5% to 5.7%, based on the yield of
five-year U.S. treasury securities.
</FN>
</TABLE>
Stock Purchase Plan
In February 1996, the Company implemented a Stock Purchase Plan which authorizes
the sale of Common Shares to all full-time employees. The number of Common
Shares currently approved by the Board of Directors for this purpose is 750,000
shares of which 500,000 is subject to shareholder approval at a special meeting
of shareholders anticipated to be held in April 1999. 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 each quarter. The Company recognizes compensation expense
for the 75% Company matching portion, which totaled $648,000, $383,000 and
$147,000 for the years ended December 31, 1998, 1997 and 1996, respectively.
This plan is administered by the Stock Purchase Plan Committee of the Board.
401(k) Plan
The Company offers a 401(k) Plan to which employees may contribute tax deferred
earnings subject to Internal Revenue Service limitations. The Company matches
50% of employee contributions up to an employee contribution of 6% of their
salary. This Company match becomes vested over a six year period. During 1998,
the Company contributed $217,000 to the 401(k) Plan.
F - 18
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
NOTE 7. PRODUCT PRICE HEDGING CONTRACTS
During June and July 1998, the Company entered into two no-cost financial
contracts ("collars") to hedge a total of 40 million cubic feet of natural gas
per day ("MMcf/d"). The first natural gas contract for 35 MMcf/d covers the
period from July 1998 to June 1999 and has a floor price of $1.90 per million
British Thermal Units ("MMBtu") and a ceiling price of $2.96 per MMBtu. The
second natural gas contract for five MMcf/d covers the period from September
1998 to August 1999 and has a floor price of $1.90 per MMBtu and a ceiling price
of $2.89 per MMBtu. During December 1998, the Company extended these natural gas
hedges through December 2000 by entering into an additional no-cost collar with
a floor price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu for the
period of July 1999 through December 2000. This contract hedges 25 MMcf/d for
the months of July and August 1999 and 30 MMcf/d for each month thereafter. The
Company collected $175,200 on these financial contracts during 1998. These three
contracts cover over 100% of the Company's current net natural gas production.
Based on the futures market prices at December 31, 1998, the Company would not
receive or pay any amounts under these open commodity contracts even though they
covered more than the Company's production because prices at December 31, 1998
were within the contract collars.
During the fourth quarter of 1998, the Company also modified certain of its oil
sales contracts. The new contracts which are generally for a period of eighteen
months, provide that approximately 45% of the Company's oil production as of
January 31, 1999, has a price floor of between $8.00 and $10.00 per Bbl. This
equates to a NYMEX oil price of between $15.00 and $16.00 per bbl. As
compensation for the price floors, the contracts provide that the premiums
received on the posted prices decrease as oil prices rise.
NOTE 8. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1998, long-term commitments for these
items require the following future minimum rental payments:
AMOUNTS IN THOUSANDS
1999 .........................$ 593
2000 ......................... 1,274
2001 ......................... 1,259
2002 ......................... 1,242
2003 ......................... 1,120
--------------
Total lease commitments $ 5,488
==============
The Company is subject to various possible contingencies which arise primarily
from interpretation of federal and state laws and regulations affecting the oil
and natural gas industry. Such contingencies include differing interpretations
as to the prices at which oil and natural gas sales may be made, the prices at
which royalty owners may be paid for production from their leases, environmental
issues and other matters. Although management believes 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.
In June of 1997, a well blow-out occurred at the Lake Chicot Field, for which
the Company is operator, in St. Martin Parish, Louisiana in which four
individuals that were employees of other third party entities were killed,
F - 19
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
none of whom were employees or contractors of the Company. In connection with
this blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al .v.
Mallard Bay Drilling L.L.C., Parker Drilling Company and Denbury Management,
Inc., Case No. 58226-G in the 16th Judicial District Court in St. Martin Parish,
Louisiana alleging various defective and dangerous conditions, violation of
certain rules and regulations and acts of negligence. The Company believes that
all litigation to which it is a party is covered by insurance and none of such
legal proceedings can be reasonably expected to have a material adverse effect
on the Company's financial condition, results of operations or cash flows.
The Company and its subsidiaries are involved in various other lawsuits, claims
and regulatory proceedings incidental to their businesses. In the opinion of
management, the outcome of such matters will not have a material adverse effect
on the Company's business, consolidated financial position, results of
operations or cash flows.
Uncertainty Due to the Year 2000 Issue
The Year 2000 Issue arises because many computerized systems use two digits
rather than four to identify a year. Date-sensitive systems may recognize the
year 2000 as 1900 or some other date, resulting in errors when information using
year 2000 dates is processed. In addition, similar problems may arise in some
systems which use certain dates in 1999 to represent something other than a
date. The effects of the Year 2000 Issue may be experienced before, on, or after
January 2000, and, if not addressed, the impact on operations and financial
reporting may range from minor errors to significant systems failure which could
affect the Company's ability to conduct normal business operations. It is not
possible to be certain that all aspects of the Year 2000 Issue affecting the
Company, including those related to the efforts of customers, suppliers, or
other third parties, will be fully resolved.
NOTE 9. DIFFERENCES IN GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES BETWEEN CANADA AND THE UNITED STATES
The consolidated financial statements have been prepared in accordance with GAAP
in Canada. The primary differences between Canadian and U.S. GAAP affecting the
Company's consolidated financial statements are as discussed below.
Loss on Extinguishment of Debt and Imputed Preferred Dividends
The most significant GAAP difference relates to the presentation of the early
extinguishment of debt and the imputed dividend on the Convertible Preferred.
During 1996, the Company expensed $1,281,000 relating to the imputed preferred
dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would
be deducted from net income to compute the net income attributable to the common
shareholders. The Company also expensed its debt issue cost relating to the
Company's prior bank credit agreements totaling $440,000 for 1996. 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 1996 under U.S. GAAP would be
$10,025,000, while under Canadian GAAP the amount reported was $8,744,000.
F - 20
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
Earnings Per Share
In addition, the methodology for computing fully diluted earnings per common
share is not consistent between the two countries. For Canadian purposes, the
proceeds from dilutive securities are used to reduce debt in the calculation.
Under U.S. GAAP, Statement of Financial Accounting Standards ("SFAS") No. 128
requires the proceeds from such instruments be used to repurchase Common Shares.
Under U.S. GAAP, fully diluted earnings per share for the year ended December
31, 1996, the only year with a difference, would be $0.63 as compared to the
$0.62 reported under Canadian GAAP.
Full Cost Accounting
The U.S. full cost accounting rules differ from the Canadian full cost
accounting guidelines followed by the Company. In determining the limitation on
carrying values, U.S. accounting rules require the discounting of estimated
future net revenues from its proved reserves at 10% using constant current
prices following the guidelines of the Securities and Exchange Commission
("SEC"). The Canadian guidelines allow the use of either current prices or
average prices in the calculations of future net revenues presented on an
undiscounted basis, less estimated future administrative and financing costs,
income taxes and future site restoration and abandonment costs. See also "Note
3. Property and Equipment" for a discussion of the application of these rules on
the ceiling test calculation.
Other Differences
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (the "Statement"), which establishes
standards for accounting and reporting derivative instruments. SFAS No. 133 is
effective for periods beginning after June 15, 1999; however, earlier
application is permitted. Management is currently not planning on early adoption
of this Statement and has not had an opportunity to evaluate the impact of the
provisions of the Statement on the Company's consolidated financial statements.
The implementation of SFAS No. 130, "Reporting Comprehensive Income" is required
for all fiscal years beginning after December 15, 1997. The Company had no items
that would be included in a Comprehensive Income Statement for any of the three
years ended December 31, 1998.
F - 21
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
NOTE 10. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon operations. For the year
ended December 31, 1998, the Company sold 10% or more of its net production of
oil and natural gas to the following purchasers: Hunt Refining (34%), Natural
Gas Clearinghouse (17%) and Genesis Crude Oil (11%).
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural
gas property acquisition, exploration and development activities. Property
acquisition costs are those costs incurred to purchase, lease, or otherwise
acquire property, including both undeveloped leasehold and the purchase of
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, 1998, 1997 and 1996 are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------
AMOUNTS IN THOUSANDS 1998 1997 1996
----------- ----------- -----------
Property acquisitions:
Proved......................... $ 13,093 $ 149,145 $ 46,230
Unevaluated.................... 7,185 77,664 2,626
Exploration......................... 12,222 20,734 4,592
Development......................... 70,152 57,884 33,409
----------- ----------- -----------
Total costs incurred $ 102,652 $ 305,427 $ 86,857
=========== =========== ===========
Property Acquisitions
On December 30, 1997, Denbury acquired producing oil and natural gas properties
in Mississippi for approximately $202 million (the "Chevron Acquisition"). The
acquisition included 122 wells, of which 96 wells will be Company operated. The
Company funded this acquisition with bank financing from a revised and restated
credit facility.
This acquisition was accounted for under purchase accounting and the results of
operations will be consolidated effective December 31, 1997. Pro forma results
of operations of the Company as if the Chevron Acquisition had occurred at the
beginning of each respective period are as follows:
F - 22
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
YEAR ENDED DECEMBER 31,
--------------------------
1997 1996
---------- -----------
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
Revenues........................................$ 104,695 $ 77,311
Net income...................................... 9,966 5,342
Net income per common share:
Basic...................................... 0.49 0.41
Fully diluted.............................. 0.48 0.41
In computing the pro forma results, depreciation, depletion and amortization
expense was computed using the units of production method, and an adjustment was
made to interest expense reflecting the bank debt that was required to fund the
acquisition. The pro forma results does not reflect any increases in general and
administrative expense.
11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Denbury Management, Inc. issued debt securities during February 1998 which are
fully and unconditionally guaranteed by Denbury Resources Inc. Denbury Holdings
Ltd. was merged into Denbury Resources Inc. in December 1997 and is not a
guarantor of the debt. Condensed consolidating financial information for Denbury
Resources Inc. and Subsidiaries as of December 31, 1998 and 1997 and for the
years ended December 31, 1998, 1997 and 1996 is as follows:
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31, 1998
-------------------------------------------------------
Denbury Denbury Denbury
Management, Resources Inc. Resources Inc.
AMOUNTS IN THOUSANDS Inc. (Issuer) (Guarantor) Eliminations Consolidated
----------- ------------ ----------- ------------
<S> <C> <C> <C> <C>
ASSETS
Current assets........................................$ 23,900 $ 34 $ - $ 23,934
Property and equipment (using full cost accounting)... 180,664 - - 180,664
Investment in subsidiaries (equity method)............ - (32,274) 32,274 -
Other assets.......................................... 8,260 1 - 8,261
----------- ------------ ----------- ------------
Total assets............................$ 212,824 $ (32,239) $ 32,274 $ 212,859
=========== ============ =========== ============
LIABILITIES AND SHAREHOLDERS' DEFICIT
Current liabilities...................................$ 18,662 $ 26 $ - $ 18,688
Long-term liabilities................................. 226,436 - - 226,436
Shareholders'deficit.................................. (32,274) (32,265) 32,274 (32,265)
----------- ------------ ----------- ------------
Total liabilities and shareholders' deficit..... $ 212,824 $ (32,239) $ 32,274 $ 212,859
=========== ============ =========== ============
</TABLE>
F - 23
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
DECEMBER 31, 1997
-------------------------------------------------------
Denbury Denbury Denbury
Management, Resources Inc. Resources Inc.
AMOUNTS IN THOUSANDS Inc. (Issuer) (Guarantor) Eliminations Consolidated
----------- ------------ ----------- ------------
<S> <C> <C> <C> <C>
ASSETS
Current assets........................................$ 33,017 $ 363 $ - $ 33,380
Property and equipment (using full cost accounting)... 408,832 - - 408,832
Investment in subsidiaries (equity method)............ - 159,892 (159,892) -
Other assets.......................................... 5,234 102 - 5,336
----------- ------------ ----------- ------------
Total assets............................$ 447,083 $ 160,357 $ (159,892) $ 447,548
=========== ============ =========== ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities...................................$ 30,554 $ 134 $ - $ 30,688
Long-term liabilities................................. 256,637 - - 256,637
Shareholders' equity.................................. 159,892 160,223 (159,892) 160,223
----------- ------------ ----------- ------------
Total liabilities and shareholders' equity...$ 447,083 $ 160,357 $ (159,892) $ 447,548
=========== ============ =========== ============
</TABLE>
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(in thousands of U.S. dollars)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
-------------------------------------------------------
Denbury Denbury Denbury
Management, Resources Inc. Resources Inc.
AMOUNTS IN THOUSANDS Inc. (Issuer) (Guarantor) Eliminations Consolidated
------------ ------------ ----------- ------------
<S> <C> <C> <C> <C>
Revenues.....................................$ 83,504 $ 2 $ - $ 83,506
Expenses..................................... 386,094 177 - 386,271
------------ ------------ ----------- ------------
Loss before: (302,590) (175) - (302,765)
Equity in net losses of subsidiaries... - (286,970) 286,970 -
------------ ------------ ----------- ------------
Loss before income taxes..................... (302,590) (287,145) 286,970 (302,765)
Income tax benefit........................... 15,620 - - 15,620
------------ ------------ ----------- ------------
Net loss.....................................$ (286,970) $ (287,145) $ 286,970 $ (287,145)
============ ============ =========== ============
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
----------------------------------------------------------------------
Denbury Denbury Denbury
Management, Denbury Resources Inc. Resources Inc.
AMOUNTS IN THOUSANDS Inc. (Issuer) Holdings Ltd. (Guarantor) Eliminations Consolidated
------------ ----------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C>
Revenues.....................................$ 86,451 $ - $ 150 $ (145) $ 86,456
Expenses..................................... 62,658 - 145 (145) 62,658
------------ ----------- ------------ ----------- -------------
Income before: 23,793 - 5 - 23,798
Equity in net earnings of subsidiaries... - 14,898 14,898 (29,796) -
------------ ----------- ------------ ----------- -------------
Income before income taxes................... 23,793 14,898 14,903 (29,796) 23,798
Income tax provision......................... (8,895) - - - (8,895)
------------ ----------- ------------ ----------- -------------
Net income...................................$ 14,898 $ 14,898 $ 14,903 $ (29,796) $ 14,903
============ =========== ============ =========== =============
</TABLE>
F - 24
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
----------------------------------------------------------------------
Denbury Denbury Denbury
Management, Denbury Resources Inc. Resources Inc.
AMOUNTS IN THOUSANDS Inc. (Issuer) Holdings Ltd. (Guarantor) Eliminations Consolidated
------------ ----------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C>
Revenues.....................................$ 53,631 $ - $ 179 $ (161) $ 53,649
Expenses..................................... 38,008 - 1,746 (161) 39,593
------------ ----------- ------------ ----------- -------------
Income (loss) before: 15,623 - (1,567) - 14,056
Equity in net earnings of subsidiaries.. - 10,311 10,311 (20,622) -
------------ ----------- ------------ ----------- -------------
Income before income taxes................... 15,623 10,311 8,744 (20,622) 14,056
Income tax provision......................... (5,312) - - - (5,312)
------------ ----------- ------------ ----------- -------------
Net income...................................$ 10,311 $ 10,311 $ 8,744 $ (20,622) $ 8,744
============ =========== ============ =========== =============
</TABLE>
NOTE 12. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31, 1998, 1997
and 1996 were prepared by Netherland & Sewell, independent petroleum engineers
located in Dallas, Texas. The reserves were prepared in accordance with
guidelines established by the Securities and Exchange Commission and,
accordingly, were based on existing economic and operating conditions. Oil and
natural gas prices in effect as of the reserve report date were used without any
escalation except in those instances where the sale is covered by contract, in
which case the applicable contract prices including fixed and determinable
escalations were used for the duration of the contract, and thereafter the last
contract price was used (See "Standardized Measure of Discounted Future Net Cash
Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves" below
for a discussion of the effect of the different prices on reserve quantities and
values.) Operating costs, production and ad valorem taxes and future development
costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in the United States.
F - 25
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
Estimated Quantities of Reserves
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1998 1997 1996
---------------------- ---------------------- ----------------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
--------- ---------- ---------- --------- --------- ----------
<S> <C> <C> <C> <C> <C> <C>
BALANCE BEGINNING OF YEAR................... 52,018 77,191 15,052 74,102 6,292 48,116
Revisions of previous estimates.......... (7,267) (15,369) 3,398 1,098 (490) 3,737
Revisions due to price changes........... (14,921) (990) (1,525) (317) 1,053 402
Extensions, discoveries and other
additions.......................... 678 1,951 6,373 11,205 3,492 5,480
Production............................... (4,965) (13,361) (2,884) (13,257) (1,500) (8,933)
Acquisition of minerals in place......... 2,998 21 31,604 4,360 6,205 25,300
Sales of minerals in place............... (291) (640) - - - -
--------- ---------- ---------- --------- --------- ----------
BALANCE AT END OF YEAR...................... 28,250 48,803 52,018 77,191 15,052 74,102
========= ========== ========== ========= ========= ==========
PROVED DEVELOPED RESERVES:
Balance at beginning of year............. 31,355 69,805 13,371 58,634 5,290 34,894
Balance at end of year................... 20,357 44,995 31,355 69,805 13,371 58,634
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does
not purport to present the fair market value of the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates. It should be noted that
estimates of reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. The product prices used
in calculating these reserves has varied widely during the three year period.
These prices have a significant impact on both the quantities and value of the
proven reserves as the reduced oil price causes wells to reach the end of their
economic life much sooner and also makes certain proved undeveloped locations
uneconomical, both of which reduce the reserves. The low prices also indirectly
affect reserve quantities and values as the Company may postpone or cancel
repairs and upgrades on oil wells which result in steeper than expected
declines.
The oil prices used in the December 31, 1996 reserve report were based on a West
Texas Intermediate price of $23.39 per Bbl, with these representative prices
adjusted by field to arrive at the appropriate corporate net price in accordance
with the rules of the Securities and Exchange Commission. However, this price
was reduced to $16.18 per Bbl at December 31, 1997 and further reduced to $9.50
as of December 31, 1998. The Company's average net realized oil prices used in
the December 31, 1996, 1997 and 1998 reserve reports were $21.73, $14.43 and
$7.37, respectively. The gas prices used in the reserve calculation also varied
widely with a NYMEX Henry Hub price of $3.90 per MMBtu at December 31, 1996 and
a price of $2.58 and $2.15 per MMBtu at December 31, 1997 and 1998,
respectively.
F - 26
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
Future cash inflows were reduced by estimated future production and development
costs based on year-end costs to determine pre-tax cash inflows. Future income
taxes were computed by applying the statutory tax rate to the excess of pre-tax
cash inflows over the Company's tax basis in the associated proved oil and
natural gas properties. Tax credits and net operating loss carryforwards were
also considered in the future income tax calculation. Future net cash inflows
after income taxes were discounted using a 10% annual discount rate to arrive at
the Standardized Measure.
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------
AMOUNTS IN THOUSANDS 1998 1997 1996
-------------- ------------- -------------
<S> <C> <C> <C>
Future cash inflows.................................................... $ 317,148 $ 957,718 $ 627,476
Future production costs................................................ (112,521) (285,968) (134,986)
Future development costs............................................... (23,887) (68,287) (28,722)
-------------- ------------- -------------
Future net cash flows before taxes .................................... 180,740 603,463 463,768
10% annual discount for estimated timing of cash flows............ (65,721) (242,134) (147,670)
-------------- ------------- -------------
Discounted future net cash flows before taxes.......................... 115,019 361,329 316,098
Discounted future income taxes......................................... - (26,021) (74,226)
-------------- ------------- -------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS............... $ 115,019 $ 335,308 $ 241,872
============== ============= =============
</TABLE>
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
AMOUNTS IN THOUSANDS 1998 1997 1996
------------- ------------- --------------
<S> <C> <C> <C>
BEGINNING OF YEAR...................................................... $ 335,308 $ 241,872 $ 81,164
Sales of oil and natural gas produced, net of production costs......... (52,721) (63,115) (39,385)
Net changes in sales prices............................................ (198,836) (132,905) 116,587
Extensions and discoveries, less applicable future development
and production costs................................................ 6,605 75,632 34,113
Previously estimated development costs incurred........................ 30,742 10,088 5,278
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production................. (76,532) 264 7,747
Accretion of discount.................................................. 33,531 24,187 8,116
Purchase of minerals in place.......................................... 12,869 131,080 86,677
Sales of minerals in place............................................. (1,968) - -
Net change in income taxes............................................. 26,021 48,205 (58,425)
------------- ------------- --------------
END OF YEAR............................................................ $ 115,019 $ 335,308 $ 241,872
============= ============= ==============
</TABLE>
F - 27
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 1998 and 1997.
<TABLE>
<CAPTION>
IN THOUSANDS EXCEPT PER SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
- ----------------------------------------------- ------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998
- ----
Revenues $ 25,555 $ 22,883 $ 19,599 $ 15,469
Expenses 26,608 195,067 22,022 142,574
Net loss (608) (121,939)(c) (2,423) (162,103)(c)
Net loss per share: (a)
Basic (0.03) (4.57) (0.09) (6.05)
Fully diluted (0.03) (4.57) (0.09) (6.05)
Cash flow from operations (b) 11,455 9,052 6,817 2,772
Cash flow used for investing activities 26,689 50,120 17,781 9,207
Cash flow provided by financing activities 14,826 30,906 20,501 10,002
1997
- ----
Revenues $ 21,653 $ 19,015 $ 20,401 $ 25,387
Expenses 13,375 15,512 15,304 18,467
Net income 5,215 2,207 3,211 4,270
Net income per share:
Basic 0.26 0.11 0.16 0.21
Fully diluted 0.24 0.11 0.15 0.20
Cash flow from operations (b) 14,922 12,001 13,243 16,441
Cash flow used for investing activities 15,572 21,427 35,012 235,548
Cash flow provided by financing activities 436 1,030 20,752 218,897
<FN>
(a) Due to the significant variances between quarters in net income and average
shares outstanding, the combined quarterly loss per share does not equal the
reported loss per share for 1998.
(b) Exclusive of the net change in non-cash working capital balances.
(c) Includes full cost ceiling writedown of oil and natural gas properties of
$165 million and $115 million for the quarters ended June 30, 1998 and
December 31, 1998, respectively.
</FN>
</TABLE>
Common Stock Trading Summary
The following table summarizes the high and low last reported sales prices on
days in which there were trades of the Common Shares on The New York Stock
Exchange ("NYSE"), NASDAQ and on The Toronto Stock Exchange ("TSE") (as reported
by such exchange) for each quarterly period for the last two fiscal years. The
trades on the NYSE / NASDAQ are reported in U.S. dollars and the TSE trades are
reported in Canadian dollars. The Company's Common Shares were listed on NASDAQ
from August 25, 1995 to May 8, 1997. The Common Shares have been listed on the
NYSE since May 8, 1997.
As of February 1, 1999, to the best of the Company's knowledge, the Common
Shares were held of record by approximately 1,300 holders, of which
approximately 300 were U.S. residents holding approximately 80% of the
outstanding Common Shares of the Company.
No Common Share dividends have been paid or are anticipated to be paid. (See
also Note 6 to the Consolidated Financial Statements.)
F - 28
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
NYSE/NASDAQ (U.S. $) TSE (CDN $)
HIGH LOW HIGH LOW
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998
- ----
First quarter 20.63 16.13 29.00 23.00
Second quarter 17.75 12.75 25.00 18.50
Third quarter 13.50 6.00 19.90 8.75
Fourth quarter 8.50 3.50 13.10 5.40
- --------------------------------------------------------------------------------------------------------------------
1998 annual 20.63 3.50 29.00 5.40
- --------------------------------------------------------------------------------------------------------------------
1997
- ----
First quarter 16.00 12.00 21.75 16.40
Second quarter 17.63 13.13 24.50 18.00
Third quarter 23.75 16.13 33.00 22.20
Fourth quarter 24.63 17.88 33.50 25.50
- --------------------------------------------------------------------------------------------------------------------
1997 annual 24.63 12.00 33.50 16.40
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
________________________________________________________________________________
COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when the financial
statements are affected by conditions and events that cast substantial doubt on
the Company's ability to continue as a going concern, such as those described in
Note 1 to the consolidated financial statements. Our report to the shareholders
dated February 19, 1999 is expressed in accordance with Canadian reporting
standards which do not permit a reference to such events and conditions in the
auditors' report when these are adequately disclosed in the financial
statements.
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
February 19, 1999
F - 29
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Denbury Resources Inc.
We have audited the financial statements of Denbury Resources Inc. as of
December 31, 1998 and 1997, and for each of the three years in the period ended
December 31, 1998, and have issued our report thereon dated February 19, 1999,
such financial statements and report are included elsewhere in this Form 10-K.
Our audits also included the financial statement schedule of Denbury Resources
Inc., listed in Item 14. This financial statement schedule is the responsibility
of the Company's management. Our responsibility is to express an opinion based
on our audits. In our opinion, such financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
February 19, 1999
Note: See separate comments by auditors for U.S. Readers on Canada - U.S.
Reporting Difference on page F-35.
F - 30
<PAGE>
Schedule 1 - Condensed Financial Information of Registrant
DENBURY RESOURCES INC.
UNCONSOLIDATED BALANCE SHEETS
(Amounts in thousands of U.S. dollars)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------
1998 1997
------------- -------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents............................................... $ 20 $ 354
Trade and other receivables............................................. 14 9
------------- -------------
Total current assets ...................................... 34 363
------------- -------------
INVESTMENT IN SUBSIDIARIES (EQUITY METHOD)................................. (32,274) 159,892
OTHER ASSETS............................................................... 1 102
------------- -------------
TOTAL ASSETS................................................. $ (32,239) $ 160,357
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities................................ $ 26 $ 134
SHAREHOLDERS' EQUITY (DEFICIT)
Common shares, no par value
unlimited shares authorized;
outstanding - 26,801,680 shares at December 31, 1998
and 20,388,683 shares at December 31, 1997.......................... 227,796 133,139
Retained earnings (accumulated deficit)................................ (260,061) 27,084
------------- -------------
Total shareholders' equity (deficit)......................... (32,265) 160,223
------------- -------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT).................... $ (32,239) $ 160,357
============= =============
</TABLE>
See Notes to Condensed Financial Statements
F - 31
<PAGE>
Schedule 1 - Condensed Financial Information of Registrant
DENBURY RESOURCES INC.
UNCONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
(U.S. dollars)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1998 1997 1996
-------------- -------------- --------------
REVENUES
<S> <C> <C> <C>
Interest income and other.......................... $ 2 $ 150 $ 179
-------------- -------------- --------------
EXPENSES
General and administrative......................... 177 145 161
Interest........................................... - - 304
Imputed preferred dividends........................ - - 1,281
-------------- -------------- --------------
Total expenses............................... 177 145 1,746
-------------- -------------- --------------
Income (loss) before the following:..................... (175) 5 (1,567)
Equity in net earnings (losses) of subsidiaries... (286,970) 14,898 10,311
-------------- -------------- --------------
Income (loss) before income taxes....................... (287,145) 14,903 8,744
Provision for federal income taxes...................... - - -
-------------- -------------- --------------
NET INCOME (LOSS)....................................... $ (287,145) $ 14,903 $ 8,744
============== ============== ==============
NET INCOME (LOSS) PER COMMON SHARE
Basic.............................................. $ (11.08) $ 0.74 $ 0.67
Fully diluted...................................... (11.08) 0.70 0.62
Average number of common shares outstanding............. 25,926 20,224 13,104
============== ============== =============
</TABLE>
See Notes to Condensed Financial Statements
F - 32
<PAGE>
Schedule 1 - Condensed Financial Information of Registrant
DENBURY RESOURCES INC.
UNCONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of U.S. dollars)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
------------- ----------- -------------
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss)......................................................... $ (287,145) $ 14,903 $ 8,744
Adjustments needed to reconcile to net cash flow provided by
operations:
Imputed preferred dividend.......................................... - - 1,281
Other............................................................... 101 (163) 114
Equity in net (earnings) losses of subsidiaries..................... 286,970 (14,898) (10,311)
------------- ----------- -------------
(74) (158) (172)
Changes in working capital items relating to operations:
Trade and other receivables......................................... (5) (3) -
Accounts payable and accrued liabilities............................ (108) 35 90
------------- ----------- -------------
NET CASH FLOW USED BY OPERATIONS............................................. (187) (126) (82)
------------- ----------- -------------
CASH FLOW FROM INVESTING ACTIVITIES:
Investments in subsidiaries............................................... (94,804) (2,510) (60,316)
Net purchases of other assets............................................. - (100) -
------------- ----------- -------------
NET CASH USED FOR INVESTING ACTIVITIES....................................... (94,804) (2,610) (60,316)
------------- ----------- -------------
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock.................................................. 94,657 2,816 60,664
------------- ----------- -------------
NET CASH PROVIDED BY FINANCING ACTIVITIES.................................... 94,657 2,816 60,664
------------- ----------- -------------
NET INCREASE IN CASH AND CASH EQUIVALENTS.................................... (334) 80 266
Cash and cash equivalents at beginning of year............................... 354 274 8
------------- ----------- -------------
CASH AND CASH EQUIVALENTS AT END OF YEAR..................................... $ 20 $ 354 $ 274
============= =========== =============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for interest.................................... $ - $ - $ 277
</TABLE>
See Notes to Condensed Financial Statements
F - 33
<PAGE>
DENBURY RESOURCES INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL STATEMENTS
Note 1. Basis of Presentation and Financing Requirements
The condensed financial statements have been presented using accounting
principles applicable to a going concern, which assumes that the Company will
continue operations in the foreseeable future and be able to realize assets and
satisfy liabilities in the normal course of business. As of December 31, 1998,
the current value of the reserves of the Company's subsidiary, using the
unescalated 1998 year-end oil and natural gas prices and costs, are insufficient
to repay the subsidiary's senior bank loan, the 9% Senior Subordinated Notes due
2008 and the related interest costs, for all of which the Company is a
guarantor, which casts doubt upon the validity of the going concern assumption.
The Company's ability to continue as a going concern is dependent upon the
completion of the sale of stock to the Texas Pacific Group ("TPG") as described
in Note 6 to the Consolidated Financial Statements and related notes of Denbury
Resources Inc. and Subsidiaries and / or an increase in oil and natural gas
prices. If this proposed sale of stock does not close and / or oil and natural
gas prices do not increase to enable the repayment of the debt and interest
costs, the Company's subsidiary will be in default of covenants of its bank
credit agreement.
If the going concern assumption were not appropriate for these financial
statements, then significant adjustments would be necessary in the carrying
value of assets and liabilities, the reported net loss and the balance sheet
classifications.
Note 2. Accounting Policies
Consolidation - The financial statements of Denbury Resources Inc. have been
prepared in accordance with Canadian generally accepted accounting principles
and reflect the investment in subsidiaries using the equity method.
Income Taxes - No provision for income taxes has been made in the Statement
of Operations because the Company has losses for Canadian tax purposes.
Note 3. Consolidated Financial Statements
Reference is made to the Consolidated Financial Statements and related
notes of Denbury Resources Inc. and Subsidiaries for additional information.
F - 34
<PAGE>
Note 4. Debt and Guarantees
Information on the long-term debt of Denbury Resources Inc. is disclosed in
Note 4 to the Consolidated Financial Statements. Denbury Resources Inc. has
guaranteed the subsidiaries' bank credit line.
Note 5. Dividends Received
Subsidiaries' of Denbury Resources Inc. do not make formal cash dividend
declarations and distributions to the parent and are currently restricted from
doing so under the subsidiaries bank loan agreement.
________________________________________________________________________________
COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when the financial
statements are affected by conditions and events that cast substantial doubt on
the Company's ability to continue as a going concern, such as those described in
Note 1 to the financial statements. Our report to the shareholders dated
February 19, 1999 is expressed in accordance with Canadian reporting standards
which do not permit a reference to such events and conditions in the auditors'
report when these are adequately disclosed in the financial statements.
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
February 19, 1999
F - 35
<PAGE>
EXHIBIT INDEX
-------------
Exhibit No. Exhibit
- ----------- -------
10(m)* Fourth Amendment to First Restated Credit Agreement, by
and among Denbury Management, as borrower, Denbury
Resources Inc., as guarantor, NationsBank of Texas,
N.A., as administrative agent, and NationsBank of
Texas, N.A., as bank, entered into as of February 19,
1999.
11* Statement re-computation of per share earnings.
12* Statement of Ratio of Earnings to Fixed Charges.
23* Consent of Deloitte & Touche LLP
27* Financial Data Schedule.
* Filed herewith.
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EXHIBIT 10(M)
FOURTH AMENDMENT TO FIRST RESTATED CREDIT AGREEMENT
---------------------------------------------------
This Fourth Amendment to First Restated Credit Agreement (this "Fourth
Amendment") is entered into on February 19, 1999, to be effective in accordance
with Section 5 hereof, by and among DENBURY MANAGEMENT, INC., a Texas
corporation ("Borrower"), DENBURY RESOURCES, INC., a corporation incorporated
under the Canadian Business Corporations Act ("Parent"), NATIONSBANK, N.A.,
successor by merger to NationsBank of Texas, N.A., as Administrative Agent
("Administrative Agent"), and the financial institutions parties hereto as Banks
("Executing Banks").
W I T N E S S E T H:
WHEREAS, Borrower, Parent, Administrative Agent and Executing Banks are
parties to that certain First Restated Credit Agreement dated as of December 29,
1997, as amended by (a) that certain First Amendment to First Restated Credit
Agreement dated as of January 27, 1998, (b) that certain Second Amendment to
First Restated Credit Agreement dated as of February 25, 1998, and (c) that
certain Third Amendment to First Restated Credit Agreement dated as of August
10, 1998 (as amended, the "Credit Agreement") (unless otherwise defined herein,
all terms used herein with their initial letter capitalized shall have the
meaning given such terms in the Credit Agreement); and
WHEREAS, pursuant to the Credit Agreement the Banks have made certain Loans
to Borrower; and
WHEREAS, Borrower has requested that Banks (a) amend certain terms of the
Credit Agreement in certain respects, and (b) establish a Borrowing Base of
$110,000,000 to be effective February 19, 1999, and continuing until the first
Redetermination thereafter; and
WHEREAS, subject to the terms and conditions herein contained, Executing
Banks have agreed to Borrower's request.
NOW THEREFORE, for and in consideration of the mutual covenants and
agreements herein contained and other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged and confessed,
Borrower, Parent, Administrative Agent and each Executing Bank hereby agree as
follows:
Section 4. Amendments. The Credit Agreement is hereby amended effective as of
December 31, 1998 in the manner provided in this Section 1.
4.1 Additional Definitions. Section 1.1 of the Credit Agreement is amended
to add thereto in alphabetical order the definitions of "Fourth Amendment,"
"Proposed Equity Contribution,"
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"Proxy Statement/Prospectus," "Qualified Purpose," "Security Documents," "Stock
Purchase Agreement" and "Stock Purchase Documents" which shall read in full as
follows:
"Fourth Amendment" means that certain Fourth Amendment to First
Restated Credit Agreement dated February 19, 1999 among Borrower,
Administrative Agent and Banks.
"Proposed Equity Contribution" means the proposed purchase by Texas
Pacific Group from Parent of shares of common stock of Parent substantially
on the terms set forth in the Proxy Statement/Prospectus and the Stock
Purchase Documents resulting in (a) gross cash proceeds to Parent of not less
than $100,000,000 and (b) net cash proceeds to Parent of not less than
$98,000,000.
"Proxy Statement/Prospectus" means the Registration Statement, Proxy
Statement and Prospectus which were filed by Parent in preliminary form and
subject to completion with the Securities and Exchange Commission on January
19, 1999 under Registration No. 333-69577.
"Qualified Purpose" means (i) the purchase by Borrower of Proved
Mineral Interests, or (ii) capital expenditures made by Borrower to maintain,
enhance or develop Proved Mineral Interests owned by Borrower; provided,
that, the portion of the aggregate amount of all Borrowings made during any
period during which Section 9.15 is in effect hereunder which is utilized to
purchase Proved Mineral Interests which is in excess of the "qualified
amount" will not be deemed to be utilized for a "Qualified Purpose." As used
herein, "qualified amount" means, with respect to Proved Mineral Interests
acquired with the proceeds of Borrowings made during any period during which
Section 9.15 is in effect hereunder, an amount equal to two hundred percent
(200%) of the Recognized Value of that portion of such Proved Mineral
Interests which constitute Proved Producing Mineral Interests.
"Security Documents" has the meaning set forth in Section 5.2.
"Stock Purchase Agreement" means that certain Stock Purchase Agreement,
dated as of December 16, 1998, by and between Parent and TPG Partners II,
L.P., and all amendments thereto (to the extent permitted hereunder).
"Stock Purchase Documents" means the Stock Purchase Agreement and each
other document, instrument and agreement now or hereafter executed and
delivered by or among Borrower, Parent, Texas Pacific Group and TPG Partners
II, L.P. pursuant to the Stock Purchase Agreement.
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4.2 Amendment to Definitions. The definitions of "Applicable Margin,"
"Commitment Fee Percentage," "Letter of Credit Fee," "Loan Papers,"
"Non-Conforming Margin," Recognized Value" and "Required Consolidated Tangible
Net Worth" set forth in Section 1.1 of the Credit Agreement are amended to read
in full as follows:
"Applicable Margin" means, on any date, with respect to each Eurodollar
Loan, an amount determined by reference to the ratio of Outstanding Credit to
the Conforming Borrowing Base on such date in accordance with the table
below:
Ratio of Outstanding Applicable Margin for
Credit to Conforming Borrowing Eurodollar Loans
Base
- ------------------------------ ---------------------
<= .50 to 1 1.000%
> .50 to 1 and <= .75 to 1 1.250%
> .75 to 1 and <= .90 to 1 1.500%
> .90 to 1 and <= 1.0 to 1 1.750%
> 1.0 to 1 Non Conforming Margin
"Commitment Fee Percentage" means, on any date, an amount determined by
reference to the ratio of Outstanding Credit to the Conforming Borrowing Base
on such date in accordance with the table below:
Ratio of Outstanding
Credit to Conforming Borrowing Commitment Fee Percentage
Base
- ------------------------------ -------------------------
<= .50 to 1 .350%
> .50 to 1 and <= .75 to 1 .375%
> .75 to 1 and <= .90 to 1 .500%
> .90 to 1 and <= 1.0 to 1 .500%
> 1.0 to 1 .500%
"Letter of Credit Fee" means, with respect to any Letter of Credit
issued hereunder, a fee in an amount equal to the greater of (a) $500, or (b)
a percentage of the stated amount of such Letter of Credit (calculated on a
per annum basis based on the stated term of such Letter of Credit) determined
by reference to the ratio of Outstanding Credit to the Conforming Borrowing
Base in effect on the date such Letter of Credit is issued in accordance with
the table below:
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Ratio of Outstanding Per Annum Letter of
Credit to Conforming Borrowing Credit Fee
Base
- ------------------------------ -------------------
<= .50 to 1 1.000%
> .50 to 1 and <= .75 to 1 1.250%
> .75 to 1 and <= .90 to 1 1.500%
> .90 to 1 and <= 1.0 to 1 1.750%
> 1.0 to 1 Non Conforming Margin
"Loan Papers" means this Agreement, the First Amendment, the Second
Amendment, the Third Amendment, the Fourth Amendment, the Notes, the Facility
Guarantees, the Parent Pledge Agreement, the Existing Mortgages (as amended
by the Amendment to Mortgages), each Security Document now or at any time
hereafter delivered pursuant to Section 5.2, and all other certificates,
documents or instruments delivered in connection with this Agreement, as the
foregoing may be amended from time to time.
"Non-Conforming Margin" means 2.125%.
"Recognized Value" means, with respect to Mineral Interests, the
discounted present value of the estimated net cash flow to be realized from
the production of Hydrocarbons from such Mineral Interests as determined by
NationsBank, N.A. for purposes of determining the portion of the Borrowing
Base which it attributes to such Mineral Interests in accordance with Article
IV hereof.
"Required Consolidated Tangible Net Worth" means, (a) as of June 30,
1999, the sum of (i) Parent's Consolidated Tangible Net Worth as of December
31, 1998 plus (ii) an amount equal to sixty percent (60%) of the Net Cash
Proceeds received by Parent from any issuance by Parent of its equity
securities after January 1, 1999 and on or prior to June 30, 1999 (including
pursuant to the Proposed Equity Contribution) (the sum of (i) and (ii)
preceding is referred to herein as the "June 30, 1999 Required Net Worth"),
and (b) from and after (but excluding), June 30, 1999, "Required Consolidated
Tangible Net Worth" shall increase (but not decrease) above the Required
Consolidated Tangible Net Worth previously in effect pursuant to this
definition (i) on each Quarterly Date by an amount equal to fifty percent
(50%) of Parent's Consolidated Net Income for the Fiscal Quarter then ended,
and (ii) on the date of issuance by Parent of its equity securities by amount
equal to fifty percent (50%) of the net proceeds received by Parent from the
issuance of such securities. Notwithstanding anything to the contrary
contained herein, in no event will Required
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Consolidated Tangible Net Worth be less than $25,000,000.
4.3 Amendment to Mandatory Prepayment Provision. Section 2.6 of the Credit
Agreement is amended to add the following sentence thereto:
"Simultaneously with the consummation of the Proposed Equity
Contribution, Borrower shall make a mandatory prepayment of the Revolving
Loan in the amount of the Net Cash Proceeds resulting from such Proposed
Equity Offering."
4.4 Amendment to Security Provisions. Article V of the Credit Agreement is
amended to read in full as follows:
ARTICLE V
COLLATERAL AND GUARANTEES
SECTION 5.1. Required Security. The Obligations shall be secured by (a)
first priority perfected Liens on one hundred percent (100%) of the issued
and outstanding capital stock of every class of Borrower, and (b) first
priority perfected Liens on such Proved Mineral Interests owned by Borrower
as Administrative Agent shall require but which shall, in all events, include
Proved Mineral Interests with a Recognized Value representing not less than
eighty five percent (85%) of the Recognized Value of all Proved Mineral
Interests evaluated by Banks for purposes of determining the Borrowing Base;
provided, that, from and after the occurrence of a Borrowing Base Deficiency,
a Default or an Event of Default, the Obligations shall be secured by first
priority perfected Liens on one hundred percent (100%) of all Mineral
Interests owned by Borrower.
SECTION 5.2. Security Documents. Not later than March 1, 1999 and
thereafter simultaneously with any Redetermination or the occurrence of any
Default or Event of Default, and at such other times as Administrative Agent
or Required Banks shall request, Borrower shall execute and deliver, and
cause Parent to execute and deliver, to Administrative Agent such deeds of
trust, mortgages, security agreements, assignments, financing statements,
pledge agreements, collateral assignments and other documents, instruments
and agreements (including, without limitation, any modifications, amendments,
supplements, restatements, renewals or extensions of any of the foregoing) as
Administrative Agent shall request to fully create, evidence and perfect the
liens and security interests required by Section 5.1 (collectively, the
"Security Documents").
SECTION 5.3. Evidence of Existence, Authority, Proper Execution and
Delivery and Title; Opinions. At any time Parent or Borrower is required to
execute and deliver Security Documents pursuant to Section 5.2, Parent or
Borrower, as applicable, shall also deliver to Administrative Agent and its
counsel (a) such certificates of Authorized Officers of Parent and Borrower,
certificates of
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<PAGE>
Governmental Authorities, resolutions of the Boards of Directors of Parent
and Borrower, certified copies of the charter and bylaws of Parent and
Borrower and other documents, instruments and agreements as Administrative
Agent shall require to evidence (i) the valid corporate existence and
authority to transact business of Parent and Borrower, and (ii) the due
authorization, execution and delivery of the Security Documents by Parent and
Borrower, (b) opinions of counsel (addressed to Administrative Agent) or
other evidence of title as Administrative Agent shall require to verify
Borrower's title to all Proved Mineral Interests subject to the Liens of such
Security Documents and the priority of such Liens, and (c) opinions of
counsel addressed to Administrative Agent favorably opining as to the due
authorization, execution, delivery and enforceability of such Security
Documents and such other matters related to Borrower, Parent and such
Security Documents as Administrative Agent shall require.
SECTION 5.4. Guarantees. Payment and performance of the Obligations
shall be guaranteed by Parent pursuant to the Facility Guaranty duly executed
and delivered by Parent.
4.5 Amendment to Asset Disposition Covenant. Subclause (b) of Section 9.5 of
the Credit Agreement is amended to read in full as follows:
"(b) the sale, lease, transfer, abandonment, exchange or other
disposition of other assets, provided that the aggregate value (which, in the
case of assets consisting of Mineral Interests, shall be the Recognized Value
of such Mineral Interests and in the case of any exchange, shall be the net
value or net Recognized Value realized or resulting from such exchange) of
all assets sold, leased, transferred, abandoned, exchanged or disposed of
pursuant to this clause (b) in any period between Scheduled Redeterminations
shall not exceed five percent (5%) of the Conforming Borrowing Base then in
effect (for purposes of this clause (b) the Closing Date will be deemed to be
a Scheduled Redetermination)."
4.6 Amendment to Hedge Transaction Covenant. Section 9.11 of the Credit
Agreement is amended to delete "seventy five percent (75%)" and to insert in
lieu thereof "eighty five percent (85%)."
4.7 Amendments to Stock Purchase Agreement; Qualified Purpose. Article IX of
the Credit Agreement is amended to add thereto the following additional Sections
9.14 and 9.15 which shall read in full as follows:
"SECTION 9.14. Amendments to Stock Purchase Agreement. The Credit
Parties will not, nor will the Credit Parties permit any of their
Subsidiaries to, enter into or permit any modification or amendment of, or
waive any provision of the Stock Purchase Agreement or any other Stock
Purchase Document or any of their respective rights thereunder if the effect
of such amendment, modification or waiver is to (a) extend the "Closing Date"
as defined in the Stock Purchase Agreement,
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<PAGE>
(b) decrease the "Buyer Purchase Price" as defined in the Stock Purchase
Agreement, (c) alter the investment from a cash investment in common stock,
or (d) in any other manner result in, or be reasonably expected to result in,
a Material Adverse Effect.
SECTION 9.15. Qualified Purpose. Borrower will not request or receive
any Borrowing hereunder if, after giving effect thereto and the use of the
proceeds thereof, that portion of the principal balance of the Revolving Loan
which is outstanding at such time and was utilized for any purpose other than
a Qualified Purpose exceeds twenty five percent (25%) of the Borrowing Base
in effect at such time. Borrower agrees that each Request for Borrowing will
include in addition to the information described in Section 2.2 hereof, a
certification from an Authorized Officer of Borrower as to the purpose and
utilization of the proceeds of such Borrowing. Additionally, notwithstanding
anything to the contrary contained in Section 3.2 hereof, all principal
payments received by Banks with respect to the Revolving Loan shall be
applied first to that portion of the outstanding principal balance of the
Revolving Loan utilized for purposes other than Qualified Purposes.
Notwithstanding the foregoing, the Credit Parties shall not be required to
comply with this Section 9.15 at any time (a) on or prior to the date Texas
Pacific Group makes the Proposed Equity Contribution (and Parent, in turn,
contributes the proceeds of such Proposed Equity Contribution to the common
equity capital of Borrower), and (b) that the Borrowing Base is equal to the
Conforming Borrowing Base. Any principal outstanding under the Revolving Loan
immediately after giving effect to receipt and application of the proceeds of
the Proposed Equity Contribution (as required pursuant to Section 2.6) shall
be deemed to be utilized for a Qualified Purpose.
4.8 Minimum Consolidated Tangible Net Worth. Section 10.2 of the Credit
Agreement is amended to read in full as follows:
"SECTION 10.2. Minimum Consolidated Tangible Net Worth. The Credit
Parties will not permit Parent's Consolidated Tangible Net Worth to be less
than the Required Consolidated Tangible Net Worth on any Quarterly Date on or
after June 30, 1999."
4.9 Consolidated EBITDA to Consolidated Net Interest Expense. Section 10.3 of
the Credit Agreement is amended to read in full as follows:
"SECTION 10.3. Consolidated EBITDA to Consolidated Net Interest
Expense. The Credit Parties will not permit Parent's Ratio of Consolidated
EBITDA to Consolidated Net Interest Expense to be less than (i) 2.0 to 1.0
for (a) the Fiscal Quarter ending on September 30, 1999, (b) the period of
two (2) consecutive Fiscal Quarters ending on December 31, 1999, (c) the
period of three (3) consecutive Fiscal Quarters ending on March 31, 2000, and
(d) the periods of four (4) consecutive Fiscal Quarters ending on each of
June 30, 2000 and September 30, 2000; (ii) 2.25 to 1.0
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<PAGE>
for the periods of four (4) consecutive Fiscal Quarters ending on each of
December 31, 2000 and March 31, 2001; and (iii) 2.5 to 1.0 for any period of
four (4) consecutive Fiscal Quarters ending on or after June 30, 2001."
4.10 Amendment to Events of Default. Section 11.1 of the Credit Agreement is
amended (a) to delete the word "or" at the end of clause (k) thereof, and (b) to
insert new clauses (m) and (n) which shall read in full as follows:
"(m) Texas Pacific Group shall fail, for any reason, to make the
Proposed Equity Contribution on or before the earlier of (i) the forty fifth
(45th) day following the date on which the Proxy Statement/Prospectus is
declared effective by the Securities and Exchange Commission, or (ii) June
16, 1999; or
"(n) the Stock Purchase Agreement shall, for any reason, terminate or
otherwise cease to be in full force or effect, or Texas Pacific Group shall
deliver any notice of termination or intent to terminate or any other notice
stating its intent to not complete the Proposed Equity Contribution on or
before the Closing Date therein specified;"
Section 5. Certain Agreements Regarding the Borrowing Base and the Conforming
Borrowing Base. Borrower, Parent, Administrative Agent and each Bank agree that
the Borrowing Base and the Conforming Borrowing Base in effect for the period
from and after February 19, 1999 until the next Redetermination thereafter shall
be $110,000,000 and $60,000,000, respectively. Borrower acknowledges that
Required Banks have approved such Borrowing Base and Conforming Borrowing Base
based on the expectation that on or before June 16, 1999 Texas Pacific Group
will make the Proposed Equity Contribution. Borrower, Administrative Agent and
Banks agree that the Redetermination provided for in this Section 2 shall not be
construed to be a Special Redetermination for purposes of Section 4.4 of the
Credit Agreement.
Section 6. Extension and Waiver of April 1, 1999 Scheduled Redetermination.
Borrower, each Bank and Administrative Agent hereby agree to postpone, until
June 16, 1999, the Scheduled Redetermination of the Borrowing Base and the
Conforming Borrowing Base scheduled to occur on or promptly following April 1,
1999 (the "April 1, 1999 Redetermination"). Borrower, each Bank and such
Administrative Agent further agree to waive the April 1, 1999 Redetermination;
provided, that waiver is subject to the condition precedent that Texas Pacific
Group makes the Proposed Equity Contribution on or before June 16, 1999 (and
Parent, in turn, contributes the proceeds of such Proposed Equity Contribution
to the common equity capital of Borrower). In the event Texas Pacific Group does
not make the Proposed Equity Contribution on or before June 16, 1999, the
foregoing waiver will be of no force or effect and Banks may make such Scheduled
Redetermination on or promptly following June 16, 1999 in accordance with the
provisions of Article IV of the Credit Agreement, but giving effect to the
failure of Texas Pacific Group to make the Proposed Equity Contribution.
Section 7. Agreements Regarding Consent Letter. Reference is hereby made to
that certain letter agreement dated as of November 30, 1998 by and among
Administrative Agent,
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<PAGE>
Borrower and Banks pursuant to which Banks granted their consent to the
consummation by Parent and Borrower of the "Emigration Transaction" (as therein
defined) (the "Emigration Consent Letter"). Pursuant to the Emigration Consent
Letter, Borrower, Administrative Agent and Banks agreed that, upon the
completion of the Emigration Transaction, Borrower, Administrative Agent and
Banks will enter into a Fourth Amendment to Credit Agreement in the form
attached as Exhibit A to the Emigration Consent Letter (the Fourth Amendment to
Credit Agreement attached to, and to be executed pursuant to, the Emigration
Consent Letter is referred to herein as the "Contemplated Amendment"). Borrower,
Administrative Agent, and Banks reaffirm their obligations under the Emigration
Consent Letter including the obligation to enter into the Contemplated
Amendment; provided, that Borrower, Administrative Agent and Banks further agree
that certain conforming revisions will be made to the Contemplated Amendment
when executed to give effect to this Fourth Amendment. Such conforming revisions
will (a) include revisions to reflect that the Contemplated Amendment is the
fifth amendment to the Credit Agreement (not the Fourth Amendment), and (b) give
effect to the amendments to Article V, Article IX, and to Sections 1.1, 2.6,
9.5, 9.7, 9.11, 10.2, 10.3 and 11.1 of the Credit Agreement contained in this
Fourth Amendment.
Section 8. Effectiveness of Amendment. With the exception of Section 3
hereof, this Fourth Amendment shall be effective automatically and without the
necessity of any further action by Administrative Agent, Parent, Borrower or any
Bank when counterparts hereof have been executed by Administrative Agent,
Parent, Borrower and Required Banks; provided, that upon such execution, the
amendments contained in Section 1 hereof will be deemed to be effective as of
December 31, 1998. Section 3 hereof will be effective automatically and without
the necessity of any further action on the part of Administrative Agent, Parent,
Borrower or any Bank when counterparts hereof have been executed by
Administrative Agent, Parent, Borrower and all Banks.
Section 9. Closing Deliveries. Simultaneously with their execution and
delivery hereof, Parent and Borrower shall deliver to Administrative Agent: (a)
such certificates of Authorized Officers of Parent and Borrower, certificates of
Governmental Authorities, certified copies of the charter and by-laws of Parent
and Borrower, certified copies of resolutions of the Boards of Directors of
Parent and Borrower and such other documents, instruments and agreements as
Administrative Agent shall require to evidence the valid corporate existence and
authority to conduct business of Parent and Borrower and the due authorization,
execution and delivery of this Fourth Amendment by Parent and Borrower, and (b)
opinions of Jenkens & Gilchrist and Burnet, Duckworth & Palmer, counsel to
Parent and Borrower, with respect to the due authorization, execution, delivery
and enforceability of this Fourth Amendment and such other matters related
thereto as Administrative Agent shall require. The failure of Parent and
Borrower to timely comply with this Section 6 shall constitute an Event of
Default under and for all purposes of this Fourth Amendment and the other Loan
Papers.
Section 10. Amendment Fee. Upon execution of this Fourth Amendment by
Required Banks, Borrower shall pay to Administrative Agent for the ratable
benefit of Executing Banks (determined in the manner set forth below) a fee in
the aggregate amount of $275,000. Such fee shall be distributed by
Administrative Agent to each Executing Bank (provided that such Executing Bank
executes and delivers this Fourth Amendment on or before February 19, 1999)
ratably based on the
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percentage, expressed as a decimal, determined by dividing the Commitment
Percentage of such Executing Bank by the aggregate Commitment Percentages of all
Executing Banks.
Section 11. Representations and Warranties of Borrower. To induce Banks and
Administrative Agent to enter into this Fourth Amendment, Borrower and Parent
hereby represent and warrant to Administrative Agent and Banks as follows:
11.1 Reaffirmation of Representations and Warranties. Each representation and
warranty of Borrower and Parent contained in the Credit Agreement and the other
Loan Papers is true and correct on the date hereof and will be true and correct
after giving effect to the amendments set forth in Section 1 hereof.
11.2 Due Authorization, No Conflicts. The execution, delivery and performance
by Borrower and Parent of this Fourth Amendment are within Borrower's and
Parent's corporate powers, have been duly authorized by necessary action,
require no action by or in respect of, or filing with, any governmental body,
agency or official and do not violate or constitute a default under any
provision of applicable law or any Material Agreement binding upon Borrower, the
Subsidiaries of Borrower or Parent or result in the creation or imposition of
any Lien upon any of the assets of Borrower or the Subsidiaries of Borrower or
Parent except Permitted Encumbrances.
11.3 Validity and Binding Effect. This Fourth Amendment constitutes the valid
and binding obligations of Borrower and Parent enforceable in accordance with
its terms, except as (i) the enforceability thereof may be limited by
bankruptcy, insolvency or similar laws affecting creditor's rights generally,
and (ii) the availability of equitable remedies may be limited by equitable
principles of general application.
11.4 No Defenses. Borrower and Parent have no defenses to payment,
counterclaim or rights of set-off with respect to the Obligations existing on
the date hereof.
Section 12. Miscellaneous.
12.1 Reaffirmation of Loan Papers; Extension of Liens. Any and all of the
terms and provisions of the Credit Agreement and the Loan Papers shall, except
as amended and modified hereby, remain in full force and effect. Borrower hereby
extends the Liens securing the Obligations until the Obligations have been paid
in full or are specifically released by Administrative Agent and Banks prior
thereto, and agree that the amendments and modifications herein contained shall
in no manner adversely affect or impair the Obligations or the Liens securing
payment and performance thereof.
12.2 Parties in Interest. All of the terms and provisions of this Fourth
Amendment shall bind and inure to the benefit of the parties hereto and their
respective successors and assigns.
12.3 Legal Expenses. Borrower hereby agrees to pay on demand all reasonable
fees
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and expenses of counsel to Administrative Agent incurred by Administrative
Agent, in connection with the preparation, negotiation and execution of this
Fourth Amendment and all related documents.
12.4 Counterparts. This Fourth Amendment may be executed in counterparts, and
all parties need not execute the same counterpart; however, no party shall be
bound by this Fourth Amendment until counterparts hereof have been executed by
the parties specified in Section 5 hereof.
Facsimiles shall be effective as originals.
12.5 Complete Agreement. THIS FOURTH AMENDMENT, THE CREDIT AGREEMENT AND THE
OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE
PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
12.6 Headings. The headings, captions and arrangements used in this Fourth
Amendment are, unless specified otherwise, for convenience only and shall not be
deemed to limit, amplify or modify the terms of this Fourth Amendment, nor
affect the meaning thereof.
IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to
be duly executed by their respective Authorized Officers on the date and year
first above written.
BORROWER:
---------
DENBURY MANAGEMENT, INC.,
a Texas corporation
By:
-----------------------------------
Gareth Roberts
President and Chief Executive Officer
By:
-----------------------------------
Phil Rykhoek
Chief Financial Officer and Secretary
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PARENT:
-------
DENBURY RESOURCES, INC., a corporation
incorporated under the Canadian Business
Corporations Act
By:
-----------------------------------
Gareth Roberts
President and Chief Executive Officer
By:
-----------------------------------
Phil Rykhoek
Chief Financial Officer and Secretary
ADMINISTRATIVE AGENT:
---------------------
NATIONSBANK, N.A.,
successor by merger to
NationsBank of Texas, N.A.
By:
-----------------------------------
Scott Fowler
Vice president
BANKS:
------
NATIONSBANK, N.A.,
successor by merger to
NationsBank of Texas, N.A.
By:
-----------------------------------
Scott Fowler
Vice president
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BANKBOSTON, N.A.
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
BANK ONE, TEXAS, N.A.
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
CHASE BANK OF TEXAS, NATIONAL ASSOCIATION
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
CHRISTIANAIA BANK, OG KREDITKASSE ASA
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
BANQUE PARIBAS
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
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CREDIT LYONNAIS - NEW YORK BRANCH
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
WELLS FARGO BANK (TEXAS), N.A.
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
NATEXIS BANQUE BFCE
By:
-----------------------------------
Name:
-----------------------------------
Title:
-----------------------------------
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EXHIBIT 11
DENBURY RESOURCES INC.
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
1998 1997 1996
------------- ---------- ---------
CANADIAN GAAP (Amounts in thousands except per
------------- share amounts)
Basic EPS:
- ----------
<S> <C> <C> <C>
Weighted average shares outstanding 25,926 20,224 13,104
============= ========== =========
Net income (loss) $ (287,145) $ 14,903 $ 8,744
============= ========== =========
Basic earnings (loss) per common share $ (11.08) $ 0.74 $ 0.67
============= ========== =========
Fully Diluted EPS:
- ------------------
Weighted average shares outstanding 25,926 20,224 13,104
Assumed conversions:
Convertible debentures (b) (b) 391
Warrants (a) 700 750
Stock options (a) 1,550 1,053
Convertible preferred (b) (b) (a)
------------- ---------- ---------
Adjusted shares outstanding 25,926 22,474 15,298
------------- ---------- ---------
Net income (loss) $ (287,145) $ 14,903 $ 8,744
Adjustments:
Interest on subordinated debentures (b) (b) 126
Interest on warrant proceeds (a) 169 245
Interest on option proceeds (a) 572 365
Imputed preferred dividend (b) (b) (a)
------------- ---------- ---------
Adjusted net income (loss) $ (287,145) $ 15,644 $ 9,480
------------- ---------- ---------
Fully diluted earnings (loss) per common share $ (11.08) $ 0.70 $ 0.62
============= ========== =========
<FN>
(a) Anti-dilutive or immaterial
(b) Not applicable for this period
</FN>
</TABLE>
-1-
<PAGE>
EXHIBIT 11
DENBURY RESOURCES INC.
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1998 1997 1996
------------- --------- ---------
U.S. GAAP (Amounts in thousands except per
--------- share amounts)
Basic EPS:
- ----------
<S> <C> <C> <C>
Weighted average shares outstanding 25,926 20,224 13,104
============= ========= =========
Net income (loss) $ (287,145) $ 14,903 $ 8,744
============= ========= =========
Basic earnings (loss) per common share $ (11.08) $ 0.74 $ 0.67
============= ========= =========
Diluted EPS:
- ------------
Weighted average shares outstanding 25,926 20,224 13,104
Net adjustments to shares after repurchases with proceeds:
Convertible debentures (b) (b) 391
Warrants (a) 428 402
Stock options (a) 793 397
Convertible preferred (b) (b) (a)
------------- --------- ---------
Adjusted shares outstanding 25,926 21,445 14,294
------------- --------- ---------
Net income (loss) $ (287,145) $ 14,903 $ 8,744
Adjustments:
Interest on subordinated debentures (b) (b) 220
Imputed preferred dividend (b) (b) (a)
------------- --------- ---------
Adjusted net income (loss) $ (287,145) $ 14,903 $ 8,964
------------- --------- ---------
Diluted earnings (loss) per common share $ (11.08) $ 0.70 $ 0.63
============= ========= =========
<FN>
(a) Anti-dilutive or immaterial
(b) Not applicable for this period
</FN>
</TABLE>
-2-
EXHIBIT 12
DENBURY RESOURCES INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1998 1997 1996
------------ ----------- ------------
(Amounts in thousands)
Earnings:
<S> <C> <C> <C>
Pretax income (loss) from continuing operations $ (302,765) $ 23,798 $ 14,056
Fixed charges 17,758 1,262 4,080
------------ ----------- ------------
Earnings (losses) $ (285,007) $ 25,060 $ 18,136
============ =========== ============
Fixed Charges:
Interest expense $ 17,534 $ 1,111 $ 1,993
Interest component of rent expense 224 151 116
Imputed preferred dividend - - 1,281
Preferred dividend tax effect - - 690
------------ ----------- ------------
Fixed charges $ 17,758 $ 1,262 $ 4,080
============ =========== ============
Ratio of earnings to fixed charges (a) 19.9 4.4
<FN>
(a) For the year ended December 31, 1998, a pre-tax loss of $(302,765) was
insufficient to cover fixed charges of $17,758.
</FN>
</TABLE>
-1-
EXHIBIT 23
DENBURY RESOURCES INC.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in the Registration Statements of
Denbury Resources Inc. on Forms S-8 (Registration No-333-1006, 333-27995 and
333-70485) of our reports dated February 19, 1999 (which express an unqualified
opinion and for U.S. Readers had a Canada-U.S. reporting difference which would
require the addition of an explanatory paragraph (following the opinion
paragraph) relating to the Company's ability to continue as a going concern),
with respect to the consolidated financial statements and schedule of Denbury
Resources Inc. appearing in the Annual Report on Form 10-K of Denbury Resources
Inc. for the year ended December 31, 1998.
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
March 1, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE DENBURY
RESOURCES INC. DECEMBER 31, 1998 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000945764
<NAME> Denbury Resources Inc.
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,049
<SECURITIES> 0
<RECEIVABLES> 21,885
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 23,934
<PP&E> 574,216
<DEPRECIATION> (393,552)
<TOTAL-ASSETS> 212,859
<CURRENT-LIABILITIES> 18,688
<BONDS> 0
0
0
<COMMON> 227,796
<OTHER-SE> (260,061)
<TOTAL-LIABILITY-AND-EQUITY> 212,859
<SALES> 81,883
<TOTAL-REVENUES> 83,506
<CGS> 0
<TOTAL-COSTS> 368,737
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,534
<INCOME-PRETAX> (302,765)
<INCOME-TAX> (15,620)
<INCOME-CONTINUING> (287,145)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (287,145)
<EPS-PRIMARY> (11.08)
<EPS-DILUTED> (11.08)
</TABLE>
