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, 1997
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 (I.R.S. Employer
jurisdiction Identification No.)
of incorporation or
organization)
17304 Preston Rd.,Suite 200 75252
Dallas, TX
(Address of principal (Zipcode)
executive offices)
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 March 16, 1998, the aggregate market value of the registrant's Common
Shares held by non-affiliates was approximately $272,000,000.
The number of shares outstanding of the registrant's Common Shares as of
March 16, 1998, was 26,598,413.
DOCUMENTS INCORPORATED BY REFERENCE
Document Incorporated as to
1.Notice and Proxy Statement for the 1. Part III, Items 10, 11,
Annual Meeting of Shareholders to be held 12, and 13
May 19, 1998
2.Annual Report to Shareholders for the 2. Part I, Item 1 and Part
year ended December 31, 1997 II, Items 5, 6, 7, 8
<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. and its Canadian office is located at 2550, 140--4th Avenue S.W.,
Calgary, Alberta T2P 3N3. At December 31, 1997, the Company had 157 employees,
66 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 2,771,530 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.
The Denbury Acquisition signaled a new direction for the Company and added a new
geographic area of operation (the states of Texas, Louisiana and Mississippi),
and management expertise to the Company. 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 through its
subsidiary, Denbury Management.
Since 1993, after having disposed of its Canadian oil and natural gas
properties, the Company has focused its operations primarily onshore in
Louisiana and Mississippi. Over the last four years, the Company has achieved
rapid growth in proved reserves, production and cash flow by concentrating on
the acquisition of properties which it believes have significant upside
potential and through the efficient development, enhancement and operation of
those properties.
Business Strategy
Information as to the Company's business strategy is set forth under
"Company Business Strategy", appearing on Page 10 of the Annual Report. Such
information is incorporated herein by reference.
2
<PAGE>
Acquisitions of Oil and Gas Properties
Information as to recent acquisitions by the Company is set forth under
"Acquisition of Oil and Natural Gas Properties", appearing on page 9 of the
Annual Report. Such information is incorporated herein by reference.
Oil and Gas Operations
Information regarding selected operating data and a discussion of the Company's
two significant operating areas and the primary properties within those two
areas is set forth under "Selected Operating Data", "Operations in Southern
Louisiana" and "Operations in Mississippi", appearing on pages 6 and 7 and pages
12 through 18 of the Annual Report. Such information is incorporated herein by
reference.
Oil and Gas Acreage
The following table sets forth Denbury's acreage position at December 31,
1997:
<TABLE>
<CAPTION>
Developed Undeveloped
------------------------- ----------------------
Gross Net Gross Net
----------- ----------- ---------- ---------
<S> <C> <C> <C> <C>
Louisiana 28,458 19,813 19,859 8,693
Mississippi 17,584 12,913 26,038 10,610
----------- ----------- ---------- ---------
Total 46,042 32,726 45,897 19,303
=========== =========== ========== =========
</TABLE>
Productive Wells
This table sets forth both the gross and net productive wells of the
Company at December 31, 1997:
<TABLE>
<CAPTION>
Producing Oil Wells Producing Gas Wells Total
------------------ ------------------ -----------------
Gross Net Gross Net Gross Net
-------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Louisiana 40 25.7 70 43.2 110 68.9
Mississippi 276 247.2 21 7.2 297 254.4
-------- ------- ------- ------- ------- -------
Total 316 272.9 91 50.4 407 323.3
======== ======= ======= ======= ======= =======
</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, 1997.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1997 1996 1995
------------ ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ------ ----- ----- ------
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells: (1)
Productive (2)........... 2 0.7 - - - -
Nonproductive (3)........ 7 2.3 1 1.0 2 1.0
Development Wells: (1)
Productive (2)........... 33 22.5 9 7.9 2 1.5
Nonproductive (3)........ 2 0.8 - - - -
----- ----- ------ ----- ----- ------
Total............. 44 26.3 10 8.9 4 2.5
===== ===== ====== ===== ===== ======
<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 six wells in the process of drilling at December 31, 1997.
3
<PAGE>
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 natual gas properties, some of
which are subject to minor encumbrances, easements and restrictions.
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, 1997. "Net" production is production
that is owned by the Company and produced for its interest after deducting
royalties and other similar interests.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------
1997 1996 1995
-------- ------- -------
<S> <C> <C> <C>
Net production volume
Crude oil - (MBbls) 2,884 1,500 728
Natural gas - (MMcf) 13,257 8,933 4,844
Equivalent - MBOE (1) 5,094 2,989 1,535
Average sales price
Crude oil - ($/Bbl) $ 17.25 $ 18.98 $14.90
Natural gas - ($/Mcf) 2.68 2.73 1.90
Per equivalent BOE (1) 16.75 17.69 13.05
Average production cost
Per equivalent BOE (1) $ 4.36 $ 4.51 $ 4.42
<FN>
(1)Based on a 6 Mcf to 1 Bbl gas to oil conversion ratio.
</FN>
</TABLE>
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, 1997, the Company sold 10% or more of its net production of oil and
gas to the following purchasers: Hunt Refining (42%), Natural Gas Clearinghouse
(22%) and Columbia Energy Services (10%).
4
<PAGE>
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.
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 77% of the Company's oil production in 1997, 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.
The Company is currently selling a majority of its oil under a two-year
contract to Hunt Refining which expires in April 1998 and is currently receiving
a premium to the posted price in this contract. The Company may not be able to
renew this contract in the future or may not be able to obtain terms as
favorable as those in the existing contract.
Natural Gas Marketing
Virtually all of Denbury's natural gas production is close to existing
pipelines and consequently, the Company generally has a variety of options to
market its natural gas. The Company sells the majority of its natural gas on one
year contracts with prices fluctuating month-to-month based on published
pipeline indices with slight premiums or discounts to the index.
Production Price Hedging
For 1995, the Company entered into financial contracts to hedge 75% of the
Company's net natural gas production and 43% of the Company's net oil
production. The net effect of these hedges was to increase oil and natural gas
revenues by approximately $750,000 during 1995. The Company did not enter into
any hedging contracts during 1996 or 1997, although it may enter into such
contracts in the future.
5
<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
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.
6
<PAGE>
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
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.
7
<PAGE>
Environmental Regulations
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Public interest in the protection of the
environment has increased dramatically in recent years. The trend of more
expansive and stricter environmental legislation and regulations could continue.
To the extent laws are enacted or other governmental action is taken that
restricts drilling or imposes environmental protection requirements that result
in increased costs to the oil and gas industry in general, the business and
prospects of the Company could be adversely affected.
The EPA and various state agencies have limited the approved methods of
disposal for certain hazardous and nonhazardous wastes. Certain wastes generated
by the Company's oil and natural gas operations that are currently exempt from
treatment as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Most of
these properties have been operated by prior owners, operators and third parties
whose treatment and disposal or release of hydrocarbons or other wastes was not
under the Company's control. These properties and the wastes disposed thereon
may be subject to Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), Federal Resource Conservation and Recovery Act and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Certain provisions of CAA may result in
the gradual imposition of certain pollution control requirements with respect to
air emissions from the operations of the Company. The EPA and states have been
developing regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several years for air
pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues.
However, the Company does not believe its operations will be materially
adversely affected by any such requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from a spill, including but not
limited to, the costs of responding to a release of oil to surface waters.
Regulations are currently being developed under the OPA and state laws
concerning oil pollution prevention and other matters that may impose additional
regulatory burdens on the Company.
The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as nonhazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or 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.
8
<PAGE>
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 4 "Income Taxes" of the Consolidated Financial Statements
for additional tax disclosures and such information is incorporated herein by
reference.
Estimated Net Quantities of Proved Oil and Gas Reserves and Present Value of
Estimated Future Net Revenues
Net proved oil and gas reserves as of December 31, 1997, 1996,and 1995 have
been prepared by Netherland, Sewell and Associates, Inc., independent petroleum
engineers located in Dallas, Texas. See Note 11 "Supplemental Reserve
Information" of the Consolidated Financial Statements for disclosure of reserve
amounts and such information is incorporated herein by reference.
Forward-Looking Statements
The statements contained in this Annual Report on Form 10-K ("10-K Report")
that are not historical facts, including, but not limited to, statements found
in this Item 1. "Business" and Item 7. "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 Exchange Act, that involve a
number of risks and uncertainties. Such forward-looking statements may be or may
concern, among other things, capital expenditures, drilling activity,
acquisition plans and proposals, dispositions, development activities, cost
savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon
prices, liquidity, regulatory matters and competition. Such forward-looking
statements generally are accompanied by words such as "plan," "estimate,"
"expect", "predict," "anticipate," "projected," "should," "assume," "believe,"
or other words that convey the uncertainty of future events or outcomes. Such
forward-looking statements are based upon management's current plans,
expectations, estimates and assumptions and are subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and the Company's financial condition and
results of operations. As a consequence, actual results may differ materially
from expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital, general economic conditions,
competition and government regulations, as well as the risks and uncertainties
discussed in this 10-K 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.
Item 2. Properties
See Item 1. "Business - Oil and Gas Operations, Oil and Gas Acreage,
Productive Wells and Estimated Net Quantities of Proved Oil and Gas Reserves and
Present Value of Estimated Future Net Revenues". The Company also has various
operating leases for rental of office space, office equipment, and vehicles. See
Note 7 "Commitments and Contingencies" of the Consolidated Financial Statements
for the future minimum rental payments 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 other third party entities were killed, none
of whom were employees or contractors of the Company. In connection with this
blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al.v. Mallard
Bay Drilling L.L.C., Parker Drilling Company and Denbury Management, Inc., Case
No. 58226-G in the 16th Judicial District court in St. Martin Parish, Louisiana
alleging various defective and dangerous conditions, violation of certain rules
and regulations and acts of negligence. The Company believes that all litigation
to which it is a party is covered by insurance and none of such legal
proceedings can be 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 1997.
9
<PAGE>
PART II
Item 5. Market for the Common Stock and Related Matters
Information as to the markets in which the Company's Common Stock is
traded, the quarterly high and low prices for such stock, 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, 1998, is set forth under
"Quarterly Stock Information", appearing on page 47 of the Annual Report.
Information as to restrictions on the payment of dividends with respect to the
Company's Common Stock is set forth in Note 5 "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 March 16, 1998 was $17.06 and $24.30
respectively.
Item 6. Selected Financial Data
Selected Financial Data for the Company for each of the last five years are
set forth under "Financial Highlights", appearing on page 1 of the Annual
Report. All such information is incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Information as to the Company's financial condition, changes in financial
condition and results of operations and other matters is set forth in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations", appearing on pages 19 through 26 of the Annual Report and is
incorporated herein by reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Not applicable
Item 8. Financial Statements and Supplementary Data
The Company's consolidated financial statements, accounting policy
disclosures, notes to financial statements, business segment information and
independent auditors' report are presented on pages 27 through 47 of the Annual
Report. Selected quarterly financial data are set forth under "Unaudited
Quarterly Information" appearing on page 46 of the Annual Report. All such
information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
10
<PAGE>
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 and Special Meeting of
shareholders to be held May 19, 1998, ("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 1997.
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, 1998, by each of its directors and nominees
for director, its five most highly compensated executive officers and its
directors and executive officers as a group will be presented under the caption
"Security Ownership of Certain Beneficial Owners and Management" in the Proxy
Statement for the Annual Meeting and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
Information on related transactions will be presented under the caption
"Compensation Committee Interlocks and Insider Participation" and "Interests of
Insiders in Material Transactions" in the Proxy Statement for the Annual Meeting
and is incorporated herein by reference.
11
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Financial Statements and Schedules. Financial statements filed as a
part of this report are presented on pages 27 through 47 of the Annual
Report and are incorporated herein by reference. Footnote 10 "Condensed
Consolidating Financial Information" of the Consolidated Financial
Statements presents seperate condensed financial statements for Denbury
Resources Inc. and Denbury Management, Inc. Additional seperate
disclosures are not considered necessary as they are not material to
investors. The following schedules are filed as part of this report:
Schedule I: Condensed Financial Information of the Registrant.
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) Shelf Registration Agreement dated April 24, 1995, by and among
Newscope Resources Ltd. and holders of Special Warrants
(incorporated by reference as Exhibit 10(a) of the Registrant's
Registration Statement on Form F-1 dated August 25, 1995).
10(b) 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(c) Registration Rights Agreement dated May 5, 1995, between
Internationale Nederlanden (U.S.) Capital Corporation and
Newscope Resources Ltd. (incorporated by reference as Exhibit
10(d) of the Registrant's Registration Statement on Form F-1
dated August 25, 1995).
10(d) 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).
12
<PAGE>
Exhibit No. Exhibit
10(e) Denbury Resources Inc. Stock Purchase Plan (incorporated by
reference as Exhibit 4(g) of the Registrant's Registration
Statement on Form S-8 dated February 2, 1996).
10(f) 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(g) 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(h) 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(i) 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(j) 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(k) 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(l)* 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.
10(m)* Stock Purchase Agreement and Amendment to Registration Rights
Agreement between TPG Partners, L.P. and Denbury Resources, Inc.
dated as of January 20, 1998.
11* Statement re-computation of per share earnings.
12* Statement of Ratio of Earnings to Fixed Charges.
13* Annual Report to the Security Holders.
21* List of Subsidiaries of Denbury Resources Inc.
23* Consent of Deloitte & Touche.
27* Financial Data Schedule.
* Filed herewith.
(b) Form 8-Ks filed during the fourth quarter of 1997.
On December 8, 1997, the Company filed a Form 8-K to report that it had
entered into an asset sale agreement to purchase producing oil
properties in the Heidelberg Field, Jasper County, Mississippi for $202
million from Chevron U.S.A. Inc. On January 20, 1998, the Company field
an amendmentment No. 1 to this Form 8-K to include audited statements of
revenues and expenses related to the acquired properties and to report
the related pro forma results of operations.
On December 16, 1997, the Company filed a Form 8-K to announce the
election of Wilmot L. Matthews of Toronto, Ontario to the Board of
Directors.
13
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Denbury Resources Inc. (the "Company") has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
DENBURY RESOURCES INC.
DENBURY MANAGEMENT, INC.
March 19, 1998 /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 the Company
and in the capacities and on the dates indicated.
March 19, 1998 /s/ Ronald G. Greene
-------------------------------
Ronald G. Greene
Chairman of the Board and
Director
DENBURY RESOURCES INC.
March 19, 1998 /s/ Gareth Roberts
-------------------------------
Gareth Roberts
Director, President and Chief
Executive Officer
(Principal Executive Officer)
DENBURY RESOURCES INC.
March 19, 1998 /s/ Phil Rykhoek
-------------------------------
Phil Rykhoek
Chief Financial Officer and
Secretary
(Principal Financial Officer)
DENBURY RESOURCES INC.
March 19, 1998 /s/ Bobby J. Bishop
-------------------------------
Bobby J. Bishop
Chief Accounting Officer and
Controller
(Principal Accounting Officer)
DENBURY RESOURCES INC.
March 19, 1998 /s/ Wilmot L. Matthews
-------------------------------
Wilmot L. Matthews
Director
DENBURY RESOURCES INC.
March 19, 1998 /s/ Wieland F. Wettstein
-------------------------------
Wieland F. Wettstein
Director
DENBURY RESOURCES INC.
14
<PAGE>
March 19, 1998 /s/ Gareth Roberts
-------------------------------
Gareth Roberts
Director, President and Chief
Executive Officer
(Principal Executive Officer)
DENBURY MANAGEMENT, INC.
March 19, 1998 /s/ Phil Rykhoek
-------------------------------
Phil Rykhoek
Director, Chief Financial Officer
and Secretary
(Principal Financial Officer)
DENBURY MANAGEMENT, INC.
March 19, 1998 /s/ Bobby J. Bishop
-------------------------------
Bobby J. Bishop
Chief Accounting Officer and
Controller
(Principal Accounting Officer)
DENBURY MANAGEMENT, INC.
March 19, 1998 /s/ Matthew Deso
-------------------------------
Matthew Deso
Director and Vice President,
Exploration
DENBURY MANAGEMENT, INC.
March 19, 1998 /s/ Mark Worthey
-------------------------------
Mark Worthey
Director and Vice President,
Operations
DENBURY MANAGEMENT, INC.
15
<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, 1997 and 1996, and for each of the three years in the period ended
December 31, 1997, and have issued our report thereon dated February 27, 1998,
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
Chartered Accountants
Calgary, Alberta
February 27, 1998
1
<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,
------------------------
1997 1996
--------- --------
Assets
<S> <C> <C>
Current assets
Cash and cash equivalents $ 354 $ 274
Trade and other receivables 9 6
--------- --------
Total current assets 363 280
--------- --------
Investment in subsidiaries (equity method) 159,892 140,763
Loan receivable from subsidiary - 1,558
Other assets 102 2
--------- --------
Total assets $ 160,357 $142,603
========= ========
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 134 $ 99
--------- --------
Shareholders' equity
Common shares, no par value
unlimited shares authorized;
outstanding - 20,388,683 shares at
December 31, 1997 and 20,055,757 shares
at December 31, 1996 133,139 130,323
Retained earnings 27,084 12,181
--------- --------
Total shareholders' equity 160,223 142,504
--------- --------
Total liabilities and shareholders' equity $ 160,357 $142,603
========= ========
</TABLE>
(See Notes to Condensed Financial Statements)
2
<PAGE>
Schedule 1 - Condensed Financial Information of Registrant
DENBURY RESOURCES INC.
UNCONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands except per share amounts)
(U.S. dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1997 1996 1995
------- -------- -------
<S> <C> <C> <C>
Revenues
Interest income and other $ 150 $ 179 $ 460
------- -------- -------
Expenses
General and administrative 145 161 178
Interest - 304 282
Imputed preferred dividends - 1,281 -
------- -------- -------
Total expenses 145 1,746 460
------- -------- -------
Income (loss) before the following: 5 (1,567) -
Equity in net earnings of subsidiaries 14,898 10,311 714
------- -------- -------
Income before income taxes 14,903 8,744 714
Provision for federal income taxes - - -
------- -------- -------
Net income $14,903 $ 8,744 $ 714
======= ======== =======
Net income per common share
Basic $ 0.74 $ 0.67 $ 0.10
Fully diluted 0.70 0.62 0.10
Average number of common shares
outstanding 20,224 13,104 6,870
======= ======== ========
</TABLE>
(See Notes to Condensed Financial Statements)
3
<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,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Cash flow from operating activities:
Net income $ 14,903 $ 8,744 $ 714
Adjustments needed to reconcile to net cash flow provided by operations:
Imputed preferred dividend -- 1,281 --
Other (163) 114 17
Equity in net earnings of subsidiaries (14,898) (10,311) (714)
-------- -------- --------
(158) (172) 17
Changes in working capital items relating to operations:
Trade and other receivables (3) -- (4)
Accounts payable and accrued liabilities 35 90 (12)
-------- -------- --------
Net cash flow provided by (used by) operations (126) (82) 1
-------- -------- --------
Cash flow from investing activities:
Investments in subsidiaries (2,510) (60,316) (43,569)
Net purchases of other assets (100) -- 7
-------- -------- --------
Net cash used for investing activities (2,610) (60,316) (43,562)
-------- -------- --------
Cash flow from financing activities:
Issuance of subordinated debt -- -- 1,772
Issuance of common stock 2,816 60,664 26,825
Issuance of preferred stock -- -- 15,000
Costs of debt financing -- --
(35)
-------- -------- --------
Net cash provided by financing activities 2,816 60,664 43,562
-------- -------- --------
Net increase in cash and cash equivalents 80 266 1
Cash and cash equivalents at beginning of year 274 8 7
-------- -------- --------
Cash and cash equivalents at end of year $ 354 $ 274 $ 8
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for interest $ -- $ 277 $ 282
</TABLE>
(See Notes to Condensed Financial Statements)
4
<PAGE>
DENBURY RESOURCES INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRATION
NOTES TO FINANCIAL STATEMENTS
Note 1. 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 Income because the Company has losses for Canadian tax purposes.
Note 2. Consolidated Financial Statements
Reference is made to the Consolidated Financial Statements and related
notes of Denbury Resources Inc. and Subsidiaries for additional information.
Note 3. Debt and Guarantees
Information on the long-term debt of Denbury Resources Inc. is disclosed in
Note 3 to the Consolidated Financial Statements. Denbury Resources Inc. has
guaranteed the subsidiaries' bank credit line.
Note 4. 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.
5
Exhibit 10(l)
SECOND AMENDMENT TO FIRST RESTATED CREDIT AGREEMENT
This Second Amendment to First Restated Credit Agreement (this "Second
Amendment") is entered into as of the 25th day of February, 1998, by and among
Denbury Management, Inc. ("Borrower"), Denbury Resources, Inc. ("Parent"),
NationsBank of Texas, N.A., as Administrative Agent ("Agent"), and NationsBank
of Texas, N.A., as Bank (the "Bank").
W I T N E S E T H
WHEREAS, Borrower, Parent, Agent and the Bank are parties to that certain
First Restated Credit Agreement dated as of December 29, 1997, as amended by
that certain First Amendment to First Restated Credit Agreement dated as of
January 27, 1998 (as amended, "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, the parties to the Credit Agreement desire to amend the Credit
Agreement in certain respects.
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, Agent and each Bank hereby agree as follows:
Section 1. Amendments. In reliance on the representations, warranties,
covenants and agreements contained in this Second Amendment, the Credit
Agreement shall be amended effective February 25, 1998 (the "Effective Date") in
the manner provided in this Section 1.
1.1. Additional Definitions. Section 1.1 of the Credit Agreement shall be
amended to add the definition of "Second Amendment" as follows:
"Second Amendment" means that certain Second Amendment to First
Restated Credit Agreement dated as of February 25, 1998 among Borrower, Parent,
Agent and Banks.
1.2 Amendment to Definitions. The definitions of "Eligible Assignee" and
"Loan Papers" in Section 1.1 of the Credit Agreement shall be amended to read in
full as follows:
"Eligible Assignee" means (a) a Bank; (b) an affiliate of a Bank; and
(c) any other Person approved by the Administrative Agent and, unless an Event
of Default has occurred and is continuing at the time any assignment is effected
in accordance with Section 14.10, the Borrower, such approval not to be
unreasonably withheld or delayed by the Borrower or the Administrative Agent,
and such approval to be deemed given by the Borrower if no objection is received
by the assigning Bank and the Administrative Agent from the Borrower within two
Domestic Business Days after notice of such proposed assignment has been
provided by the assigning Bank to the Borrower; provided, however, that neither
the Borrower nor an affiliate of the Borrower shall qualify as an Eligible
Assignee.
1
<PAGE>
"Loan Papers" means this Agreement, the First Amendment, the Second
Amendment, the Notes, the Facility Guarantees, the Parent Pledge Agreement, the
Existing Mortgages (as amended by the Amendment to Mortgages), and all Mortgages
now or at any time hereafter delivered pursuant to Section 5.1, and all other
certificates, documents or instruments delivered in connection with this
Agreement, as the foregoing may be amended from time to time.
1.3 Conditions. The introductory clause to Section 6.2 of the Credit
agreement shall be amended to read in full as follows:
"The obligation of each Bank to loan its Commitment Percentage of each
Borrowing and the obligation of the Agent to issue, extend, amend or renew any
Letter of Credit on the date such Letter of Credit is to be issued, extended,
amended or renewed is subject to the further satisfaction of the following
conditions:"
1.4 Amendments and Waivers. Section 14.5 of the Credit Agreement shall be
amended to read in full as follows:
"SECTION 14.5. Amendments and Waivers. Any provision of this
Agreement, the Notes or the other Loan Papers may be amended or waived if, but
only if such amendment or waiver is in writing and is signed by Borrower and the
Required Banks (and, if the rights or duties of any Agent are affected thereby,
by such Agent); provided that no such amendment or waiver shall, unless signed
by all Banks, (a) increase the Commitment of any Bank, (b) reduce the principal
of or rate of interest on any Loan or any fees or other amounts payable
hereunder or for termination of any Commitment, (c) change the percentage of the
Total Commitment, or the number of Banks which shall be required for the Banks
or any of them to take any action under this Section 14.5 or any other provision
of this Agreement, (d) extend the due date for, or forgive any principal,
interest or fees due hereunder, (e) release any material guarantor or other
material party liable for all or any part of the Obligations or release any
material part of the collateral for the Obligations or any part thereof other
than releases required pursuant to sales of collateral which are expressly
permitted by Section 9.5 hereof, or (f) amend or modify any of the provisions of
Article IV hereof or the definitions of any terms defined therein."
1.5 Assignments and Participations. Section 14.10 of the Credit Agreement
shall be amended to add the following subsection (g) to the end of such Section:
"(g) Each Loan Paper binds and inures to the parties to it, any
intended beneficiary of it, and each of their respective successors and
permitted assigns. Neither Borrower nor Parent shall assign or transfer any
rights or obligations under any Loan Paper or permit any other Credit Party to
assign or transfer any rights or obligations under any Loan Paper without first
obtaining all Banks' consent, and any purported assignment or transfer without
all Banks' consent is void."
2
<PAGE>
Section 2. Waiver Regarding Environmental Workplan. Pursuant to Schedule
8.10 of the Credit Agreement, Borrower was required to provide an environmental
Workplan by February 12, 1998. Borrower requests additional time to prepare such
Workplan. Bank hereby extends the due date for delivery of the Workplan pursuant
to Section 8.10 of the Credit Agreement to March 15, 1998. Bank waives any
Default or Event of Default resulting from the failure to deliver the Workplan
on February 12, 1998. Borrower acknowledges that this waiver and extension are
limited solely to Schedule 8.10 of the Credit Agreement. Nothing contained
herein shall obligate the Banks to grant any additional or future waiver or
extension of Schedule 8.10 of the Credit Agreement or any other provision of any
Loan Paper.
Section 3. Representations and Warranties of Borrower. To induce the Banks
and Agent to enter into this Second Amendment, Borrower and Parent hereby
represent and warrant to Agent as follows:
(a) 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.
(b) The execution, delivery and performance by Borrower and Parent of
this Second Amendment are within the 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 the
Parent or result in the creation or imposition of any Lien upon any of the
assets of Borrower or the Subsidiaries of Borrower or the Parent except
Permitted Encumbrances.
(c) This Second Amendment constitutes the valid and binding
obligations of Borrower and the 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.
(d) 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 4. Miscellaneous.
4.1 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 and
Parent hereby extend the Liens securing the Obligations until the Obligations
have been paid in full or are specifically released by Agent and Banks prior
thereto, and agree that the amendments and modifications herein contained shall
in no manner affect or impair the Obligations or the Liens securing payment and
performance thereof.
3
<PAGE>
4.2 Parties in Interest. All of the terms and provisions of this Second
Amendment shall bind and inure to the benefit of the parties hereto and their
respective successors and assigns.
4.3 Legal Expenses. Borrower hereby agrees to pay on demand all reasonable
fees and expenses of counsel to Agent incurred by Agent, in connection with the
preparation, negotiation and execution of this Second Amendment and all related
documents.
4.4 Counterparts. This Second Amendment may be executed in counterparts,
and all parties need not execute the same counterpart; however, no party shall
be bound by this Second Amendment until all parties have executed a counterpart.
Facsimiles shall be effective as originals.
4.5 Complete Agreement. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND THE
OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT BETWEEN 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.
4.6 Headings. The headings, captions and arrangements used in this Second
Amendment are, unless specified otherwise, for convenience only and shall not be
deemed to limit, amplify or modify the terms of this Second Amendment, nor
affect the meaning thereof.
IN WITNESS WHEREOF, the parties hereto have caused this Second 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
4
<PAGE>
PARENT:
DENBURY RESOURCES, INC.,
a corporation incorporated under
the Canada Business Corporations
Act
By:
----------------------------
Gareth Roberts
President and Chief
Executive Officer
By:
----------------------------
Phil Rykhoek
Chief Financial Officer
and Secretary
ADMINISTRATIVE AGENT:
NATIONSBANK OF TEXAS, N.A.
By:
----------------------------
J. Scott Fowler
Vice President
BANKS:
NATIONSBANK OF TEXAS, N.A.
By:
----------------------------
J. Scott Fowler
Vice President
5
EXHIBIT 10(m)
TPG PARTNERS, L.P. STOCK PURCHASE AGREEMENT
STOCK PURCHASE AGREEMENT
THIS STOCK PURCHASE AGREEMENT ("Agreement") is entered into as of the 20th
day of January, 1998 by and between Denbury Resources, Inc. ("Company") and TPG
Partners, L.P. ("Buyer").
W I T N E S S E T H
WHEREAS, the Company is offering $100,000,000 of its Common Shares ("Common
Shares"), no par value, to the public in an offering ("Public Offering") through
a syndicate of underwriters ("Underwriters"); and
WHEREAS, concurrent with and conditioned upon the closing of the Public
Offering, the Company desires to sell to Buyer, and Buyer desires to purchase
from Company, $5,000,000 of the Company's Common Shares (the "Shares") pursuant
to a registered offering on the terms and conditions set forth herein;
NOW THEREFORE, in consideration of the mutual covenants and agreements
contained herein, and other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties hereto agree as
follows:
ARTICLE 1
PURCHASE AND SALE OF SHARES
1.1 Purchase and Sale of Shares. Subject to the conditions set forth in
Section 1.3 hereof, the Company agrees to sell the Shares to Buyer and Buyer
agrees to purchase the Shares from the Company for a total purchase price of
$5,000,000, on the terms and conditions set forth in this Agreement (the "TPG
Offering").
1.2 Purchase Price. The purchase price per Share for the Shares shall be
the price per share of the Common Shares to the public in the Public Offering
less underwriting discounts and commissions, as set forth in the final
prospectus relating to the Public Offering; provided, however, that such
purchase price shall be subject to approval by the Toronto Stock Exchange
("TSE"). In the event that the TSE does not approve such purchase price, the
purchase price of the Shares shall be 100% of the price per share to the public
in the Public Offering.
1.3 Conditions Precedent. The Company's obligation to sell and Buyer's
obligation to buy the Shares is subject to and conditioned upon (i) the closing
of the Public Offering, (ii) the effectiveness of a Registration Statement
relating to the TPG Offering, and (iii) the delivery to Buyer of a final
prospectus relating to the TPG Offering.
6
<PAGE>
1.4 Closing. The purchase and sale of the Shares shall be consummated at a
closing to be held simultaneously with the closing of the Public Offering, or at
such other date as the parties shall agree. At the closing, the following
documents shall be exchanged:
A. In payment of the purchase price for the Shares, Buyer shall
deliver immediately available funds to the Company by wire transfer to
NationsBank of Texas, N.A., for the Account of Denbury Resources Inc.
B. The Company shall deliver the certificate(s) representing the
Shares to Buyer.
C. Buyer and the Company shall execute and deliver each to the other
at the closing a cross receipt for the certificate(s) representing the Shares
and the funds representing the purchase price of the Shares, respectively.
1.5 Assignment to Affiliates. Buyer may assign all or any portion of its
rights to purchase the Shares under this Agreement to any one of its affiliates
having TPG GenPar, L.P., as its general partner, including TPG Parallel I, L.P.
ARTICLE 2
REPRESENTATIONS AND WARRANTIES OF BUYER
2.1 Informed Investor. Buyer holds the position of an affiliate of the
Company for the purpose of Rule 144 promulgated pursuant to the Securities Act
of 1933 (the "Act"), and by reason of such position has access to substantial
information regarding the Company's finances, properties, assets and
liabilities, and business prospects. Such information is sufficient to permit
Buyer to make an informed investment in the Shares.
2.2 Sophisticated Investor. By reason of Buyer's business and financial
experience (and the business and financial experience of any persons retained by
Buyer to advise him with respect to his investment in the Shares), Buyer
(together with such advisers, if any) has such knowledge, sophistication and
experience in business and financial matters as to be capable of evaluating the
merits and risks of the investment in the Shares.
2.3 No Distribution Intent. Buyer represents to the Company that it is not
acquiring the Shares with a view to, nor does it have any current intent to
engage in, a distribution of the Shares. Buyer acknowledges that as an affiliate
under Rule 144, Buyer may only resell the Shares in accordance with the
applicable terms and conditions of Rule 144 (other than Rule 144(d)), including
restrictions on the volume of Shares that may be resold and the manner of sale.
7
<PAGE>
2.4 Authority; No Consent. Upon execution and delivery by Buyer, this
Agreement will constitute the legal, valid, and binding obligation of Buyer,
enforceable against Buyer in accordance with its terms. Buyer has the absolute
and unrestricted right, power, and authority to execute and deliver this
Agreement and to perform its obligations under this Agreement. Buyer is not and
will not be required to obtain any consent from any person in connection with
the execution and delivery of this Agreement or the consummation or performance
of any of the transactions contemplated hereby.
2.5 No Violation. Buyer represents and warrants that neither the execution
and performance of this Agreement nor the consummation of the transactions
contemplated hereby will (i) conflict with, or result in a breach of the terms,
conditions and provisions of, or constitute a default under, its organizational
documents, any agreement, indenture or other instrument under which it is bound,
or (ii) violate or conflict with any judgment, decree, order, statute, rule,
regulation or administrative proceedings or lawsuits, pending or threatened, of
any court or any public, governmental or regulatory agency or body having
jurisdiction over him or his properties or assets.
2.6 The Toronto Stock Exchange. Buyer undertakes not to sell or otherwise
dispose of any of the Common Shares purchased pursuant to this Agreement, or any
securities derived therefrom, for a period of six (6) months from the date of
the closing of the Public Offering without the prior consent of The Toronto
Stock Exchange and any other regulatory body having jurisdiction.
ARTICLE 3
REPRESENTATIONS AND WARRANTIES OF THE COMPANY
3.1 Shares. The Shares will be duly authorized and when issued in
accordance with this Agreement and upon the payment of the purchase price set
forth in Section 1.2 hereof, will be duly and validly issued, fully paid and
nonassessable and the Company will deliver an opinion of Jenkens & Gilchrist, a
Professional Corporation, to that effect at the closing.
3.2 Authority; No Consent. Upon the execution and delivery by the Company
of this Agreement, this Agreement will constitute the legal, valid, and binding
obligation of the Company, enforceable against it in accordance with its terms.
The Company has the absolute and unrestricted right, power, and authority to
execute and deliver this Agreement and to perform its obligations under this
Agreement. The Company is not and will not be required to obtain any consent
from any person in connection with the execution and delivery of this Agreement
or the consummation or performance of any of the transactions contemplated
hereby.
ARTICLE 4
MISCELLANEOUS
4.1 Entire Agreement. This Agreement sets forth the entire agreement and
understanding of the parties with respect to the transactions contemplated
hereby, and supersedes all prior agreements, arrangements, and understandings
relating to the subject matter hereof.
8
<PAGE>
4.2 Notices. All notices, payments and other required communications
("Notices") to the parties shall be in writing, and shall be addressed,
respectively, as follows:
If to Company: Denbury Resources Inc.
17304 Preston Road, Suite 200
Dallas, Texas 75252
Attn: Phil Rykhoek
If to Buyer: TPG Partners, L.P.
201 Main Street
Suite 2420
Fort Worth, Texas 76102
Attn: James J. O'Brien
All Notices shall be given (i) by personal delivery, or (ii) by electronic
communication, with a confirmation sent by registered or certified mail, return
receipt requested, or (iii) by registered or certified mail, return receipt
requested. All Notices shall be deemed delivered (i) if by personal delivery, on
the date of delivery if delivered during normal business hours, and, if not
delivered during normal business hours, on the next business day following
delivery, (ii) if by electronic communication, on the date of receipt of the
electronic communication, and (iii) if solely by mail, on the date of deposit of
the mailing in an official U.S. post office mail depository. A party may change
its address by Notice to the other party.
4.3 Applicable Law and Venue. All questions concerning the construction,
validity and interpretation of this Agreement shall be governed by the internal
laws, and not the law of conflicts, of the State of Texas. Any legal action
relating to this Agreement shall be brought only in a court of competent
jurisdiction in Dallas County, Texas or in the United States District Court for
the Northern District of Texas, Dallas Division.
4.4 Attorney's Fees. If any legal action is brought by any party hereto, it
is expressly agreed that the prevailing party in such legal action shall be
entitled to recover from the other party reasonable attorneys' fees in addition
to any other relief that may be awarded. For the purposes of this Section, the
"prevailing party" shall be the party in whose favor final judgment is entered.
In the event that declaratory or injunctive relief alone is granted, the court
may determine which, if either, of the parties is the prevailing party. The
amount of reasonable attorneys' fees shall be determined by the court.
4.5 Waiver. The failure of a party to insist on the strict performance of
any provision of this Agreement or to exercise any right, power or remedy upon a
breach hereof shall not constitute a waiver of any provision of this Agreement
or limit the party's right thereafter to enforce any provision or exercise any
right.
4.6 Severability. If any term, provision, covenant, or restriction of this
Agreement is held by the final, nonappealable order of a court of competent
jurisdiction to be invalid, void, or unenforceable, the remainder of the terms,
provisions, covenants, and restrictions hereof shall remain in full force and
effect and shall in no way be affected, impaired, or invalidated.
9
<PAGE>
4.7 Amendments. This Agreement may be amended, modified, or superseded only
by written instrument executed by all parties hereto.
4.8 Headings. The Article and Section headings appearing in this Agreement
are for convenience of reference only and are not intended, to any extent or for
any purpose, to limit or define the text of any Article or Section.
4.9 Gender and Number. Whenever required by the context, as used in this
Agreement, the singular number shall include the plural and the neuter shall
include the masculine or feminine gender, and vice versa.
4.10 Counterparts. This Agreement may be executed in several counterparts,
each of which shall be an original and all of which together shall constitute
one agreement binding on all parties hereto, notwithstanding that all the
parties have not signed the same counterpart.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement
effective as of the date first above written.
Company: DENBURY RESOURCES INC.
By:
----------------------------
Phil Rykhoek
Chief Financial Officer
Buyer: TPG PARTNERS, INC.
By: TPG GenPar, L.P.
its General Partner
By:TPG Advisors, Inc.
its General Partner
By:
----------------------
James J. O'Brien
Vice-President
10
<PAGE>
AMENDMENT TO REGISTRATION
RIGHTS AGREEMENT
This AMENDMENT TO REGISTRATION RIGHT AGREEMENT is dated as of January 20,
1998, and is by and among DENBURY RESOURCES INC., A Canadian corporation (the
"Company"), TPG PARTNERS, L.P., a Delaware limited partnership ("TPG"), and TPG
PARALLEL I, L.P., a Delaware limited partnership ("Parallel").
W I T N E S S E T H :
WHEREAS, the Company, TPG and Parallel are parties to that certain
Registration Rights Agreement effective as of December 21, 1995 (the
"Registration Rights Agreement");
WHEREAS, the Company and TPG are parties to that certain Stock Purchase
Agreement dated as of January 20, 1998 (the "Stock Purchase Agreement"), whereby
TPG has agreed to purchase $5,000,000 of the Company's Common Shares (the
"Shares"); and
WHEREAS, the parties desire to amend herein the Registration Rights
Agreement so that the benefits accruing to TPG and Parallel thereunder shall
likewise apply to the Shares to be purchased pursuant to the Stock Purchase
Agreement.
NOW, THEREFORE, in consideration of the premises and other good and
valuable consideration, the receipt and sufficiency of which hereby are
acknowledged, the parties hereto hereby agree as follows:
1. Section 1(i) of the Registration Rights Agreement hereby is amended in
its entirety to read as follows:
(i) "Subject Common Shares" means the Common Shares to be acquired
pursuant to the Securities Purchase Agreement, the Common Shares issuable upon
exercise of the Warrants and upon conversion of the Series A Preferred Shares,
and, if necessary (only with respect to registration in the United States) to
register the underlying Common Shares, the Warrants and the Series A Preferred
Shares, any additional Common Shares distributed in respect of such Subject
Common Shares, any equity security into which the original Subject Common Shares
are converted, and the Common Shares to be acquired pursuant to those two
certain Stock Purchase Agreements dated as of October 2, 19967, and January 20,
1998, by and between the Company and TPG.
2. Except as amended hereby, the Registration Rights Agreement remains in
full force and effect.
11
<PAGE>
IN WITNESS WHEREOF, the parties have executed this Amendment to
Registration Rights Agreement effective as of the date first above written.
DENBURY RESOURCES INC.
By:
-----------------------------------
Phil Rykhoek
Chief Financial Officer
TPG PARTNERS, L.P.
By:TPG GenPar, L.P., its general partner
By:TPG Advisors, Inc., its general partner
By:
-----------------------------------
James J. O'Brien, Vice President
TPG PARALLEL I, L.P.
By:TPG GenPar, L.P., its general partner
By:TPG Advisors, Inc., its general partner
By:
-----------------------------------
James J. O'Brien, Vice President
12
EXHIBIT 11
DENBURY RESOURCES INC.
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------
1997 1996 1995
------- ------- ------
CANADIAN GAAP (Amounts in thousands
except per share amounts)
<S> <C> <C> <C>
Basic EPS:
Weighted average shares outstanding 20,224 13,104 6,870
------- ------- ------
Net income $14,903 $ 8,744 $ 714
------- ------- ------
Basic earnings per common share $ 0.74 $ 0.67 $ 0.10
======= ======= ======
Fully Diluted EPS:
Weighted average shares outstanding 20,224 13,104 6,870
Assumed conversions:
Convertible debentures (b) 391 (a)
Warrants 700 750 (a)
Stock options 1,550 1,053 (a)
Convertible preferred (b) (a) (b)
------- ------- ------
Adjusted shares outstanding 22,474 15,298 6,870
------- ------- ------
Net income $14,903 $ 8,744 $ 714
Adjustments:
Interest on subordinated debentures (b) 126 (a)
Interest on warrant proceeds 169 245 (a)
Interest on option proceeds 572 365 (a)
Imputed preferred dividend (b) (a) (b)
------- ------- ------
Adjusted net income $15,644 $ 9,480 $ 714
------- ------- ------
Fully diluted earnings per common share $ 0.70 $ 0.62 $ 0.10
======= ======= ======
<FN>
(a) Anti-dilutive or immaterial
(b) Not applicable for this period
</FN>
</TABLE>
13
<PAGE>
EXHIBIT 11
DENBURY RESOURCES INC.
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------
1997 1996 1995
------ ------ ------
U.S. GAAP (Amounts in thousands
except per share amounts)
<S> <C> <C> <C>
Basic EPS:
Weighted average shares outstanding 20,224 13,104 6,870
------ ------ ------
Net income $14,903 $8,744 $ 714
------ ------ ------
Basic earnings per common share $ 0.74 $ 0.67 $ 0.10
====== ====== ======
Diluted EPS:
Weighted average shares outstanding 20,224 13,104 6,870
Net adjustments to shares after repurchases
with proceeds:
Convertible debentures (b) 391 (a)
Warrants 428 402 (a)
Stock options 793 397 (a)
Convertible preferred (b) (a) (b)
------ ------ ------
Adjusted shares outstanding 21,445 14,294 6,870
------ ------ ------
Net income $14,903 $8,744 $ 714
Adjustments:
Interest on subordinated debentures (b) 220 (a)
Imputed preferred dividend (b) (a) (b)
------ ------ ------
Adjusted net income $14,903 $8,964 $ 714
------ ------ ------
Diluted earnings per common share $ 0.70 $ 0.63 $ 0.10
====== ====== ======
<FN>
(a) Anti-dilutive or immaterial
(b) Not applicable for this period
</FN>
</TABLE>
14
EXHIBIT 12
DENBURY RESOURCES INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Earnings:
Pretax income from continuing operations $23,798 $14,056 $ 1,081
Fixed charges 1,262 4,080 2,161
------- ------- -------
Earnings $25,060 $18,136 $ 3,242
======= ======= =======
Fixed Charges:
Interest expense $ 1,111 $ 1,993 $ 2,085
Interest component of rent expense 151 116 76
Imputed preferred dividend -- 1,281 --
Preferred dividend tax effect -- 690 --
------- ------- -------
Fixed charges $ 1,262 $ 4,080 $ 2,161
======= ======= =======
Ratio of earnings to fixed charges 19.9 4.4 1.5
======= ======= =======
</TABLE>
1
EXHIBIT 13
DENBURY RESOURCES, INC.
PAGE 1 AND PAGES 6 THROUGH 47, INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO
SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31, 1997, BUT EXCLUDING PHOTOGRAPHS AND
ILLUSTRATIONS SET FORTH ON THESE PAGES, NONE OF WHICH SUPPLEMENTS THE TEXT AND
WHICH ARE NOT OTHERWISE REQUIRED TO BE DISCLOSED IN THIS ANNUAL REPORT ON FORM
10-K.
<PAGE>
Financial Highlights
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------- AVERAGE
AMOUNTS IN THOUSANDS OF U.S. ANNUAL
DOLLARS UNLESS NOTED 1997 1996 1995 1994 1993 GROWTH (2)
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
PRODUCTION (DAILY)
Oil (Bbls) 7,902 4,099 1,995 1,340 858 74%
Gas (Mcf) 36,319 24,406 13,271 9,113 2,013 106%
BOE (6:1) 13,955 8,167 4,207 2,858 1,193 85%
REVENUE (NET OF ROYALTIES)
Oil sales 49,748 28,475 10,852 6,767 4,356 84%
Gas sales 35,585 24,405 9,180 5,925 1,512 120%
Total 85,333 52,880 20,032 12,692 5,868 95%
UNIT SALES PRICE
Oil (per Bbl) 17.25 18.98 14.90 13.84 13.91 6%
Gas (per Mcf) 2.68 2.73 1.90 1.78 2.06 7%
CASH FLOW FROM OPERATIONS (1) 56,607 34,140 9,394 6,185 3,030 108%
NET INCOME 14,903 8,744 714 1,163 1,735 71%
AVERAGE COMMON SHARES OUTSTANDING 20,224 13,104 6,870 6,240 4,990 42%
PER SHARE:
Cash flow from operations: (1)
Basic 2.80 2.51 1.37 0.99 0.61 47%
Fully diluted 2.57 2.07 1.37 0.99 0.61 43%
Net income:
Basic 0.74 0.67 0.10 0.19 0.35 21%
Fully diluted 0.70 0.62 0.10 0.19 0.35 19%
OIL AND GAS CAPITAL INVESTMENTS 305,427 86,857 28,524 16,903 29,855 79%
TOTAL ASSETS 447,548 166,505 77,641 48,964 35,978 88%
LONG-TERM LIABILITIES 256,637 7,481 5,077 17,768 6,633 149%
SHAREHOLDERS' EQUITY AND
PREFERRED STOCK 160,223 142,504 68,501 25,962 24,431 60%
PROVEN RESERVES
Oil (MBbls) 52,018 15,052 6,292 4,230 3,583 95%
Gas (MMcf) 77,191 74,102 48,116 42,046 13,029 56%
MBOE (6:1) 64,883 27,403 14,312 11,237 5,755 83%
Discounted future cash flow - 10% 361,329 316,098 96,952 52,691 28,638 88%
PER BOE DATA (6:1)
Revenue 16.75 17.69 13.05 12.17 13.47 6%
Production expenses (4.36) (4.51) (4.42) (4.13) (4.75) (2)%
- ---------------------------------------------------------------------------------------------------------------------
Production netback 12.39 13.18 8.63 8.04 8.72 9%
General and administrative expenses (1.30) (1.50) (1.25) (1.12) (1.80) (8)%
Interest and other income (expense) 0.02 (0.26) (1.26) (0.99) 0.04 (16)%
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOW (1) 11.11 11.42 6.12 5.93 6.96 12%
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Exclusive of the net change in non-cash working capital balances.
(2) Computed using 1993 as a base year.
</FN>
</TABLE>
Reporting Format
Unless otherwise noted, the disclosures in this report have (i) dollar amounts
presented in U.S. dollars, (ii) production volumes expressed on a net revenue
interest basis, and (iii) gas volumes are converted to equivalent barrels at
6:1.
1
<PAGE>
Selected Operating Data
OIL AND GAS RESERVES
The reserves at December 31, 1997, 1996 and 1995 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 31st 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 net revenue interest (after royalties) of the Company.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------
1997 1996 1995
--------- -------- -------
<S> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil (MBbls)............................. 52,108 15,052 6,292
Natural Gas (MMcf)...................... 77,191 74,102 48,116
Oil Equivalent (MBOE)................... 64,883 27,403 14,311
PERCENTAGE OF MBOE:
Proved producing........................ 40% 45% 38%
Proved non-producing.................... 26% 39% 40%
Proved undeveloped...................... 34% 16% 22%
REPRESENTATIVE OIL AND GAS PRICES: (1)
West Texas Intermediate.................$ 16.18 $ 23.39 $ 18.00
NYMEX Henry Hub......................... 2.58 3.90 2.24
PRESENT VALUES:
Discounted estimated future net cash
flow before income taxes (PV10 Value)
(thousands) (2).........................$361,329(3) $316,098(4) $ 96,965
Standardized measure of discounted
estimated future net cash flow after net
income taxes (thousands)...............$335,308 $241,872 $ 81,164
- ---------------
<FN>
(1) The oil prices as of each respective year-end were based on West Texas
Intermediate "WTI" posted prices per barrel and NYMEX Henry Hub ("NYMEX")
prices per MMBtu,with these representative prices adjusted by field to
arrive at the appropriate corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance
with the guidelines of the SEC, discounted at 10% per annum.
(3) For comparative purposes the Company also prepared a reserve report as of
December 31, 1997 using the prices used in the December 31, 1996 reserve
report. The PV10 Value in this report was $633.4 million with 67.8 MMBOE of
proved reserves. Of the PV10 Value $206.7 million was attributable to the
Chevron Acquisition. As opposed to a PV10 Value of $109.4 million using
December 31, 1997 prices.
(4) For comparative purposes the Company prepared a December 31, 1996 reserve
report using a WTI price of $21.00 per Bbl and a NYMEX price of $2.40 per
MMBtu with these prices also adjusted by field. The PV10 Value in this
report was $213.7 million with 27.0 MMBOE of proved reserves. For the year
ended December 31, 1997, the average WTI price was approximately $18.62 per
Bbl and the average NYMEX price was approximately $2.59 per MMBtu.
</FN>
</TABLE>
CAPITAL EXPENDITURES
Denbury's commitment to future growth is best demonstrated by its reinvestment
levels. The major components of the Company's capital expenditure programs over
the last three years are as follows:
<TABLE>
<CAPTION>
(Amounts in Thousands) Year Ended December 31,
-------------------------------
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Property acquisition................... $ 226,809 $ 48,856 $ 17,198
Exploration............................ 20,734 4,592 1,687
Development............................ 57,884 33,409 9,639
--------- --------- ---------
TOTAL CAPITAL EXPENDITURES $ 305,427 $ 86,857 $ 28,524
========= ========= =========
</TABLE>
FINDING COST
Finding costs are one of the primary critical factors in determining a company's
profitability. Excluding the recent Chevron Acquisition approximately one-half
of the Company's reserves have come from acquisitions and one-half of its
reserves from exploitation and development. The finding cost for each of these
activities can vary widely depending on market conditions, drilling costs, etc.
In addition, one must also look at the type of reserves acquired as the cost per
BOE will vary depending on the
6
<PAGE>
netbacks, timing of cash flow, etc. In the finding cost calculation all oil and
gas expenditures incurred, including capital expenditures which will benefit
future years such as seismic surveys, prospect costs and undeveloped properties
have been included in the calculations. The forecasted future development costs
as outlined in the independent engineer's reserve forecast have not been
included in the calculation. The reserves are obtained from the unescalated SEC
price case using the Company's net revenue interest plus applicable historical
production, BOE equivalents are calculated using six Mcf per one barrel of oil.
<TABLE>
<CAPTION>
THREE YEAR INCEPTION
AVERAGE TO
1997 1995-1997 DATE
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Total capitalized costs (millions) $ 305.4 $ 420.8 $ 471.6
Proved reserve additions and production (MMBOE) 42.6 63.3 76.1
- ----------------------------------------------------------------------------
AVERAGE FINDING COST PER BOE (6:1) $ 7.17 $ 6.65 $ 6.20
- ----------------------------------------------------------------------------
</TABLE>
The above table includes $75 million of cost relating to the Chevron Acquisition
which was allocated to unevaluated properties as of December 31, 1997. The
average finding cost per BOE would be $5.41, $5.47 and $5.21 for 1997, the
three-year average and inception to date amounts respectively if the $75 million
were excluded from the calculation.
FIELD SUMMARIES
Denbury operates in two core areas, Louisiana and Mississippi. The eight largest
fields owned by the Company constitute approximately 85% and 82%, respectively,
of its total proved reserves on a BOE and PV10 Value basis. Within these eight
fields the Company owns an average 91% working interest and operates 85% of the
wells which comprise 71% of the Company's 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>
1997 Average
Proved Reserves as of December 31, 1997 (1) Average Production (2) Net
-------------------------------------------- --------------------- Gross Revenue
Oil Natural Gas PV10 Value PV10 Value Oil Natural Gas Productive Interest
(MBbls) (MMcf) (000's) % of Total (Bbls/d) (Mcf/d) Wells (3) (3)
- ------------------------------------------------------------------------------------------------------------------------------------
LOUISIANA
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Lirette 289 27,746 $ 44,668 12.4% 174 10,880 18 63.0%
Bayou Rambio 69 11,353 18,205 5.0% 46 3,492 3 59.1%
Gibson 302 6,631 12,658 3.5% 251 4,988 3 57.8%
South Chauvin 135 7,333 9,734 2.7% 51 2,736 4 73.4%
Other Louisiana 1,423 15,048 33,192 9.2% 1,218 11,378 82 48.7%
- ------------------------------------------------------------------------------------------------------------------------------------
Total Louisiana 2,218 68,111 118,457 32.8% 1,740 33,474 110 51.5%
- ------------------------------------------------------------------------------------------------------------------------------------
MISSISSIPPI
Heidelberg (4) 30,171 2,517 118,973 32.9% -(4) -(4) 122 81.0%
Eucutta 8,967 -- 58,657 16.2% 1,959 -- 45 75.3%
Quitman 3,032 -- 19,064 5.3% 1,470 -- 18 60.7%
Davis 2,660 -- 13,348 3.7% 1,181 -- 25 90.5%
Other Mississippi 4,834 5,597 29,667 8.2% 1,474 2,437 87 53.1%
- ------------------------------------------------------------------------------------------------------------------------------------
Total Mississippi 49,664 8,114 239,709 66.3% 6,084 2,437 297 66.5%
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER 136 966 3,163 0.9% 78 408 -- -%
- ------------------------------------------------------------------------------------------------------------------------------------
COMPANY TOTAL 52,018 77,191 $361,329 100.0% 7,902 36,319 407 60.7%
====================================================================================================================================
<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, 1997. The oil price at that date
was WTI $16.18 per Bbl adjusted by field and a NYMEX natural gas price
average of $2.58 per MMBtu, also adjusted by field.
(2) This table does not include production on the properties acquired in the
Chevron Acquisition on December 30, 1997.
(3) Includes only productive wells in which the Company has a working interest
as of December 31, 1997.
(4) Property acquired in the Chevron Acquisition plus three other minor
acquisitions. The average net production on the properties acquired in the
Chevron Acquisition from October 1, 1997 through December 31, 1997 was
2,800 Bbls/d and 650 MCF/d.
</FN>
</TABLE>
7
<PAGE>
[ONE ILLUSTRATION, NOT INCORPORATED BY REFERENCE - SEE PREFACING COMMENT ON
EXHIBIT 13 COVER PAGE]
8
<PAGE>
ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES
The Company regularly seeks to acquire properties that complement its
operations, provide exploitation, exploration and development opportunities and
have cost reduction potential. During 1997, Denbury completed a total of 17
separate acquisitions for a total expenditure of $224.1 million, of which 14 of
these acquisitions were in Mississippi and 3 were in Louisiana. The largest
acquisition of the Company to date was the purchase of the Heidelberg Field from
Chevron (the "Chevron Acquisition") which was completed at year-end 1997. Other
less significant acquisitions during 1997 included the acquisition of additional
interest at the Lirette Field in Louisiana and the Davis Field in Mississippi,
plus new interest at the Crawford Creek Field, also in Mississippi.
Chevron Property Acquisition
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202 million.
The Chevron Acquisition represents the largest acquisition by the Company to
date. The Heidelberg Field is adjacent to the Company's other primary oil
properties in Mississippi and includes 122 producing wells, 96 of which the
Company will operate. The Company purchased an average working interest of 94%
and an average net revenue interest of 81% in these 96 wells, which wells
account for approximately 99% of the field's average net daily production. The
average net daily production from these properties during the fourth quarter of
1997 was approximately 2,800 Bbls/d and 650 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed $75 million of the purchase price to unevaluated properties.
The Company has scheduled several potential development projects for 1998 during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 12 wells, recompleting 30
wells in new zones and drilling 41 wells. Horizontal wells drilled by the
Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily
production rates significantly as compared to vertical wells drilled in the same
fields. Consequently, the Company anticipates that 31 of the 41 proposed wells
in the Heidelberg Field will be horizontal wells. The Company's total 1998
development budget for the Heidelberg Field is approximately $30 million.
Update on 1996 Acquisitions
The Company completed several property acquisitions during 1996, the largest of
which was the acquisition of producing oil and natural gas properties in
Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in
Ohio, for approximately $37.2 million from Amerada Hess, effective May 1, 1996
(the "Hess Acquisition"). The average daily production from the properties
included in the Hess Acquisition during May and June 1996, the first two months
of ownership, was approximately 2,945 BOE/d. The average daily production on
these properties had increased to 5,373 BOE/d by the fourth quarter of 1997 and
had further increased to approximately 8,400 BOE/d during the month of January
1998.
As of December 31, 1997, in the Company's independent reserve report (the
"December Report"), the properties in the Hess Acquisition had estimated net
proved reserves of approximately 14.2 MMBOE with a PV10 Value of $95.1 million.
This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1
million PV10 Value on these same properties as reported in the Company's
independent reserve report dated July 1, 1996 (the "July Report"). The December
Report was calculated using year-end prices which were based on a WTI price of
$16.18 per Bbl and a NYMEX price of $2.58 per Mcf, with these representative
prices adjusted by field to arrive at the appropriate corporate net price, as
compared to oil and gas prices of $20.00 and $2.65, respectively, in the July
Report. In addition to the increase in proved reserves, the Company produced
approximately 2.6 MMBOE from July 1, 1996 through December 31, 1997 with total
net operating income of $30.5 million. As of December 31, 1997, the Company had
a remaining net investment in these properties of approximately $43.4 million.
9
<PAGE>
Company Business Strategy
The Company seeks to: (i) achieve attractive returns on capital through prudent
acquisitions, development and exploratory drilling and efficient operations;
(ii) maintain a conservative balance sheet to preserve maximum financial and
operational flexibility; and (iii) create strong employee incentives through
equity ownership. The Company believes that its growth to date in proved
reserves, production and cash flow is a direct result of its adherence to the
following fundamental principles which are at the core of the Company's
long-term growth strategy:
Experienced and Incentivized Personnel
The Company intends to maintain a highly competitive team of experienced and
technically proficient employees and motivate them through a positive work
environment and stock ownership in the Company. The Company's 29 geological and
engineering professionals have an average of over 15 years of experience in the
Gulf Coast region. The Company believes that employee ownership, which is
encouraged through the Company's stock option and stock purchase plans, is
essential for attracting, retaining and motivating quality personnel. The
Company believes that all employees are important to the success of the Company
and as such grants bonuses and stock options to both management and employees on
a basis roughly proportional to salaries.
Regional Focus
By focusing its efforts in the Gulf Coast region, primarily Louisiana and
Mississippi, the Company has been able to accumulate substantial geological and
reservoir data and operating experience which it believes provides it with
significant competitive advantages. The Company believes the Gulf Coast
represents one of the most attractive regions in North America given the
region's prolific production history, complex geology (with multiple producing
horizons) and the opportunities that have been created by advanced technologies
such as 3-D seismic and various drilling, completion and recovery techniques.
Disciplined Acquisition Strategy
The Company intends to continue to acquire properties where it believes
significant additional value can be created. Such properties are typically
characterized by: (i) long production histories; (ii) complex geological
formations with multiple producing horizons and substantial exploitation
potential; (iii) a history of limited operational focus and capital investment,
often due to their relatively small size and limited strategic importance to the
previous owner; and (iv) the potential for the Company to gain control of
operations. The Company believes that due to continuing rationalization of
properties, primarily by major integrated and independent energy companies,
future acquisition opportunities should continue to be available. In addition,
the Company seeks to maintain a well-balanced portfolio of oil and natural gas
development, exploitation and exploration projects in order to minimize the
overall risk profile of its investment opportunities while still providing
significant upside potential.
Operation of High Working Interest Properties
The Company intends to continue to acquire working interest positions that give
it operational control or that the Company believes may lead to operational
control. Once a property is acquired, the Company employs its technical and
operational expertise to fully evaluate a field's future potential. If
favorable, it will consolidate its working interest positions, primarily through
negotiated transactions, which tend to be attractively priced compared to
acquisitions available in competitive situations. The consolidation of ownership
allows the Company to: (i) enhance the effectiveness of its technical staff by
concentrating on relatively few wells; (ii) increase production while adding
virtually no additional personnel; and (iii) increase ownership in a property so
that the potential benefits of value enhancement activities justify the
allocation of Company resources.
Exploitation of Properties
The Company intends to maximize the value of its properties through a
combination of increasing production, increasing recoverable reserves or
reducing operating costs. During 1997, the Company's primary methodology for
achieving these objectives was the use of horizontal drilling, which it also
intends to emphasize in 1998. Horizontal drilling has historically produced oil
at faster rates and with lower operating costs on a BOE basis than traditional
vertical drilling. The Company also utilizes a variety of other techniques to
maximize property values, including: (i) undertaking surface improvements such
as rationalizing, upgrading or redesigning production facilities; (ii) making
downhole improvements such as resizing downhole pumps or reperforating existing
production zones; (iii) reworking existing wells into new production zones with
additional potential; and (iv) utilizing exploratory drilling, which is
frequently based on various advanced technologies such as 3-D seismic.
10
<PAGE>
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
11
<PAGE>
Operations in 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. Given the swampy conditions of southern
Louisiana, 3-D seismic has only recently become feasible for this area as
improvements in field recording techniques have made the process more
economical. 3-D seismic has become a valuable tool in exploration and
development throughout the onshore Gulf Coast and has been pivotal in
discovering significant reserves. The Company currently owns or has license to
work on over 300 square miles of 3-D seismic data and plans to continue to
expand its data ownership. The Company believes that this 3-D seismic data, some
of which is the first 3-D shot in these swampy areas, has the potential to
identify significant exploration prospects, particularly in the deeper
geopressured sections below 12,000 feet.
During 1995, the Company acquired approximately 46 square miles of 3-D seismic
data over five of its existing fields in Southern Louisiana, namely Bayou
Rambio, De Large, North Deep Lake, Gibson and Humphreys. During 1996, the
Company entered into a joint venture agreement with two industry partners and
shot approximately 158 square miles of 3-D seismic data in the Terrebonne Parish
area, which includes three of the Company's existing fields, Lirette, Lapeyrouse
and North Lapeyrouse. The Company's existing productive zones are excluded from
the joint venture. Denbury owns a one-third interest in any new prospects
discovered through this joint venture that currently owns rights to over 35,000
acres within the survey area. The 3-D seismic survey is complete and two wells
have been drilled to date based on the results of the survey. One was a dry hole
and the other a successful well in the Lirette Field area. There are currently
10 identified prospect areas which have been generated as a result of the
survey, of which three should be drilled during the first half of 1998. The 3-D
seismic survey is still being reviewed for additional drilling opportunities.
Lirette Field
The Lirette structure is a large salt-cored anticline located about 10 miles
south of Houma, Louisiana, which has produced over one Tcf of natural gas from
multiple reservoirs. The field is located in six to ten feet of inland water and
produces from depths of 8,000 feet to 16,000 feet. The field was discovered in
1937, but in 1993, when the Company first acquired a 23% working interest in the
field, gross production had declined to less than 3 MMcf/d. By January 1995,
following a series of workovers of existing wells, gross production had grown to
approximately 13.2 MMcf/d and 360 Bbls/d (6.5 MMcf/d and 150 Bbls/d net).
Additional interests were acquired in 1995 and 1997 to increase the Company's
ownership to its current average 82% working interest. During January 1998 the
net production from this field averaged approximately 10.6 MMcf/d and 177 Bbls/d
from 18 wells.
During the latter half of 1996, the Lirette Field was covered by a 3-D seismic
survey which is currently being evaluated. One well was drilled in the Lirette
area in 1997, the Scana No. 1 Laterre, as a result of this 3-D seismic survey.
This well established two pay sands in the prolific Tex W interval in a southern
untested fault block and should commence production in the first half of 1998.
Two additional untested fault blocks have been identified on the Lirette
structure and are scheduled for drilling during 1998.
Gibson Field
In late 1994, Denbury acquired minor working interests in five wells in the
Gibson and adjacent Humphreys Fields located in Terrebonne Parish, 20 miles
northwest of the Lirette Field, in the northern part of the Houma embayment. The
Gibson Field, since its discovery in 1937, has produced over 813 Bcf and 14
MMBbls. During 1995, the Company acquired and processed 38 square miles of 3-D
seismic data covering these fields and in November 1995 acquired a additional
working interest in these fields. By December 1995, Denbury's acreage position
had grown to 3,165 net acres with interests in six active wells and eight
inactive wells. During January 1998, the net production in this field averaged
approximately
12
<PAGE>
5.2 Mmcf/d and 83Bbls/d. Denbury drilled two wells in this area in 1997, one of
which was successful. This well, the Pelican A-12 found two productive intervals
and was completed in the lower most formation. This well produced at an average
rate of 460 Mcf/d net to the Company, during the month of January 1998. No wells
are currently plannned in this field for 1998.
South Chauvin Field
In February 1996, the Company purchased interests in two producing wells and
four non-producing wells in South Chauvin Field located in the Houma embayment
area, about four miles south of Houma and six miles northwest of Lirette Field.
Of the four currently producing wells at Chauvin, the Company owns an average
94% working interest. During January 1998, the net production from this field
average 2.5 MMcf/d and 29 Bbls/d. In late 1996, the Company acquired 13.7 square
miles of 3-D seismic data covering the field and is currently evaluating the
data. The Company drilled one well in this area in 1997 which produced at an
average rate of 1.3 MMcf/d and 17 Bbls/d, net to the Company, during the month
of January 1998. One well, a sidetrack of an existing well, is currently planned
in this field for 1998.
Bayou Rambio Field
Production at the Bayou Rambio Field was established in 1955 and has exceeded
150 Bcf and 920 MBbls to date. The Company operates three producing wells in the
field, which is located in Terrebonne Parish about 15 miles west of Lirette
Field. During January 1998, the net production from this field averaged 6.3
Mmcf/d and 59 Bbls/d. Two of these producing wells were drilled in 1997 based on
a review of 3-D seismic data. The Company has one additional well planned for
the first half of 1998 which will attempt to accelerate the production of the
established reserves and increase the field's PV10 Value, while also testing a
deeper sand interval which may establish additional pay sands.
Other Louisiana Fields
In addition to the above fields, the Company owns an interest in wells at 39
other fields in Louisiana, which in the aggregate averaged approximately 15.1
MMcf/d and 995 Bbls/d of net production during January 1998.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
13
<PAGE>
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
14
<PAGE>
Operations in 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. The Company has increased its emphasis in horizontal
drilling based on its apparent success during the past year. These horizontal
wells have contributed to the reduction of operating costs on a BOE basis during
the last twelve months, as these wells typically produce oil more efficiently,
resulting in higher production rates and better recovery efficiency.
The Company drilled its first horizontal well in 1995 at the South Thompson
Creek Field in Mississippi and drilled a subsequent horizontal well in this
field during 1996. Both of these wells were completed as producers. During the
last quarter of 1996 and through the end of 1997, the Company drilled and
completed twelve horizontal wells at an average cost of $1.05 million. These
wells produced at an average production rate of 420 Bbls/d in their initial
month of production. Although horizontal wells typically decline rapidly from
their initial production rates, these twelve wells had an average production
rate of 280 Bbls/d for the month of December 1997 and have been producing for an
average of seven months. These horizontal wells typically have a higher internal
rate of return than a comparable vertical well, reduce operating costs per BOE
and reduce the number of wells required to drain the reservoir. The Company
plans to drill over 50 horizontal wells in 1998 in Mississippi.
Heidelberg Field
Heidelberg field was discovered in 1944 and has produced an estimated 191 MMBbls
and 36 Bcf since its discovery. This Field is a large salt-cored anticline which
is divided by faulting into western and eastern segments. Production is from a
series of normally pressured Cretaceous and Jurassic sandstone horizons situated
between 4,500 feet and 11,500 feet. There are 11 producing formations in the
Heidelberg Field containing over 40 individual reservoir intervals, with the
majority of the current production coming from the Eutaw and Christmas sands at
depths of approximately 5,000 feet.
The West Heidelberg Eutaw sands have been unitized and water injection began
late in 1996 in order to increase the bottom hole pressure and improve
recoveries from the formation. A production response to the injection is
expected during 1998. The Eutaw East One Fault Block Oil Pool Unit (Eutaw
formation in East Heidelberg) was recently unitized and injection is projected
to commence in March 1998. These waterflood projects, particularly the East
Unit, comprise a significant portion of the potential reserves at Heidelberg.
The Company has a 78% working interest in the East Unit, 59% of which was
acquired in the Chevron Acquisition and the remaining 19% of which was acquired
over a three-month period from three other entities. The Company operates a
similar Eutaw unit at its East Eucutta Field, located approximately nine miles
to the southeast, with production from sands with similar porosity,
permeability, thickness, oil characteristics and drive mechanisms.
The Company has scheduled several potential development projects for 1998 during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 12 wells, recompleting 30
wells in new zones and drilling 41 wells. Horizontal wells drilled by the
Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily
production rates significantly as compared to vertical wells drilled in the same
fields. Consequently, the Company anticipates that 31 of the 41 proposed wells
will be horizontal wells. The Company's total 1998 development budget for the
Heidelberg Field is approximately $30 million. During January 1998, the net
production averaged approximately 2,750 Bbls/d.
Based on its experience in other fields in the same area, particularly with
regard to the Mississippi properties acquired in the Hess Acquisition, the
Company believes that significant additional reserve potential may exist beyond
the identified proven reserves. The development budget in 1998 and ensuing years
is expected, in part, to be used to evaluate this potential which is summarized
below:
Higher oil recovery in the Eutaw sand waterfloods
Since discovery of the Heidelberg Field, total cumulative production in the
Eutaw formation through December 1997 has been 80 MMBbls, which, based upon
geological and engineering analysis, the Company estimates has recovered 22% of
the original oil in place. Based upon a similar analysis, the Company estimates
that historical cumulative production from the
15
<PAGE>
Eutaw formation under waterflood at nearby East Eucutta Field has recovered an
estimated 34% of the oil in place. The Company believes that similar recovery
factors may be achievable at Heidelberg Field based on the geological conditions
that appear to be analogous. The Company will also attempt to improve the
recovery factors through the use of horizontal drilling and may also employ
tertiary recovery methods such as carbon dioxide injection. The Company
currently is evaluating the feasibility of such methods.
Higher oil recovery in the Christmas sands
Because of the success of the Company's horizontal drilling program in other
fields in the area, the Company intends to develop the Christmas sands primarily
through horizontal drilling. Since its discovery, the Christmas sands have
produced approximately 67 MMBbls through December 1997. The Company believes
these sands are ideal for horizontal development due to the strong natural water
drive of these reservoirs. Recent horizontal drilling by the Company has
produced oil at higher rates and reduced operating costs on a BOE basis as
compared to vertical drilling. Although Denbury believes that horizontal
drilling should ultimately increase the amount of oil recovered from the
Christmas sands, to date the Company does not have enough production history to
determine if, and to the extent, oil recoveries will increase.
Further drilling in deeper zones
The zones below the Christmas formation, including the Tuscaloosa, Paluxy,
Rodessa, Hosston, Cotton Valley and Smackover formations, have produced on a
cumulative basis a combined 44 MMBbls and 14 Bcf through December 1997. The
Company believes that additional reserve potential may exist for extensions of
existing reservoirs and potential new reservoirs in these zones within the
Heidelberg Field area. A 36-square-mile 3-D seismic program over the field was
shot by Chevron in 1993 and will be acquired under license by Denbury. The
Company intends to reprocess the 3-D seismic data to evaluate this potential.
Eucutta Field
The Eucutta Field is located about 18 miles east of Laurel, Mississippi. Since
its discovery in 1943, this field has produced 63 MMBbls and 4.7 Bcf. Denbury
acquired the majority of its interests in this field as part of the Hess
Acquisition and currently operates 45 producing oil wells and 3 saltwater
injection wells.
The Eucutta Field is divided into a shallow Eutaw sand unit in which the Company
has a 78% working interest and the deeper Tuscaloosa, Wash-Fred, Paluxy,
Rodessa, Sligo and Hosston sand zones in which the Company has an average
working interest of 99%. The Eucutta Field traps oil in multiple sandstone
reservoirs from the Eutaw to the Hosston formations in this highly faulted
anticline from depths of 5,000 to 11,000 feet. Denbury recently established new
production in the Paluxy interval in a series of six stacked sands. As of
February 28, 1998, two additional vertical delineation wells and five horizontal
wells have been drilled and completed for this Paluxy interval, with an
additional four either in progress or planned for 1998. These recently completed
horizontal wells had average initial production rates of approximately 1,300
Bbls/d. Although these wells are expected to have high initial decline rates, at
the current rate, these wells should pay out in approximately three months. The
deeper intervals of the Cotton Valley and Smackover formations have yet to be
tested in crestal positions on this structure although these two horizons have
proven to be highly productive throughout the Mississippi Salt Basin.
Bar graph illustrating Mississippi portion of Hess Acquisition
1996 1997
--------------------- ---------------------
Proved Daily Proved Daily
Reserves Production Reserves Production
--------- --------- --------- ---------
Third Quarter 4.2 1,580 First Quarter (1) 2,769
Fourth Quarter 6.8 2,323 Second Quarter (1) 3,364
Third Quarter (1) 4,079
Fourth Quarter 12.6 4,514
(1) Not available
Since its acquisition in May 1996, the Company has implemented a capital
expenditure program at Eucutta Field which included upgrading production
facilities, recompletions and drilling wells. At the time of acquisition,
production from this field was approximately 1,100 Bbls/d. All seven wells
drilled in 1997 were successful, two of which were horizontal wells. As a result
of these wells and other development work, during January 1998 the net
production increased to an average of 5,255 Bbls/d. The Company plans to shoot a
3-D seismic survey over the field and have it processed by late 1998. During
1998, the Company also plans to drill 16 wells, of which nine will be horizontal
wells.
16
<PAGE>
Davis Field.
The Davis Field is located 42 miles northeast of Laurel in the northern part of
the Mississippi salt basin. Denbury operates 36 producing wells within the area.
Davis is a compact anticline that has produced over 21 MMBbls since its
discovery by Conoco in 1969. Over 30 sands have produced oil between the
intervals of 5,000 feet and 8,000 feet. At the time of acquisition in 1993, the
gross production from this field was approximately 700 Bbls/d. During the month
of January 1998, the gross production was approximately 920 Bbls/d with net
production of 823 Bbls/d.
The Davis Field is a relatively mature field and produces large amounts of
saltwater. During January 1998, the field produced an average of approximately
50,000 barrels of saltwater per day, all of which were re-injected into the
ground. The Company places considerable emphasis on controlling operating costs
in this field by minimizing the cost of saltwater disposal and pumping
equipment.
Since acquiring the majority of the Davis Field in 1993, Denbury has undertaken
an active redevelopment program including numerous workovers and several
development wells. As a result of this work and continued reductions in
operating costs, the Company has been able to steadily increase the proven
reserves every year. During 1996, the Company drilled two successful horizontal
wells to improve withdrawal efficiency and drilled an additional three
horizontal wells in 1997, with one additional well in progress as of December
31, 1997. The Company plans to drill three to five wells in this field during
1998, of which all but one will be horizontal wells.
Quitman Field
The Quitman Field is located in Clarke County, Mississippi, 31 miles northeast
of Laurel and near the Davis Field. The Company acquired the field as part of
the Hess Acquisition and now operates 18 producing wells. The Company owns an
average working interest of 93%. The Quitman Field was discovered in 1966 and
has since produced approximately 21 MMBbls from 18 separate reservoirs between
7,500 feet and 12,000 feet. The principal producing zones at Quitman Field are
the Smackover formation and several sands in the Cotton Valley formation.
Since its acquisition in May 1996, the Company has implemented a capital
expenditure program at Quitman Field which has included upgrading production
facilities and drilling wells. At the time of acquisition, the net production
from this field was approximately 200 Bbls/d. During January 1998, the net
production averaged 1,495 Bbls/d. All five wells drilled in 1997 were
successful, of which two were horizontal wells. During 1998, the Company plans
to drill four wells, of which three will be horizontal wells.
Other Mississippi Fields
In addition to the above fields, Denbury owns an interest in wells in 35 other
fields in Mississippi, which in the aggregate averaged approximately 1,819
Bbls/d and 2.6 MMcf/d of net production during January 1998.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
17
<PAGE>
Selected Abbreviations
Bbls ~ Barrels of oil
Bbl/d ~ Barrels of oil produced per day
Bcf ~ Billion cubic feet of natural gas
BOE ~ Barrel of oil equivalent
using the ratio of one barrel of
crude oil to 6 Mcf of
natural gas
BOE/d ~ Barrel of oil equivalent
produced per day
Btu ~ British thermal unit
MBbls ~ Thousand barrels of oil
MBOE ~ Thousand BOE
MBOE/d ~ Thousand barrels of oil
equivalent produced per day
MBtu ~ Thousand Btu
Mcf ~ Thousand cubic feet of natural gas
Mcf/d ~ One thousand cubic feet
of natural gas produced per day
MMBbls ~ Million barrels of oil
MMBOE ~ Million BOE
MMBtu ~ Million Btu
MMcf ~ Million cubic feet of natural gas
MMcf/d ~ Million cubic feet of
natural gas produced per day
PV10 Value ~ Estimated future revenue to be generated from the production of
proved reserves, net of estimated production and development
costs, using prices in effect awt the determination date,
without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future
income taxes or to depreciation and amortization, discounted to
present value using an annual discount rate of 10% in
accordance with the guidelines of the Securities and Exchange
Commission.
Tcf ~ Trillion cubic feet of
natural gas
Financial Table of Contents
Management's Discussion &
Analysis 19
Independent Auditors' Report 27
Financial Statements 28
Shareholder Information 48
18
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Denbury is an independent energy company engaged in acquisition, development and
exploration activities in the U.S. Gulf Coast region, primarily onshore in
Louisiana and Mississippi. Over the last four years, the Company has achieved
rapid growth in proved reserves, production and cash flow by concentrating on
the acquisition of properties which it believes have significant upside
potential and through the efficient development, enhancement and operation of
those properties.
Acquisition of Chevron Properties
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202 million
(the "Chevron Acquisition"). The Chevron Acquisition represents the largest
acquisition by the Company to date. The Heidelberg Field is adjacent to the
Company's other primary oil properties in Mississippi and includes 122 producing
wells, 96 of which the Company will operate. The Company purchased an average
working interest of 94% and an average net revenue interest of 81% in these 96
wells, which wells account for approximately 99% of the field's average net
daily production. The average net daily production from these properties during
the fourth quarter of 1997 was approximately 2,800 Bbls/d and 650 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed $75 million of the purchase price to unevaluated properties.
The Company has scheduled several potential development projects for 1998 during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 12 wells, recompleting 30
wells in new zones and drilling 41 new wells. Horizontal wells drilled by the
Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily
production rates significantly as compared to vertical wells drilled in the same
fields. Consequently, the Company anticipates that 31 of the 41 proposed wells
in the Heidelberg Field will be horizontal wells. The Company's total 1998
development budget for the Heidelberg Field is approximately $30 million.
Bar graph illustrating Acquisition Expenditures (in millions of dollars)
1995 1996 1997
----- ----- ------
New $2.6 $41.4 $216.4
Incremental 14.2 7.0 7.7
Update on 1996 Hess Acquisition
The Company completed several property acquisitions during 1996, the largest of
which was the acquisition of producing oil and natural gas properties,
principally in Mississippi and Louisiana, for approximately $37.2 million from
Amerada Hess, effective May 1, 1996 (the "Hess Acquisition"). The average daily
production from the properties included in the Hess Acquisition during May and
June 1996, the first two months of ownership, was approximately 2,945 BOE/d. The
average daily production on these properties had increased to 5,969 BOE/d by the
fourth quarter of 1997.
As of December 31, 1997, in the Company's independent reserve report (the
"December Report"), the properties in the Hess Acquisition had estimated net
proved reserves of approximately 14.2 MMBOE with a PV10 Value of $95 million.
This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1
million PV10 Value on these same properties as reported in the Company's
independent reserve report dated July 1, 1996 (the "July Report"). The December
Report was calculated using year-end prices which were based on a West Texas
Intermediate ("WTI") price of $16.18 per Bbl and a NYMEX Henry Hub price of
$2.58 per MMBtu, with these representative prices adjusted by field to arrive at
the appropriate corporate net price, as compared to oil and gas prices of $20.00
and $2.65, respectively, in the July Report. In addition to the increase in
proved reserves, the Company produced approximately 2.6 MMBOE from July 1, 1996
through December 31, 1997 with total net operating income during the period of
$32.1 million. The Company has incurred $38.3 million of capital cost during the
same period, leaving a net investment as of December 31, 1997 of $43.4 million.
19
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
1998 Public Debt and Equity Offering
On February 26, 1998, the Company closed its public sale of 5,240,780 Common
Shares (which included the underwriter's over-allotment option of 683,580 Common
Shares) at a price 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,
affiliates of the Texas Pacific Group ("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 were approximately $88.6 million, before
offering expenses.
Concurrently with the Equity Offering and TPG Purchase, Denbury Management Inc.,
a wholly-owned subsidiary of the Company, issued $125 million in aggregate
principal amount of 9% Senior Subordinated Notes Due 2008 (the "Debt Offering"
and the "Notes"). These Notes contain certain 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
$209.8 million after deducting the estimated offering expenses of $600,000. The
Company used these proceeds to reduce outstanding borrowings under the Company's
bank credit facility, the majority of which had been borrowed to fund the $202
million Chevron Acquisition.
Pie Charts illustrating Capitalization
In Millions of Dollars 12/31/97 02/28/98
-------- --------
Bank 240 40
Common 133 221
Subordinated Debt - 125
Retained Earnings 27 27*
* 12/31 Amount
Restated Credit Facility
The Company has a credit facility (the "Credit Facility") with NationsBank of
Texas, N.A., as agent for 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 Chevron
Acquisition. As of December 31, 1997, the Company had an outstanding balance on
this facility of $240 million. This balance was reduced to $40 million as of
February 28, 1998 after application of the net proceeds from the Debt and Equity
Offerings and the TPG Purchase (collectively the "Capital Transactions"), net of
$9.8 million of additional borrowings. The Credit Facility consists of a
five-year revolving credit facility with a borrowing base (after the Capital
Transactions) of $165 million. This borrowing base is subject to review every
six months and the Credit Facility is secured by substantially all of the
Company's oil and natural gas properties, except for those acquired in the
Chevron Acquisition. Interest is payable on the revolving credit facility at
either the prime rate or, depending on the percentage of the borrowing base that
is outstanding, at rates ranging from LIBOR plus 7/8% to LIBOR plus 13/8%. The
Credit Facility has several restrictions, including, among others: (i) a
prohibition on the payment of dividends; (ii) a requirement for a minimum equity
balance; (iii) a requirement to maintain positive working capital (as defined in
the Credit Agreement); (iv) a minimum interest coverage test; and (v) a
prohibition on most debt, lien and corporate guarantees.
Capital Resources and Liquidity
As discussed below, in each of the last three years, the Company's capital
expenditures required additional debt and equity capital to supplement cash flow
from operations.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
DOLLARS IN THOUSANDS 1997 1996 1995
------- -------- --------
<S> <C> <C> <C>
Acquisitions of oil and natural $224,145 $48,407 $16,763
gas properties
Oil and natural gas expenditures 81,282 38,450 11,761
- ---------------------------------------------------------------
Total $305,427 $86,857 $28,524
- ---------------------------------------------------------------
</TABLE>
From January 1, 1995, through December 31, 1997, the Company has made total
capital expenditures of $420.8 million. These capital expenditures were funded
by the issuance of equity ($105.3 million), bank debt ($225.1 million) and cash
generated by operations ($90.4 million). As of December 31, 1997, the Company
had minimal working capital with approximately $240 million of bank debt
outstanding. On February 26, 1998, $200 million of the bank debt was repaid with
proceeds from the Capital Transactions, leaving the Company with a total debt
balance of $165 million ($40 million of bank debt and $125 million of Notes).
20
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Bar graph illustrating Capital Expenditures (in millions of dollars)
1995 1996 1997
------ ------ ------
Development 11.7 38.5 81.3
Acquisitions 16.8 48.4 224.1
Although the Company is still reviewing its budget, particularly in light of the
recent Chevron Acquisition, the Company is currently budgeting capital
expenditures for 1998 of approximately $95 million, of which approximately $30
million is allocated for the properties included in the Chevron Acquisition.
Although the Company's projected cash flow is highly variable and difficult to
predict as it is dependent on product prices, drilling success and other
factors, these projected expenditures are expected to exceed the Company's cash
flow during 1998. Even though the recent reduction in oil product prices has
significantly reduced the Company's projected 1998 cash flow and net income, as
of February 28, 1998, the Company had an unused borrowing base of $125 million
under the Credit Facility to fund any potential cash flow deficits. Furthermore,
if external capital resources are limited or reduced in the future, the Company
can also adjust its capital expenditure program accordingly. However, such
adjustments could limit, or even eliminate, the Company's future growth.
In addition to its internal capital expenditure program, the Company has
historically required capital for the acquisition of producing properties, which
have been a major factor in the Company's rapid growth during recent years.
There can be no assurance that suitable acquisitions will be identified in the
future or that any such acquisitions will be successful in achieving desired
profitability objectives. Although the Company does not anticipate that the
recent reduction in oil prices will require the Company to reduce its planned
development program, it could limit the amount of funds available for
acquisitions. Without suitable acquisitions or the capital to fund such
acquisitions, the Company's future growth could be limited or even eliminated.
Sources and Uses of Funds
During 1997, the Company spent approximately $81.3 million on exploration and
development expenditures and approximately $224.1 million on acquisitions, the
majority of which related to the $202 million Chevron Acquisition. The
exploration and development expenditures included approximately $55.9 million
spent on drilling, $9 million on geological, geophysical and acreage
expenditures and $16.4 million on workover costs. These expenditures were funded
by available cash, bank debt and cash flow from operations.
During 1996, the Company spent approximately $33.4 million on oil and natural
gas development expenditures, $37.2 million on the Hess Acquisition, $7.5
million on properties acquired in April 1996 (the "Ottawa Acquisition"), $3.7
million on other minor oil and natural gas acquisitions, and approximately $5.1
million on geological, geophysical and acreage expenditures. The development
expenditures included $15.5 million spent on drilling and 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.
During 1995, the Company made $28.5 million in capital expenditures, with the
single largest component being a $10 million acquisition of seven producing
wells in the Gibson and Humphreys Fields located near the Company's other
properties in southern Louisiana (the "Gibson Acquisition"). The balance of 1995
acquisition expenditures were for additional interests in the Company's Lirette
Field in Louisiana ($2.9 million), interests in the Bully Camp Field, also in
Louisiana ($2.1 million), and a few smaller acquisitions in both Mississippi and
Louisiana. During 1995, the Company also spent $1.9 million on drilling, $1.1
million for acreage and geological and geophysical expenditures, and the balance
of $8.1 million on workovers costs. The 1995 expenditures were funded on an
interim basis with cash flow from operations ($9.4 million) and bank debt ($19.4
million), which was repaid in December 1995 with a portion of the $39.5 million
of net proceeds from a private placement of equity with TPG.
21
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
RESULTS OF OPERATIONS
Operating Income
During the last three years, operating income has increased significantly as
outlined in the following table. Oil and natural gas revenue increased as a
result of the increased oil and natural gas production and strong oil and
natural gas product prices.
<TABLE>
<CAPTION>
Year ended December 31,
- ------------------------------------ -------------------------
1997 1996 1995
- ------------------------------------ -------------------------
OPERATING INCOME (THOUSANDS)
<S> <C> <C> <C>
Oil sales $49,748 $28,475 $10,852
Natural gas sales 35,585 24,405 9,180
Less production expenses (22,218) (13,495) (6,789)
- ------------------------------------ -------------------------
Operating income $63,115 $39,385 $13,243
- ------------------------------------ -------------------------
UNIT PRICES
Oil price per Bbl $ 17.25 $18.98 $ 14.90
Gas price per Mcf 2.68 2.73 1.90
- ------------------------------------ -------------------------
NETBACK PER BOE
Sales price $ 16.75 $ 17.69 $ 13.05
Production expenses (4.36) (4.51) (4.42)
- ------------------------------------ -------------------------
$12.39 $13.18 $8.63
- ------------------------------------ -------------------------
AVERAGE DAILY PRODUCTION VOLUME:
Bbls 7,902 4,099 1,995
Mcf 36,319 24,406 13,271
BOE 13,955 8,167 4,207
- ------------------------------------ -------------------------
</TABLE>
Bar graph illustration of average daily oil & natural gas production by quarter
(BOE basis):
1993 1994 1995 1996 1997
------ ------ ------ ------ -------
First Quarter 756 2,384 3,800 5,453 12,256
Second Quarter 848 2,527 3,885 7,841 13,404
Third Quarter 1,473 2,981 4,062 9,208 14,195
Fourth Quarter 1,682 3,528 5,067 10,132 15,922
Historically, the Company has grown from both acquisitions and internal
development and exploitation of the acquired properties. This is best evidenced
by the fact that approximately 52% of the Company's historical reserves have
been obtained from acquisitions and the remaining 48% from internal development
(excluding the Chevron Acquisition on December 30, 1997). Although the
production increases do not necessarily always directly correlate with reserve
additions, production increases have also been fueled by both internal growth
from the Company's development and exploitation programs and from the property
acquisitions. Between 1995 and 1996, production increased 94% with approximately
2,550 BOE/d attributable to the properties included in the Hess and Ottawa
Acquisitions and 750 BOE/d attributable to properties included in the Gibson
Acquisition. The balance of approximately 660 BOE/d was attributable to internal
growth on other properties. However, between 1996 and 1997, production
22
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
increased 71% with approximately 94% of the increase from internal growth and
the balance from acquisitions. Most of this internal growth is attributable to
the properties acquired in the Hess Acquisition in 1996 as production has
increased from 2,945 BOE/d during the first two months of ownership (May and
June, 1996) to approximately 5,969 BOE/d during the fourth quarter of 1997.
Bar graph illustrating oil prices
Dollars per Bbl 1995 1996 1997
----- ----- -----
14.90 18.98 17.25
Oil and natural gas revenue has increased not only because of the large
increases in production, but also due to improved product prices since 1995.
During 1996, product prices increased substantially with a 27% increase in the
average oil price and a 44% increase in the average natural gas price. Coupled
with the production increases, the Company's oil and natural gas revenue
increased 164%, or $32.8 million, from 1995 to 1996. Approximately $21.9 million
of the increase was related to properties acquired in the Hess, Ottawa and
Gibson Acquisitions, approximately $7.7 million due to the increase in product
prices and the balance of approximately $3.2 million due to increased production
from internal growth on other properties. Between 1996 and 1997, oil and natural
gas revenue increased 61%, primarily as a result of the increased production (on
a BOE basis), as oil and natural gas prices decreased 5% on a BOE basis. This
price change consisted of a 9% decline in oil prices and a more modest decline
of 2% in natural gas prices. Only $1.4 million of the revenue increase during
1997 was related to acquisitions during the year.
Bar graph illustrating natural gas prices
Dollars per Mcf 1995 1996 1997
----- ----- -----
1.90 2.73 2.68
Total production expenses increased each year along with the increases in
production, although on a BOE basis, production expenses increased only 2% from
1995 to 1996 and decreased 3% from 1996 to 1997. The 1996 increase was largely
attributable to a change in the mix of properties as the Mississippi oil
properties tend to have a higher operating cost per BOE than the Louisiana gas
properties. During the first two months of ownership (May and June 1996), the
production expenses averaged $6.27 per BOE on the Hess Acquisition properties
which were more heavily weighted toward Mississippi oil than Louisiana gas.
After assuming operations, these averages were brought more in line with the
Company averages through cost savings and increased production levels and for
the seven months ended December 31, 1996, production expenses on these
properties averaged $5.35 per BOE.
During 1997, the Company was able to lower operating costs per BOE through its
cost savings efforts and by increasing production without a corresponding
increase in the number of properties. For the properties acquired in the Hess
Acquisition, operating expenses declined 15% from the 1996 level of $5.35 per
BOE to an average of $4.56 per BOE. The Company's recent emphasis on horizontal
drilling contributed to these production increases and resultant savings, even
though the Company's production became even more weighted towards oil (which has
higher operating costs) with 57% of the 1997 BOE production coming from oil as
compared to 50% of the Company's 1996 BOE production coming from oil.
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,
- ----------------------------------------------------------
1997 1996 1995
- ----------------------------------------------------------
NET G&A EXPENSES (THOUSANDS)
<S> <C> <C> <C>
Gross expenses $ 13,909 $8,407 $3,900
State franchise taxes 428 213 100
Operator overhead charges (5,502) (2,916) (1,438)
Capitalized exploration expenses (2,225) (1,224) (630)
- ----------------------------------------------------------
Net expenses $ 6,610 $4,480 $1,932
- ----------------------------------------------------------
Average G&A cost per BOE $ 1.30 $ 1.50 $ 1.25
Employees as of December 31 157 122 51
- ----------------------------------------------------------
</TABLE>
On a BOE basis, these costs increased 20% from 1995 to 1996 but decreased 13%
from 1996 to 1997, almost returning to the 1995 level. As a result of improved
financial results during the first quarter of 1996 and other factors, the
Company conducted a review of salaries and awarded increases and bonuses in
February 1996 to its employees. Bonuses, including related payroll taxes,
23
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
amounted to approximately $225,000 ($.08 per BOE). During 1996, the Company also
accrued $545,000 ($.18 per BOE) for bonuses which were awarded in February 1997.
In addition, the Company began to increase its staff levels during the second
quarter of 1996 to handle the Hess Acquisition, but was not entitled to any
operator's overhead recovery on these properties until July 15, 1996, further
fueling an increase in general and administrative cost per BOE, as Amerada Hess
remained the operator of record until that date.
The decrease in G&A expense on a BOE basis during 1997 was partially
attributable to the increased production on both an absolute and per well basis.
Furthermore, the respective well operating agreements allow the Company, when it
is the operator, to charge a well with a specified overhead rate during the
drilling phase. As a result of the increased drilling activity in 1997 (44 wells
drilled during 1997 versus 10 wells drilled during 1996), the percentage of
gross G&A recovered through these types of allocations (listed in the above
table as "Operator overhead charges") increased when compared to the
corresponding periods of 1996. During 1996, approximately 35% was recovered by
operator overhead charges, while during 1997 this recovery increased to 40%.
Bar graph illustrating dollars per BOE.
1995 1996 1997
----- ------ -----
Cash flow 6.12 11.42 11.11
Interest 1.26 .26 -
G&A 1.25 1.50 1.30
Production 4.42 4.51 4.36
Interest and Financing Expenses
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- ------------------------------------ -------------------------
AMOUNTS IN THOUSANDS EXCEPT PER
UNIT AMOUNTS 1997 1996 1995
- ------------------------------------ -------------------------
<S> <C> <C> <C>
Interest expense $ 1,111 $1,993 $2,085
Non-cash interest expense (91) (459) (90)
- ------------------------------------ -------------------------
Cash interest expense 1,020 1,534 1,995
Interest and other income (1,123) (769) (77)
- ------------------------------------ -------------------------
Net interest expense (income) $ (103) $ 765 $ 1,918
- ------------------------------------ -------------------------
Average interest expense (income)
per BOE $ (0.02) $ 0.26 $ 1.26
Average debt outstanding $12,700 $19,500 $21,400
Average interest rate 6.9% 7.9% 9.3%
Ratio of earnings to fixed charges 19.9 4.6 1.5
- --------------------------------------------------------------
Imputed preferred dividend $ - $ 1,281 $ -
Loss on early extinguishment of debt - 440 200
- --------------------------------------------------------------
</TABLE>
During the first half of 1996 and 1997, the Company had minimal debt outstanding
as virtually all of the bank debt had been retired during the previous fourth
quarter. In 1995, the bank debt was repaid with proceeds from the December 1995
private placement of equity with TPG and in 1996 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 balance of $240 million late in
the fourth quarter to fund the Chevron Acquisition.
The private placement of equity in December 1995 with TPG included 1.5 million
Convertible Preferred Shares. 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.
Under Canadian generally accepted accounting principles ("GAAP"), this dividend
was reported as an operating expense, while under U.S. GAAP this would not be an
expense but it would be deducted from net income to arrive at net income
attributable to the common shareholders. In addition to paying off its bank debt
and converting the Convertible Preferred into common equity during 1996, the
Company also converted its remaining subordinated debt into common equity,
leaving the Company essentially debt-free as of December 31, 1996.
During 1996, the Company had a $440,000 charge relating to a loss on early
extinguishment of debt. These costs related to the remaining unamortized debt
issue costs of the Company's prior credit facility which was replaced in May
1996. The Company also had a charge of $200,000 during the first half of 1995
for the same type of expense relating to a previous bank refinancing. Under U.S.
GAAP, a loss on early extinguishment of debt would be an extraordinary item
rather than a normal operating expense as required by Canadian GAAP.
24
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Depletion, Depreciation, Amortization and Site Restoration
Depletion, depreciation and amortization ("DD&A") has increased along with the
additional capitalized cost and increased production. DD&A per BOE increased 15%
from 1995 to 1996 primarily due to 59% of the 1995 capital expenditures and 56%
of the 1996 expenditures relating to property acquisitions, which often have a
higher per unit cost than those reserves added by development expenditures.
The oil prices used in the December 31, 1996 reserve report were based on a WTI
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 while the comparable WTI price in the
December 31, 1997 reserve report was $16.18 per Bbl. Using 1996 prices, the
Company's proved oil reserves would have been 2.1 MMBOE higher (excluding the
properties acquired in the Chevron Acquisition). This loss of reserves due to
product price decreases caused DD&A to increase approximately $0.29 per BOE
during 1997. Overall, DD&A increased $0.43 per BOE during 1997 (7%) with the
balance of the increase resulting from rising drilling costs, particularly in
Louisiana.
Bar graph illustrating proven reserves. (in millions of BOE)
1995 1996 1997
---- ---- ----
Chevron - - 27.6
Oil 6.3 15.0 24.8
Natural Gas 8.0 12.4 12.5
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 1997 1996 1995
- ------------------------------------ -------------------------
<S> <C> <C> <C>
Depletion and depreciation $32,311 $17,533 $7,918
Site restoration provision 408 371 104
- ------------------------------------ -------------------------
Total amortization $32,719 $17,904 $8,022
- ------------------------------------ -------------------------
Average DD&A cost per BOE $ 6.42 $ 5.99 $ 5.22
- ------------------------------------ -------------------------
</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 income tax provision. The deferred income
tax provision as a percentage of net income has varied depending on the mix of
Canadian and U.S. expenses. The 1996 rate was highest of the three years
outlined below due to the non-deductible imputed preferred dividend and interest
on the subordinated debt during that year.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- ------------------------------------ ------------------------
1997 1996 1995
- ------------------------------------ ------- ------- -------
<S> <C> <C> <C>
Deferred income taxes (thousands) $ 8,895 $ 5,312 $ 367
Average income tax costs per BOE $ 1.75 $ 1.78 $ 0.24
Effective tax rate 37% 38% 34%
- ------------------------------------ ------- ------- -------
</TABLE>
Bar graphs illustrating cash flow and net income. (in millions of dollars)
1995 1996 1997 1995 1996 1997
----- ---- ----- ---- ---- ----
Cash flow from operations
excluding the change in
working capital items 9.4 34.1 56.6 Net Income 0.7 8.7 14.9
25
<PAGE>
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Net Income
Primarily as a result of increased production and strong product prices, net
income and cash flow from operations increased substantially from 1995 through
1997 as outlined below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- ------------------------------------ -------------------------
AMOUNTS IN THOUSAND EXCEPT PER
SHARE AMOUNTS 1997 1996 1995
- ------------------------------------ ------- ------- -------
<S> <C> <C> <C>
Net income $14,903 $ 8,744 $ 714
Net income per common share:
Basic $ 0.74 $0.67 $ 0.10
Fully diluted 0.70 0.62 0.10
Cash flow from operations (a) $56,607 $34,140 $ 9,394
- ------------------------------------ ------- ------- -------
<FN>
(a) 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 net income 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 1997 1996 1995
- ------------------------------------ ---------------------------
<S> <C> <C> <C>
Revenue $16.75 $17.69 $13.05
Production expenses (4.36) (4.51) (4.42)
- ---------------------------------------------------------------------
Production netback 12.39 13.18 8.63
General and administrative (1.30) (1.50) (1.25)
Interest and other income (expense) 0.02 (0.26) (1.26)
- ---------------------------------------------------------------------
Cash flow from operations (a) 11.11 11.42 6.12
DD&A (6.42) (5.99) (5.22)
Deferred income taxes (1.75) (1.78) (0.24)
Other non-cash items (0.01) (0.72) (0.19)
- ---------------------------------------------------------------------
Net income $ 2.93 $ 2.93 $ 0.47
- ---------------------------------------------------------------------
<FN>
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
Year 2000 Modifications
The Company is currently reviewing its computer systems in order to evaluate
necessary modifications for the year 2000 and is also making inquiries with
regard to the systems used by its oil and natural gas purchasers and other third
parties that the Company relies on as part of its normal business. The Company
does not believe that it will incur any material expenditures, nor require any
significant modifications to make its internal systems year 2000 compliant;
however, it has not yet fully evaluated the status of third-party systems and
the effect, if any, on the Company if third-party systems are not year 2000
compliant.
Recently Issued Accounting Standards
See discussion of Recently Issued Accounting Standards in Note 8 of the
Consolidated Financial Statements.
26
<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, 1997 and 1996 and the consolidated statements of income, changes in
shareholders' equity and cash flows for each of the years in the three year
period ended December 31, 1997. 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, 1997
and 1996 and the results of its operations and the changes in shareholders'
equity and cash flows for each of the years in the three year period ended
December 31, 1997, in accordance with accounting principles generally accepted
in Canada.
Deloitte & Touche
Chartered Accountants
Calgary, Alberta
February 27, 1998
27
<PAGE>
Consolidated Balance Sheets
<TABLE>
<CAPTION>
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31,
--------------------
1997 1996
-------- ---------
ASSETS
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents................... $ 9,326 $ 13,453
Accrued production receivable............... 8,692 11,906
Trade and other receivables................. 15,362 3,643
-------- ---------
Total current assets ............. 33,380 29,002
-------- ---------
PROPERTY AND EQUIPMENT (USING FULL COST
ACCOUNTING)
Oil and natural gas properties.............. 388,766 159,724
Unevaluated oil and natural gas properties.. 82,798 6,413
Less accumulated depreciation and depletion. (62,732) (31,141)
-------- ---------
Net property and equipment........... 408,832 134,996
-------- ---------
OTHER ASSETS................................... 5,336 2,507
-------- ---------
TOTAL ASSETS........................ $447,548 $ 166,505
======== =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities.... $ 24,616 $ 10,903
Oil and gas production payable.............. 6,052 5,550
Current portion of long-term debt .......... 20 67
-------- ---------
Total current liabilities........... 30,688 16,520
-------- ---------
LONG-TERM LIABILITIES
Long-term debt.............................. 240,000 125
Provision for site reclamation costs........ 1,017 613
Deferred income taxes and other............. 15,620 6,743
-------- ---------
Total long-term liabilities......... 256,637 7,481
-------- ---------
SHAREHOLDERS' EQUITY
Common shares, no par value, unlimited
shares authorized; outstanding - 20,388,683
and 20,055,757 shares at December 31, 1997
and December 31, 1996, respectively....... 133,139 130,323
Retained earnings........................... 27,084 12,181
-------- ---------
Total shareholders' equity.......... 160,223 142,504
-------- ---------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $447,548 $ 166,505
======== =========
</TABLE>
Approved by the Board:
/s/ Gareth Roberts /s/ Wieland F. Wettstein
- ------------------------- -----------------------------
Gareth Roberts Wieland Wettstein
Director Director
See Notes to Consolidated Financial Statements
28
<PAGE>
Consolidated Statements of Income
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE
AMOUNTS (U.S. DOLLARS) 1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
REVENUES
Oil, natural gas and related product
sales................................ $85,333 $52,880 $20,032
Interest income and other............... 1,123 769 77
------- ------- -------
Total revenues.................... 86,456 53,649 20,109
------- ------- -------
EXPENSES
Production.............................. 22,218 13,495 6,789
General and administrative.............. 6,182 4,267 1,832
Interest................................ 1,111 1,993 2,085
Imputed preferred dividends............. - 1,281 -
Loss on early extinguishment of debt.... - 440 200
Depletion and depreciation.............. 32,719 17,904 8,022
Franchise taxes......................... 428 213 100
------- ------- -------
Total expenses................... 62,658 39,593 19,028
------- ------- -------
Income before income taxes................... 23,798 14,056 1,081
Provision for income taxes................... (8,895) (5,312) (367)
------- ------- -------
NET INCOME................................... $14,903 $ 8,744 $ 714
======= ======= =======
NET INCOME PER COMMON SHARE..................
Basic..................................... $ 0.74 $ 0.67 $ 0.10
Fully diluted............................. $ 0.70 $ 0.62 $ 0.10
Average number of common shares outstanding.. 20,224 13,104 6,870
======= ======= =======
</TABLE>
See Notes to Consolidated Financial Statements
29
<PAGE>
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1997 1996 1995
------- ------- --------
CASH FLOW FROM OPERATING ACTIVITIES:
<S> <C> <C> <C>
Net income.................................. $14,903 $ 8,744 $ 714
Adjustments needed to reconcile to net
cash flow provided by operations:
Depreciation, depletion and amortization. 32,719 17,904 8,113
Deferred income taxes.................... 8,895 5,312 367
Imputed preferred dividend............... - 1,281 -
Loss on early extinguishment of debt..... - 440 200
Other.................................... 90 459 -
------- ------- --------
56,607 34,140 9,394
Changes in working capital items relating
to operations:
Accrued production receivable............ 3,214 (8,694) (1,303)
Trade and other receivables.............. (11,719) (1,508) (168)
Accounts payable and accrued liabilities. 13,713 6,711 (1,660)
Oil and gas production payable........... 502 4,536 490
------- ------- --------
NET CASH FLOW PROVIDED BY OPERATIONS............ 62,317 35,185 6,753
------- ------- --------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures......... (81,282) (38,450) (11,761)
Acquisition of oil and natural gas
properties............................ (224,145) (48,407) (16,763)
Net purchases of other assets............ (2,132) (1,726) (560)
Acquisition of subsidiary, net of
cash acquired......................... - 209 -
------- ------- --------
NET CASH USED FOR INVESTING ACTIVITIES......... (307,559) (88,374) (29,084)
------- ------- --------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank borrowings.......................... 239,900 47,900 19,350
Bank repayments.......................... - (47,900) (34,200)
Issuance of subordinated debt............ - - 1,772
Issuance of common stock................. 2,816 60,664 26,825
Issuance of preferred stock.............. - - 15,000
Costs of debt financing.................. (1,511) (411) (493)
Other.................................... (90) (164) (82)
------- ------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES....... 241,115 60,089 28,172
------- ------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS................................ (4,127) 6,900 5,841
Cash and cash equivalents at beginning of year.. 13,453 6,553 712
------- ------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR........ $ 9,326 $13,453 $ 6,553
======= ======= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid during the year for interest.... $ 447 $ 1,621 $ 2,127
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
30
<PAGE>
Consolidated Statement of Changes in Shareholders' Equity
<TABLE>
<CAPTION>
COMMON SHARES
(NO PAR VALUE)
Dollar Amounts in Thousands of U.S. ------------------ RETAINED
Dollars Shares Amounts EARNINGS TOTAL
--------- -------- ------- -------
<S> <C> <C> <C> <C>
BALANCE - JANUARY 1, 1995 6,304,667 $ 23,239 $ 2,723 $25,962
--------- -------- ------- -------
Issued pursuant to employee stock
option plan..................... 10,000 54 - 54
Private placement of Special Warrants
exchanged....................... 614,143 2,314 - 2,314
Private placement of common shares... 4,499,999 24,457 - 24,457
Net income........................... - - 714 714
--------- -------- ------- -------
BALANCE - DECEMBER 31, 1995 11,428,809 50,064 3,437 53,501
--------- -------- ------- -------
Issued pursuant to employee stock
option plan..................... 197,675 1,070 - 1,070
Issued pursuant to employee stock
purchase plan................... 31,311 358 - 358
Public placement of common shares.... 4,940,000 58,776 - 58,776
Conversion of preferred stock........ 2,816,372 16,281 - 16,281
Conversion of warrants............... 75,000 460 - 460
Conversion of subordinated debt...... 566,590 3,314 - 3,314
Net income........................... - - 8,744 8,744
---------- -------- ------- -------
BALANCE - DECEMBER 31, 1996 20,055,757 130,323 12,181 142,504
---------- -------- ------- -------
Issued pursuant to employee stock
option plan...................... 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
========== ======== ======= ========
</TABLE>
See Notes to Consolidated Financial Statements
31
<PAGE>
Notes to Consolidated Financial Statements
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
The Company's operating activities are related to exploration, development and
production of oil and natural gas in the United States.
On October 9, 1996 the shareholders of the Company approved an amendment to the
Articles of Continuance to consolidate the number of issued and outstanding
Common Shares on the basis of one Common Share for each two Common Shares
outstanding. All applicable shares and per share data have been adjusted for the
reverse stock split.
Principles of Consolidation
The consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles and include the accounts of
the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury
Management, Inc. and Denbury Marine L.L.C. and the Company's equity in the
operation of its 50% owned subsidiary, Denbury Energy Services ("DES"). The
Company acquired the remaining 50% of DES effective May 1, 1996 and began
consolidating all of DES as of that date. 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 the
exploration for and development of oil and natural gas reserves are capitalized
and accumulated in a single cost center representing the Company's activities
undertaken exclusively in the United States. Such costs include lease
acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and nonproductive
wells and general and administrative expenses directly related to exploration
and development activities. Proceeds received from disposals are credited
against accumulated costs except when the sale represents a significant disposal
of reserves in which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION The costs capitalized, including production
equipment, are depleted or depreciated on the unit-of-production method, based
on proved oil and natural gas reserves as determined by independent petroleum
engineers. Oil and natural gas reserves are converted to equivalent units based
upon the relative energy content which is six thousand cubic feet of natural gas
to one barrel of crude oil.
C) SITE RECLAMATION Estimated future costs of well abandonment and site
reclamation, including the removal of production facilities at the end of their
useful life, are provided for on a unit-of-production basis. Costs are based on
engineering estimates of the anticipated method and extent of site restoration,
valued at year-end prices, net of estimated salvage value, and in accordance
with the current legislation and industry practice. The annual provision for
future site reclamation costs is included in depletion and depreciation expense.
D) CEILING TEST The capitalized costs less accumulated depletion, depreciation,
related deferred taxes and site reclamation costs are limited to an amount which
is not greater than the estimated future net revenue from proved reserves using
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.
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 per common share is computed by dividing the net income attributable
to common shareholders by the weighted average number of shares of common stock
outstanding. In accordance with Canadian generally accepted accounting
principles ("GAAP"), the imputed dividend during 1996 on the Convertible First
Preferred Shares, Series A has been recorded as an
32
<PAGE>
Notes to Consolidated Financial Statements
operating expense in the accompanying financial statements and this is deducted
from net income in computing earnings per share. The conversion of the
Convertible First Preferred Shares, Series A ("Convertible Preferred") was
anti-dilutive and was not included in the calculation of earnings per share. In
computing fully diluted earnings per share, the stock options, warrants and
convertible debt instruments were dilutive for the 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. For the
year ended December 31, 1995, these instruments were either anti-dilutive or
immaterial. All of the Convertible Preferred and the convertible debt were
converted into common shares during 1996 and thus were not relevant to the
calculation of earnings per share during 1997.
Statement of Cash Flows
For purposes of the Statement of Cash Flows, cash equivalents include time
deposits, certificates of deposit and all liquid debt instruments with
maturities at the date of purchase of three months or less.
Revenue Recognition
The Company follows the "sales method" of accounting for its oil and natural gas
revenue whereby the Company recognizes sales revenue on all oil or natural gas
sold to its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A receivable or liability is recognized
only to the extent that the Company has an imbalance on a specific property
greater than the expected remaining proved reserves. As of December 31, 1997 and
1996, 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 6 to the
consolidated financial statements. Credit risk relating to these hedges is
minimal because of the credit risk standards required for counter-parties and
monthly settlements. The Company has entered into hedging contracts with only
large and financially strong companies.
The Company's financial instruments that are exposed to concentrations of credit
risk consist primarily of cash equivalents, short-term investments and trade and
accrued production receivables. The Company's cash equivalents and short-term
investments represent high-quality securities placed with various investment
grade institutions. This investment practice limits the Company's exposure to
concentrations of credit risk. The Company's trade and accrued production
receivables are dispersed among various customers and purchasers; therefore,
concentrations of credit risk are limited. Also, the Company's more significant
purchasers are large companies with excellent credit ratings. If customers are
considered a credit risk, letters of credit are the primary security obtained to
support lines of credit.
Fair Value of Financial Instruments
As of December 31, 1997 and December 31, 1996, the carrying value of the
Company's debt and other financial instruments approximates its fair market
value. The Company's bank debt is based on a floating interest rate and thus
adjusts to market as interest rates change. The Company's other financial
instruments are primarily cash, cash equivalents, short-term receivables and
payables which approximate fair value due to the nature of the instrument and
the relatively short maturities.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amount of certain assets, liabilities, revenues and expenses
as of and for the reporting period. Estimates and assumptions are also required
in the disclosure of contingent assets and liabilities as of the date of the
financial statements. Actual results may differ from such estimates.
33
<PAGE>
Notes to Consolidated Financial Statements
NOTE 2. PROPERTY AND EQUIPMENT
Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, the Company may exclude certain unevaluated costs
from the amortization base pending determination of whether proved reserves have
been discovered or impairment has occurred. A summary of the unevaluated
properties excluded from oil and natural gas properties being amortized at
December 31, 1997 and 1996 and the year in which they were incurred follows:
<TABLE>
<CAPTION>
December 31, 1997 December 31, 1996
------------------------ --------------------------
Costs Incurred During: Costs Incurred During:
---------------- -----------------
AMOUNTS IN THOUSANDS 1997 1996 Total 1996 1995 Total
------- ------- ------- ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Property acquisition cost.. $77,238 $ 286 $77,524 $ 2,614 $ 252 $ 2,866
Exploration costs......... 3,817 1,457 5,274 3,460 87 3,547
------- ------- ------- ------- ------ -------
Total................. $81,055 $ 1,743 $82,798 $ 6,074 $ 339 $ 6,413
======= ======= ======= ======= ====== =======
</TABLE>
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
Pending determination of proved reserves attributable to the above costs, the
Company cannot assess the future impact on the amortization rate.
General and administrative costs that directly relate to exploration and
development activities that were capitalized during the period totaled
$2,225,000, $1,224,000 and $630,000 for the years ended December 31, 1997, 1996
and 1995, respectively. Amortization per BOE was $6.42, $5.99 and $5.22 for the
years ended December 31, 1997, 1996 and 1995, respectively.
NOTE 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
<TABLE>
<CAPTION>
December 31,
-------------------
1997 1996
AMOUNTS IN THOUSANDS -------- --------
<S> <C> <C>
Senior bank loan...................$240,000 $ 100
Other notes payable................ 20 92
-------- --------
240,020 192
Less portion due within one year... (20) (67)
-------- --------
Total long-term debt.........$240,000 $ 125
======== ========
</TABLE>
Banks
In order to fund the Chevron Acquisition (as defined herein), the Company has
revised and restated its credit facility (the "Credit Facility") as of December
29, 1997 with NationsBank of Texas, N.A. ("NationsBank") as agent for a group of
banks and increased the size of the facility from $150 million to $300 million.
As of December 31, 1997, the borrowing base was $260 million, of which
approximately $20 million was available. The Credit Facility includes a five
year revolving credit facility of $165 million, unless renewed or extended, plus
an Acquisition Tranche of $95 million. The borrowing base is subject to review
every six months and the facility is secured by substantially all of the
Company's oil and natural gas properties, except for those acquired in the
Chevron Acquisition.
Interest is payable on the revolving credit facility at either the prime rate
or, depending on the percentage of the borrowing base that is outstanding, at
rates ranging from LIBOR plus 7/8% to LIBOR plus 13/8%; provided that interest
is payable at LIBOR plus 15/8% as long as the Acquisition Tranche is outstanding
with the rate escalating 0.25% each quarter, beginning on March 1, 1998 through
March 31, 1999, unless the Acquisition Tranche is repaid. 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, 1997, the Company had $240 million outstanding on
this line of credit and $145,000 of letters of credit outstanding. The
Acquisition Tranche was repaid during February 1998. As of February 28, 1998,
the Company had $40 million outstanding on this line of credit and $245,000 of
letters of credit outstanding.
34
<PAGE>
Notes to Consolidated Financial Statements
Subordinated Debt
On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of 6 3/4%
unsecured convertible debentures and on January 17, 1995, Denbury issued Cdn.
$2,500,000 principal amount of 9 1/2% unsecured convertible debentures. These
debentures were converted into 566,590 Common Shares during 1996.
Indebtedness Repayment Schedule
The Company's indebtedness is repayable as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1997
----------------------------------
OTHER NOTES
AMOUNTS IN THOUSANDS BANK LOAN PAYABLE TOTAL
- ------------------------ --------- ----------- --------
YEAR
<S> <C> <C> <C>
1998 ....................$ - $ 20 $ 20
1999 .................... - - -
2000 .................... - - -
2001 .................... - - -
2002 .................... 240,000 - 240,000
--------- ----------- --------
Total indebtedness $ 240,000 $ 20 $240,020
========= =========== ========
</TABLE>
NOTE 4. INCOME TAXES
The Company's income tax provision is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
------- ------ ------
<S> <C> <C> <C>
Deferred
Federal..........................$ 8,589 $5,312 $ 367
State............................ 306 - -
------- ------ ------
Total income tax provision..........$ 8,895 $5,312 $ 367
======= ====== ======
</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 1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Deferred income tax provision
calculated using the Canadian federal
and provincial statutory combined
tax rate of 44.34%................... $10,552 $ 6,233 $ 479
Increase resulting from:
Imputed preferred dividend........... - 568 -
Non-deductible Canadian expenses..... - 97 -
Decrease resulting from:
Effect of lower income tax rates on
United States income............... (1,657) (1,586) (112)
------- ------- -------
Total income tax provision $ 8,895 $ 5,312 $ 367
======= ======= =======
</TABLE>
35
<PAGE>
Notes to Consolidated Financial Statements
The Company at December 31, 1997 had net operating loss carryforwards for U.S.
federal income tax purposes of approximately $44,852,950 and approximately
$38,672,391 for alternative minimum tax purposes. The net operating losses are
scheduled to expire as follows:
<TABLE>
<CAPTION>
ALTERNATIVE
INCOME MINIMUM
AMOUNTS IN THOUSANDS TAX TAX
- ----------------------------- ------- ---------
YEAR
<S> <C> <C>
2004 ....................... $ 39 $ -
2005 ....................... 11 -
2006 ....................... 644 500
2007 ....................... 714 99
2008 ....................... 5,016 4,889
2009 ....................... 3,377 2,868
2010 ....................... 3,467 3,420
2011 ....................... 5,061 710
2012 ....................... 26,524 26,186
</TABLE>
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1997 and 1996 balance sheet dates.
At December 31, 1997 and 1996, all deferred tax assets and liabilities were
computed based on Canadian GAAP amounts and were noncurrent as follows:
<TABLE>
<CAPTION>
December 31,
------------------
AMOUNTS IN THOUSANDS 1997 1996
-------- --------
<S> <C> <C>
Deferred tax assets:
Loss carryforwards............ $(15,699) $ (4,902)
Deferred tax liabilities:
Exploration and intangible
development costs.......... 31,319 11,645
-------- --------
Net deferred tax liability....... $ 15,620 $ 6,743
======== ========
</TABLE>
NOTE 5. SHAREHOLDERS' EQUITY
Authorized
The Company is authorized to issue an unlimited number of Common Shares with no
par value, First Preferred Shares and Second Preferred Shares. The preferred
shares may be issued in one or more series with rights and conditions as
determined by the Directors.
Common Stock
Each Common Share entitles the holder thereof to one vote on all matters on
which holders are permitted to vote. The Texas Pacific Group ("TPG") was granted
a right of first refusal in the private placement (see below), to maintain
proportionate ownership. No stockholder has any right to convert common stock
into other securities. The holders of shares of common stock are entitled to
dividends when and if declared by the Board of Directors from funds legally
available therefore and, upon liquidation, to a pro rata share in any
distribution to stockholders, subject to prior rights of the holders of the
preferred stock. The Company is restricted from declaring or paying any cash
dividend on the Common Stock by its bank loan agreement.
1996 Capital Adjustments
During 1996, the Company issued 250,000 Common Shares for the conversion of the
6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for the
exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10, 1996,
the Company effected a one-for-two reverse split of its outstanding common
Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2%
Convertible Debentures ("Debentures") were converted by their holders in
accordance with their terms into 308,642 Common Shares. The holders of the
Debentures also received an additional 7,948 Common Shares in lieu of interest
which would have been due the holders absent an early conversion of the
Debentures. At a special meeting held on October 9, 1996, the shareholders of
the Company approved an amendment to the terms of the Convertible Preferred to
allow the Company to require the conversion of the Convertible Preferred at any
time, provided that the conversion rate in effect as of January 1, 1999 would
apply to any required conversion prior to that date. The Company converted all
of the 1,500,000 shares of Convertible Preferred
36
<PAGE>
Notes to Consolidated Financial Statements
on October 30, 1996 into 2,816,372 Common Shares. The Company also issued an
aggregate of 4,940,000 Common Shares on October 30, 1996 and November 1, 1996 at
a net price of $12.035 per share as part of a public offering for net proceeds
to the Company of approximately $58.8 million (the "1996 Public Offering"). TPG
purchased 800,000 of these shares at $12.035 per share.
1995 Private Placement of Securities
In December 1995, the Company closed a $40 million private placement of
securities with partnerships that are affiliated with the Texas Pacific Group
("TPG Placement"). The TPG Placement was comprised of: (i) 4.166 million common
shares issued at $5.85 per share, (ii) 625,000 warrants at a price of $1.00 per
warrant entitling the holder to purchase 625,000 common shares at $7.40 per
share through December 21, 1999 and (iii) 1.5 million shares of $10 stated value
Convertible Preferred. The Convertible Preferred shares were initially
convertible at $7.40 of stated value per common share with such conversion rate
declining 2.5% per quarter. The shares also had a mandatory redemption at a
63.86% premium at December 21, 2000. The Convertible Preferred were converted
into 2,816,372 Common Shares on October 30, 1996. During the period that the
Convertible Preferred were outstanding, the Company made a charge to net income
to accrue the increase during the period in the mandatory redemption premium.
The $7.40 warrants issued in the TPG Placement were converted into 625,000
Common Shares on January 20, 1998.
As part of the TPG Placement, TPG was granted certain "piggyback" registration
rights which allow TPG to include all or part of the Common Shares acquired by
TPG in any registration statement of the Company during the first two years.
After the initial two years and until December 21, 2000, TPG may request and
receive one demand registration statement to register the Common Shares acquired
by TPG. TPG waived their "piggyback" registration rights for the 1996 Public
Offering.
The TPG agreement provides that TPG shall have the right, but not the
obligation, to maintain its pro rata ownership interest (after the assumed
exercise of their warrants and Convertible Preferred) in the equity securities
of the Company, in the event that the Company issues any additional equity
securities or securities convertible into Common Shares of the Company, by
purchasing additional shares of the Company on the same terms and conditions.
However, this right expires should TPG's share holdings represent less than 20%
of the outstanding Common Shares. TPG waived its right to maintain its pro rata
ownership with regard to the 1996 Public Offering.
As part of the TPG Placement, Tortuga Investment Corp. was paid a financial
advisor fee of 333,333 Common Shares of the Company. The sole shareholder of
Tortuga Investment Corp. was appointed to the Board of Directors of the Company
and elected Chairman upon the closing of the TPG Placement.
Warrants
At December 31, 1997, 75,000 warrants were outstanding at an exercise price of
Cdn. $8.40 expiring on May 5, 2000 and TPG held 625,000 warrants at an exercise
price of U.S. $7.40 expiring on December 21, 1999. Each warrant entitles the
holder thereof to purchase one Common Share at any time prior to the expiration
date. The $7.40 warrants held by TPG were converted into 625,000 Common Shares
on January 20, 1998.
Special Warrant Issues
On April 25, 1995, the Company issued 614,143 Special Warrants at a price of
$4.70 (Cdn. $6.50) per Special Warrant for gross proceeds of $2,750,000 (29,036
Common Share Purchase Warrants were issued to Southcoast Capital Corporation, as
placement agent, in partial payment of their fee). Costs of the issue were
$436,000, resulting in net proceeds to the Company of approximately $2,314,000.
Each Special Warrant was exchanged, at no additional cost, for one Common Share
on August 11, 1995.
Stock Option Plan
The Company maintains a Stock Option Plan which authorizes the grant of options
up to 2,000,000 Common Shares. Under the plan, incentive and non-qualified
options may be issued to officers, key employees and consultants. These options
are granted at market value as defined in the plan. The plan is administered by
the Stock Option Committee of the Board.
37
<PAGE>
Notes to Consolidated Financial Statements
Following is a summary of stock option activity during the years ended December
31, 1997, 1996 and 1995:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1997 1996 1995
--------------------- ------------------ ------------------
Weighted Weighted Weighted
Average Average Average
Number Price Number Price Number Price
--------- ---------- --------- --------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year............... 1,053,000 $ 7.63 731.925 $ 6.11 557,312 $ 6.30
Granted.................... 797,162 14.13 525,500 8.96 274,500 5.89
Terminated................. (23,250) 11.51 (6,750) 6.28 (89,887) 7.79
Exercised.................. (280,656) 6.95 (197,675) 5.42 (10,000) 5.42
Expired.................... - - - - - -
--------- ---------- --------- --------- ------- ---------
Outstanding at end of
period.................. 1,546,256 $ 11.06 1,053,000 $ 7.63 731,926 $ 6.11
========= ========== ========= ========= ======= =========
Options exercisable at end
of year................. 391,872 $ 7.57 532,375 $ 6.82 539,675 $ 6.19
========= ========== ========= ========== ======= =========
</TABLE>
<TABLE>
<CAPTION>
Weighted
Weighted Average Weighted
Options Outstanding as Options Average Remaining Exercisable Average
of December 31, 1997: Outstanding Price Life (yrs.) Options Price
- ---------------------- --------- --------- --------------- ---------- ---------
Exercise price of:
<S> <C> <C> <C> <C> <C>
$5.55 to $7.00 384,750 $ 6.42 7.02 183,375 $ 5.88
$7.01 to $13.37 382,419 9.67 8.22 205,504 9.19
$13.38 to $22.24 779,087 14.49 9.23 2,993 13.88
</TABLE>
In 1995, the United States Financial Accounting Standards Board issued Statement
of Financial Accounting 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 and
net income per common share would have been reduced to the pro forma amounts
indicated below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
NET INCOME:
As reported (thousands)..........................$14,903 $8,744 $ 714
Pro forma (thousands)............................ 14,130 8,215 503
NET INCOME PER COMMON SHARE:
As reported:
Basic.........................................$ 0.74 $ 0.67 $ 0.10
Fully diluted................................. 0.70 0.62 0.10
Pro forma:
Basic.........................................$ 0.70 $ 0.63 $ 0.07
Fully diluted................................. 0.66 0.59 0.07
Stock options issued during period (thousands)...... 797 526 275
Weighted average exercise price.....................$ 14.13 $ 8.96 $ 5.90
Average per option compensation value of options
granted (a)...................................... 4.02 2.95 2.34
Compensation cost (thousands)....................... 1,227 801 320
<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 29% to 67%; expected dividend yield -
0%; expected option term - 3 years; and risk-free rate of return as of the
date of grant which ranged from 5.3% to 7.8%, based on the yield of
five-year U.S. treasury securities.
</FN>
</TABLE>
38
<PAGE>
Notes to Consolidated Financial Statements
Stock Purchase Plan
In February 1996, the Company also implemented a Stock Purchase Plan which
authorizes the sale of up to 250,000 Common Shares to all full-time employees.
Under the plan, the employees may contribute up to 10% of their base salary and
the Company matches 75% of the employee contribution. The combined funds are
used to purchase previously unissued Common Shares of the Company based on its
current market value at the end of the each quarter. The Company recognizes
compensation expense for the 75% Company matching portion, which totaled
$383,000 and $147,000 for the years ended December 31, 1997 and 1996,
respectively. This plan is administered by the Stock Purchase Plan Committee of
the Board.
NOTE 6. PRODUCT PRICE HEDGING CONTRACTS
In 1995, the Company entered into two swap contracts for oil. The first oil
contract was for 500 Bbls/d of oil at a price of $17.79 per barrel of oil
commencing on February 1, 1995 and ending on January 31, 1996. The second oil
contract was also for 500 Bbls/d of oil at a price of $18.83, for the period
commencing on April 12, 1995 and ending on December 30, 1995. These contracts
covered 43% of the Company's net revenue interest production for 1995 and
decreased oil and natural gas revenues by approximately $47,000 during such
period.
The Company does not have any hedge contracts in place as of December 31, 1997.
NOTE 7. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1997, long-term commitments for these
items require the following future minimum rental payments:
<TABLE>
<CAPTION>
December 31,
AMOUNTS IN THOUSANDS 1997
---------
<S> <C>
1998 .................$ 473
1999 ................. 1,076
2000 ................. 1,074
2001 ................. 1,069
2002 ................. 1,055
---------
Total lease commitments $ 4,747
=========
</TABLE>
The Company is subject to various possible contingencies which arise primarily
from interpretation of federal and state laws and regulations affecting the oil
and natural gas industry. Such contingencies include differing interpretations
as to the prices at which oil and natural gas sales may be made, the prices at
which royalty owners may be paid for production from their leases, 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.
From time to time, the Company is a party to legal proceedings in the ordinary
course of its business, including actions for personal injury and property
damage occurring as a result of the operation of wells, and claims for
environmental damage. In June of 1997, a well blow-out occurred at the Lake
Chicot Field, for which the Company is operator, in St. Martin Parish, Louisiana
in which four individuals that were employees of other third party entities were
killed, none of who 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.
39
<PAGE>
Notes to Consolidated Financial Statements
NOTE 8. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN CANADA
AND THE UNITED STATES
The consolidated financial statements have been prepared in accordance with GAAP
in Canada. The primary differences between Canadian and U.S. GAAP affecting the
Company's consolidated financial statements are as discussed below.
Loss on Extinguishment of Debt and Imputed Preferred Dividends
The most significant GAAP difference relates to the presentation of the early
extinguishment of debt and the imputed dividend on the Convertible Preferred.
During 1996, the Company expensed $1,281,000 relating to the imputed preferred
dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would
be deducted from net income to compute the net income attributable to the common
shareholders. The Company also expensed its debt issue cost relating to the
Company's prior bank credit agreements totaling $440,000 and $200,000 for 1996
and 1995, respectively. Under Canadian GAAP this is an operating expense, while
under U.S. GAAP a loss on early extinguishment of debt is an extraordinary item.
While net income per common share and all balance sheet accounts are not
affected by these differences in GAAP, the net income for 1996 under U.S. GAAP
would be $10,025,000, while under Canadian GAAP the amount reported was
$8,744,000.
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 would be $0.70, $0.63 and
$0.10 for the years ended December 31, 1997, 1996 and 1995 as compared to the
$0.70, $0.62 and $0.10 reported under Canadian GAAP.
Recently Issued Accounting Standards
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants has adopted Statement of Position 96-1,
"Environmental Remediation Liabilities," which provides guidance on the
recognition, measurement, display and disclosure of environmental remediation
liabilities. The Statement is effective for the Company's 1997 fiscal year but
did not have any material effect on the financial position or results of
operations of the Company.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income" and
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information." SFAS No. 130 establishes standards for reporting and display of
comprehensive income in the financial statements. Comprehensive income is the
total of net income and all other non-owner changes in equity. SFAS No. 131
requires that companies disclose segment data based on how management makes
decisions about allocating resources to segments and measuring their
performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of these
standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.
NOTE 9. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon operations. For the year
ended December 31, 1997, the Company sold 10% or more of its net production of
oil and natural gas to the following purchasers: Hunt Refining (42%), Natural
Gas Clearinghouse (22%) and Columbia Energy Services (10%).
Costs Incurred
The following table summarizes costs incurred in oil and natural gas property
acquisition, exploration and development activities. Property acquisition costs
are those costs incurred to purchase, lease, or otherwise acquire property,
including both undeveloped leasehold and the purchase of revenues in place.
Exploration costs include costs of identifying areas that may warrant
examination and in examining specific areas that are considered to have
prospects containing oil and natural gas reserves, including costs of drilling
exploratory wells, geological and geophysical costs and carrying costs on
undeveloped properties. Development costs are incurred to obtain access to
proved reserves, including the cost of drilling development wells, and to
provide facilities for extracting, treating, gathering and storing the oil and
natural gas.
40
<PAGE>
Notes to Consolidated Financial Statements
Costs incurred in oil and natural gas activities for the years ended December
31, 1997, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
-------- -------- -------
<S> <C> <C> <C>
Property acquisition..... $226,809 $ 48,856 $17,198
Exploration.............. 20,734 4,592 1,687
Development.............. 57,884 33,409 9,639
-------- ------- -------
Total costs incurred $305,427 $ 86,857 $28,524
======== ======== =======
</TABLE>
Property Acquisitions
On December 30, 1997, Denbury acquired producing oil and natural gas properties
in Mississippi for approximately $202 million (the "Chevron Acquisition"). The
acquisition included 122 wells, of which 96 wells will be Company operated. The
Company funded this acquisition with bank financing from a revised and restated
credit facility.
This acquisition was accounted for under purchase accounting and the results of
operations will be consolidated effective December 31, 1997. Pro forma results
of operations of the Company as if the Chevron Acquisition had occurred at the
beginning of each respective period are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
Amounts in thousands except 1997 1996
per share amounts(Unaudited) --------- --------
<S> <C> <C>
Revenues.........................$ 104,695 $ 77,311
Net income....................... 9,533 4,909
Net income per common share:
Basic......................... 0.47 0.37
Fully diluted................. 0.46 0.37
</TABLE>
In computing the pro forma results, depreciation, depletion and amortization
expense was computed using the units of production method, and an adjustment was
made to interest expense reflecting the bank debt that was required to fund the
acquisitions. The pro forma results reflect an increase of $687,000 in general
and administrative expense for additional personnel and associated costs
relating to the acquired properties, net of anticipated allocations to
operations and capitalization of exploration costs.
The following represents the revenues and direct operating expenses attributable
to the net interest acquired in the Chevron Acquisition by the Company and are
presented on the full cost accrual basis of accounting. Depreciation, depletion
and amortization, allocated general and administrative expenses, interest
expense and income, and income taxes have been excluded because the property
interests acquired represent only a portion of a business and these expenses are
not necessarily indicative of the expenses to be incurred by the Company.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996 1995
-------- ------- -------
Amount in Thousands (Unaudited)
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related
product sales.....................$ 18,239 $23,662 $17,460
Direct operating expenses:
Lease operating expense............. 6,932 6,650 5,825
-------- ------- -------
Excess of revenues over direct operating
expenses..........................$ 11,307 $17,012 $11,635
======== ======= =======
</TABLE>
41
<PAGE>
Notes to Consolidated Financial Statements
10. 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, 1997 and 1996 and for the
years ended December 31, 1997, 1996 and 1995 is as follows:
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, 1997
--------------------------------------------------------
Denbury Denbury Denbury
Management Resources Resources
Amounts in Thousands Inc. Inc. 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>
<TABLE>
<CAPTION>
December 31, 1996
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Amounts in Thousands Inc. Holdings Inc. Inc.
(Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets........................................... $ 28,722 $ -- $ 280 $ -- $ 29,002
Property and equipment (using full cost accounting)...... 134,996 -- -- -- 134,996
Investment in subsidiaries (equity method)............... -- 142,321 140,763 (283,084) --
Other assets ............................................ 2,505 -- 1,560 (1,558) 2,507
--------- --------- ---------- ------------ ------------
Total assets.......................................... $ 166,223 $ 142,321 $ 142,603 $ (284,642) $ 166,505
========= ========= ========== ============ ============
LIABILITIES AND SHAREHOLDERS'EQUITY
Current liabilities...................................... $ 16,421 $ -- $ 99 $ -- $ 16,520
Long-term liabilities ................................... 7,481 1,558 -- (1,558) 7,481
Shareholders' equity .................................... 142,321 140,763 142,504 (283,084) 142,504
--------- --------- ---------- ------------ ------------
Total liabilities and shareholders' equity............ $ 166,223 $ 142,321 $ 142,603 $ (284,642) $ 166,505
========= ========= ========== ============ ============
</TABLE>
42
<PAGE>
Notes to Consolidated Financial Statements
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(in thousands of U.S. dollars)
<TABLE>
<CAPTION>
Year Ended December 31, 1997
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Inc. Holdings Inc. Inc.
Amounts in Thousands (Issuer) 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 the following: 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
Provision for income taxes..... (8,895) -- -- -- (8,895)
--------- --------- ---------- ------------ ------------
Net income..................... $ 14,898 $ 14,898 $ 14,903 $ (29,796) $ 14,903
========= ========= ========== ============ ============
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1996
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Inc. Holdings Inc. Inc.
Amounts in Thousands (Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues....................... $ 53,631 $ -- $ 179 $ (161) $ 53,649
Expenses....................... 38,008 -- 1,746 (161) 39,593
--------- --------- ---------- ------------ ------------
Income (loss) before the
following: 15,623 -- (1,567) -- 14,056
Equity in net earnings of
subsidiaries................ -- 10,311 10,311 (20,622) --
--------- --------- ---------- ------------ ------------
Income before income taxes..... 15,623 10,311 8,744 (20,622) 14,056
Provision for income taxes..... (5,312) -- -- -- (5,312)
--------- --------- ---------- ------------ ------------
Net income..................... $ 10,311 $ 10,311 $ 8,744 $ (20,622) $ 8,744
========= ========= ========== ============ ============
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1995
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Inc. Holdings Inc. Inc.
Amounts in Thousands (Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues....................... $ 20,107 $ -- $ 460 $ (458) $ 20,109
Expenses....................... 19,026 -- 460 (458) 19,028
--------- --------- ---------- ------------ ------------
Income before the following: 1,081 -- -- -- 1,081
Equity in net earnings of
subsidiaries................ -- 714 714 (1,428) --
--------- --------- ---------- ------------ ------------
Income before income taxes..... 1,081 714 714 (1,428) 1,081
Provision for income taxes..... (367) -- -- -- (367)
--------- --------- ---------- ------------ ------------
Net income..................... $ 714 $ 714 $ 714 $ (1,428) $ 714
========= ========= ========== ============ ============
</TABLE>
43
<PAGE>
Notes to Consolidated Financial Statements
NOTE 11. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31, 1997, 1996
and 1995 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. 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.
Estimated Quantities of Reserves
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1997 1996 1995
--------------- -------------- ---------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------- ------ ------ ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
BALANCE BEGINNING OF YEAR..... 15,052 74,102 6,292 48,116 4,230 42,047
Revisions of previous
estimates................ 3,398 1,098 (490) 3,737 830 (1,620)
Revisions due to price
changes.................. (1,525) (317) 1,053 402 -- --
Extensions, discoveries
and other additions...... 6,373 11,205 3,492 5,480 732 --
Production................. (2,884)(13,257) (1,500) (8,933) (728) (4,844)
Acquisition of minerals in
place.................... 31,604 4,360 6,205 25,300 1,228 12,533
------- ------ ------ ------ ------- ------
BALANCE AT END OF YEAR........ 52,018 77,191 15,052 74,102 6,292 48,116
======= ====== ====== ====== ======= ======
PROVED DEVELOPED RESERVES:
Balance at beginning of
year..................... 13,371 58,634 5,290 34,894 3,755 35,578
Balance at end of year..... 31,355 69,805 13,371 58,634 5,290 34,894
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does
not purport to present the fair market value of the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates. It should be noted that
estimates of reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. Future cash inflows
were reduced by estimated future production and development costs based on
year-end costs to determine pre-tax cash inflows. Future income taxes were
computed by applying the statutory tax rate to the excess of pre-tax cash
inflows over the Company's tax basis in the associated proved oil and natural
gas properties. Tax credits and net operating loss 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.
44
<PAGE>
Notes to Consolidated Financial Statements
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows.............................. $957,718 $627,476 $214,932
Future production costs.......................... (285,968) (134,986) (56,323)
Future development costs......................... (68,287) (28,722) (16,154)
-------- -------- --------
Future net cash flows before taxes .............. 603,463 463,768 142,455
10% annual discount for estimated timing of
cash flows..................................... (242,134) (147,670) (45,490)
-------- -------- --------
Discounted future net cash flows before taxes.... 361,329 316,098 96,965
Discounted future income taxes................... (26,021) (74,226) (15,801)
-------- -------- --------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS....................................... $335,308 $241,872 $ 81,164
======== ======== ========
</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 1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
BEGINNING OF YEAR................................ $241,872 $ 81,164 $ 46,928
Sales of oil and natural gas produced, net of
production costs.............................. (63,115) (39,385) (13,243)
Net changes in sales prices...................... (132,905) 116,587 23,037
Extensions and discoveries, less applicable
future development and production costs...... 75,632 34,113 1,926
Previously estimated development costs incurred.. 10,088 5,278 2,193
Revisions of previous estimates, including
revised estimates of development costs,
reserves and rates of production.............. 264 7,747 3,958
Accretion of discount............................ 24,187 8,116 4,693
Purchase of minerals in place.................... 131,080 86,677 21,710
Net change in income taxes....................... 48,205 (58,425) (10,038)
-------- -------- --------
END OF YEAR...................................... $335,308 $241,872 $ 81,164
======== ======== ========
</TABLE>
NOTE 12. SUBSEQUENT EVENTS
On February 26, 1998, the Company closed on a public offering of 5,240,780
Common Shares (which included the underwriter's over-allotment option of 683,580
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, affiliates of 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.
Concurrently with the Equity Offering and TPG Purchase, Denbury Management Inc.,
a wholly-owned subsidiary of the Company, issued $125 million in aggregate
principal amount of 9% Senior Subordinated Notes Due 2008 (the "Debt Offering"
and the "Notes"). These Notes contain certain debt convents, 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 was approximately $121.8 million,
before offering expenses.
45
<PAGE>
Notes to Consolidated Financial Statements
The total net proceeds from the debt and equity offerings were approximately
$209.8 million after deducting the estimated offering expenses of $600,000. The
Company used these proceeds to reduce outstanding borrowings under the Company's
bank credit facility, the majority of which had been borrowed to fund the $202
million Chevron Acquisition. On a pro forma basis using U.S. GAAP and assuming
that the Equity Offering, TPG Purchase and the Debt Offering had closed as of
January 1, 1997 and the interest expense for 1997 relating to the bank debt was
reversed, the basic and fully diluted earnings per share would be $0.32 per
share. No interest income as assumed in the pro forma calculation even though
the proceeds from the offerings exceeded the bank debt retired for most of the
year.
The following table sets forth the actual capitalization of the Company as of
December 31, 1997 and the pro forma capitalization as adjusted for the Equity
Offering, TPG Purchase and Debt Offering:
<TABLE>
<CAPTION>
December 31, 1997
---------------------
Historical Pro forma
--------- ---------
(Unaudited)
<S> <C> <C>
Short-term debt:
Other $ 20 $ 20
--------- ---------
Long-term debt:
Credit Facility 240,000 30,200
9% Senior Subordinated Notes due 2008 - 125,000
--------- ---------
Total long-term debt 240,000 155,200
--------- ---------
Shareholders equity:
Common shares 133,139 221,139
Retained earnings 27,084 27,084
--------- ---------
Total shareholders equity 160,223 248,223
--------- ---------
Total capitalization $ 400,243 $ 403,443
========= =========
</TABLE>
UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 1997 and 1996.
<TABLE>
<CAPTION>
IN THOUSANDS EXCEPT PER SHARE AMOUNTS
MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
- --------------------------------- ----------- ---------- ---------- ------------
<S> <C> <C> <C> <C>
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
- --------------------------------- ----------------------------------------------
1996
Revenues $ 9,092 $ 11,682 $ 14,359 $ 18,516
Expenses 6,767 9,608 11,486 11,732
Net income 1,380 1,215 1,745 4,404
Net income per share: (a)
Basic 0.12 0.11 0.14 0.25
Fully diluted 0.11 0.11 0.13 0.23
Cash flow from operations (b) 6,065 7,238 8,464 12,373
<FN>
(a) Due to the significant variances between quarters in net income and average
shares outstanding, the combined quarterly income per share does not equal
the reported earnings per share for 1996.
(b) Exclusive of the net change in non-cash working capital balances.
</FN>
</TABLE>
46
<PAGE>
Notes to Consolidated Financial Statements
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, 1998, to the best of the Company's knowledge, the Common
Shares were held of record by approximately 1,200 holders, of which
approximately 150 were U.S. residents holding approximately 70% of the
outstanding Common Shares of the Company.
No Common Share dividends have been paid or are anticipated to be paid. (See
also Note 5 to the Consolidated Financial Statements).
<TABLE>
<CAPTION>
NYSE/NASDAQ (U.S.$) TSE (CDN $)
HIGH LOW HIGH LOW
- -------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------
1996
First quarter 7.88 6.25 10.80 8.30
Second quarter 10.75 8.50 14.50 12.00
Third quarter 13.50 10.00 18.10 12.70
Fourth quarter 15.25 12.50 20.95 17.00
- -------------------------------------------------------------------------
1996 annual 15.25 6.25 20.95 8.30
- -------------------------------------------------------------------------
</TABLE>
47
EXHIBIT 21
DENBURY RESOURCES INC.
LIST OF SUBSIDIARIES
JURISDICTION OF
NAME OF SUBSIDIARY INCORPORATION STATUS
- ----------------------- ------------------- -----------------------------
Denbury Management, Inc. State of Texas Wholly owned subsidiary of
Denbury Resources Inc. -
operating company
Denbury Marine, L.L.C. State of Louisiana Wholly owned subsidiary of
Denbury Management, Inc. -
marine company
Denbury Energy State of Texas Wholly owned subsidiary of
Services, Inc. Denbury Management, Inc. -
marketing company
Tallahatchie State of Texas Wholly owned subsidiary of
Resources, Inc. Denbury Management, Inc. -
dormant
1
EXHIBIT 23
DENBURY RESOURCES INC.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in the Registration statement of
Denbury Resources Inc. on Forms S-8 (Registration No.-333-1006 and 333-27995) of
our report dated February 27, 1998, 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, 1997.
Deloitte & Touche
Chartered Accountants
Calgary, Alberta
March 16, 1998
1
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE DENBURY
RESOURCES INC. DECEMBER 31, 1997 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 1
<CASH> 9,326
<SECURITIES> 0
<RECEIVABLES> 24,054
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 33,380
<PP&E> 471,564
<DEPRECIATION> (62,732)
<TOTAL-ASSETS> 447,548
<CURRENT-LIABILITIES> 30,688
<BONDS> 0
0
0
<COMMON> 133,139
<OTHER-SE> 27,084
<TOTAL-LIABILITY-AND-EQUITY> 447,548
<SALES> 85,333
<TOTAL-REVENUES> 86,456
<CGS> 0
<TOTAL-COSTS> 61,547
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,111
<INCOME-PRETAX> 23,798
<INCOME-TAX> 8,895
<INCOME-CONTINUING> 14,903
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 14,903
<EPS-PRIMARY> .74
<EPS-DILUTED> .70
</TABLE>
