UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
1999 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, 1999
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.
(Exact name of Registrant as specified in its charter)
Delaware 75-2815171
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
5100 Tennyson Parkway,
Suite 3000,Plano, TX 75024
(Address of principal executive offices) (Zip Code)
Registrant's telephone number,
including area code: (972) 673-2000
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class Name of Each Exchange on Which Registered
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Common Stock $.001 Par Value New York Stock Exchange
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Securities registered pursuant
to Section 12(g) of the Act: 9% Senior Subordinated Notes due 2008
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]
As of February 29, 2000, the aggregate market value of the
registrant's Common Stock held by non-affiliates was approximately
$50,000,000.
The number of shares outstanding of the registrant's Common Stock
as of February 29, 2000, was 45,718,486.
DOCUMENTS INCORPORATED BY REFERENCE
Document Incorporated as to
1. Notice and Proxy Statement for 1. Part III, Items 10, 11,
the Annual Meeting of Stockholders 12, and 13
to be held May 24, 2000
2. Annual Report to Shareholders for 2. Part 1, Item 1 and
the year ended December 31, 1999. Part II, Items 5, 6, 7, 8
<PAGE>
Denbury Resources Inc.
1999 Annual Report on Form 10-K
Table of Contents
Item Page
---- ----
PART I
1. Business ...................................... 3
2. Properties .................................... 11
3. Legal Proceedings ............................. 11
4. Submission of Matters to a Vote of
Security Holders ............................. 11
PART II
5. Market for Common Stock and Related Matters.... 12
6. Selected Financial Data ....................... 12
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations. 12
7A. Quantitative and Qualitative Disclosures
About Market Risk ............................ 12
8. Financial statements and Supplementary Data.... 12
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........ 12
PART III
10. Directors and Executive Officers of the Company 13
11. Executive Compensation ........................ 13
12. Security Ownership of Certain Beneficial Owners
and Management ............................... 13
13. Certain Relationships and Related Transactions. 13
PART IV
14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K .......................... 14
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<PAGE>
PART I
Item 1. Business
----------------
The Company
Denbury Resources Inc. ("Denbury" or the "Company") is a Delaware
corporation, organized under Delaware General Corporation Law, engaged
in the acquisition, development, operation and exploration of oil and
gas properties in the Gulf Coast region of the United States, primarily
in Louisiana and Mississippi. Denbury's corporate headquarters is
located at 5100 Tennyson Parkway, Suite 3000, Plano, Texas 75024, and
its phone number is 972-673-2000. At December 31, 1999, the Company
had 218 employees, 132 of which were employed in field operations.
Incorporation and Organization
Denbury was originally incorporated in Canada in 1951. In 1992,
the Company acquired all of the shares of a United States operating
company, Denbury Management, Inc. ("DMI"), and subsequent to the merger
the Company sold all of its Canadian assets. Since that time, all of
the Company's operations have been in the United States.
In April 1999, the stockholders approved a move of the Company's
corporate domicile from Canada to the United States as a Delaware
Corporation. Along with the move, the Company's wholly-owned
subsidiary, DMI, was merged into the new Delaware parent company,
Denbury Resources Inc. This move of domicile did not have any effect
on the operations and assets of the Company, and as part of the move
and merger, Denbury Resources Inc. expressly assumed any and all
liabilities of DMI, including the obligation for the 9% Senior
Subordinated Notes due 2008 and the outstanding bank credit facility.
The Company has two active wholly owned subsidiaries, Denbury
Marine, L.L.C. and Denbury Energy Services, Inc.
Recent Events
As a result of depressed oil prices in 1998 which continued into
the first part of 1999, the Company's cash flow and results of
operations were adversely affected during 1998 and the first quarter of
1999. This reduction in cash flow also contributed to an increase in
the Company's debt levels, which as a multiple of cash flow were at
historic highs as of December 31, 1998.
1999 Sale of Stock to the Texas Pacific Group
As a result of the reduced cash flows and increased debt levels,
the Company sought additional capital and in December 1998 entered into
an agreement to sell $100 million of common stock to its largest
shareholder, the Texas Pacific Group ("TPG"). In April 1999, the
stockholders approved the sale of 18,552,876 shares of common stock for
$100 million or $5.39 per share. As a result of this transaction,
TPG's ownership of the Company's outstanding common stock increased
from approximately 32% to approximately 60%. The net proceeds from
this sale of common stock of approximately $98.5 million were used to
pay down the Company's revolving credit facility.
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<PAGE>
During 1999, the Company made significant strides in rebuilding its
balance sheet and improving its financial condition. Oil prices
increased sharply during 1999 from a NYMEX average of approximately
$13.00 per Bbl during the first quarter to approximately $24.50 per Bbl
during the fourth. The Company's production also increased throughout
1999 from a first quarter average of 15,417 barrels of oil equivalent
produced per day ("BOE/d") to a fourth quarter average of 18,491 BOE/d,
an increase of 20%. This was accomplished through a combination of
both acquisitions and an increase in the Company's base production.
February 1999 Amendment to Bank Credit Facility
On February 19, 1999, the Company amended its credit facility with
Bank of America, as agent for a group of eight other banks. Under this
amendment, the borrowing base was set at $110 million, of which $60
million was classified as within their normal credit guidelines. The
credit facility's other restrictions continued, such as a prohibition
on the payment of dividends and a prohibition on most debt, liens and
corporate guarantees. This amendment (i) provided relief on certain
debt covenants, (ii) fully secured the facility with the Company's
assets, (iii) added restrictions to the uses of borrowed funds, and
(iv) increased the interest rate (for further discussion see
"Management's Discussion and Analysis of Financial Condition and
Results of Operations").
After the repayment of the credit facility in April 1999 with the
proceeds from the TPG stock sale, $9.6 million remained outstanding on
the facility, leaving a total borrowing capacity at that time of
approximately $100 million. Since April, the Company has borrowed
$17.9 million on this facility for two acquisitions, resulting in $27.5
million of outstanding bank debt as of December 31, 1999. At the
October 1, 1999 re-determination of the borrowing base, the conforming
borrowing base of $60 million and the total borrowing base of $110
million were re-affirmed, leaving the Company with a total borrowing
capacity of $82.5 million as of December 31, 1999. The next scheduled
borrowing base re-determination will be as of April 1, 2000.
Business Strategy
Information as to the Company's business strategy is set forth
under "Business Strategy," appearing on page 11 of the Company's annual
report to shareholders for the year ended December 31, 1999 ("Annual
Report"). Such information is incorporated herein by reference.
Acquisitions of Oil and Gas Properties
Information as to recent acquisitions by the Company is set forth
under "Acquisitions," appearing on page 8 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 significant operating areas and the primary properties
within those two areas is set forth under "Selected Operating Data,"
appearing on pages 6 and 7 of the Annual Report, and "Operations,"
appearing on pages 12 through 16 and page 19 of the Annual Report.
Such information is incorporated herein by reference.
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<PAGE>
Oil and Gas Acreage
The following table sets forth Denbury's acreage position at
December 31, 1999:
Developed Undeveloped
----------------- -----------------
Gross Net Gross Net
------ ------ ------ ------
Louisiana...... 19,727 12,569 18,026 7,170
Mississippi.... 34,221 27,362 41,227 23,750
------ ------ ------ ------
Total....... 53,948 39,931 59,253 30,920
====== ====== ====== ======
Productive Wells
This table sets forth both the gross and net productive wells of
the Company at December 31, 1999:
Producing Oil Producing Gas
Wells Wells Total
------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Louisiana...... 9 3.1 38 25.5 47 28.6
Mississippi.... 327 292.5 21 14.0 348 306.5
----- ----- ----- ----- ----- -----
Total...... 336 295.6 59 39.5 395 335.1
===== ===== ===== ===== ===== =====
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,
1999.
Year Ended December 31,
-----------------------------------------
1999 1998 1997
------------ ------------ ------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Exploratory Wells: (1)
Productive (2) ..... 3 1.0 - - 2 0.7
Nonproductive (3) .. 1 1.0 1 0.4 7 2.3
Development Wells: (1)
Productive (2) ..... 12 11.9 33 26.7 33 22.5
Nonproductive (3)(4) - - 1 0.8 2 0.8
----- ----- ----- ----- ----- -----
Total ............. 16 13.9 35 27.9 44 26.3
===== ===== ===== ===== ===== =====
(1) An exploratory well is a well drilled either in search of a new,
as-yet undiscovered oil or gas reservoir or to greatly extend the
known limits of a previously discovered reservoir. A developmental
well is a well drilled within the presently proved productive area
of an oil or gas reservoir, as indicated by reasonable
interpretation of available data, with the objective of completing
in that reservoir.
(2) A productive well is an exploratory or development well found to be
capable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas well.
(3) A nonproductive well is an exploratory or development well that is
not a producing well.
(4) During 1999, an additional four wells were drilled for water
injection purposes
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<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 natural 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,
1999. "Net" production is production that is owned by the Company and
produced for its interest after deducting royalties and other similar
interests.
Year Ended December 31,
-----------------------------------
1999 1998 1997
------ ------ ------
Net production volume
Crude oil - (MBbls)....... 4,413 4,965 2,884
Natural gas - (MMcf)...... 10,201 13,361 13,257
Equivalent - MBOE (1)..... 6,113 7,192 5,094
Average sales price
Crude oil - ($/Bbl)....... $13.08 $10.29 $17.25
Natural gas - ($/Mcf)..... 2.34 2.31 2.68
Per equivalent BOE (1).... 13.34 11.38 16.75
Average production cost
Per equivalent BOE (1)..... $4.85 $4.05 $4.36
(1)Based on a 6 Mcf to 1 Bbl gas to oil conversion ratio.
Significant Oil and Gas Purchasers
Oil and gas sales are made on a day-to-day basis under short-term
contracts at the current area market price. The loss of any purchaser
would not be expected to have a material adverse effect upon the
Company. For the year ended December 31, 1999, the Company sold 10% or
more of its net production of oil and gas to the following purchasers:
Genesis Crude Oil 23%, Southland Corporation 21%, Hunt Refining 12% and
Dynegy Crude Gathering 12%.
Geographic Segments
All of the Company's operations are 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.
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<PAGE>
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 or the NYMEX price less a discount.
This price is determined on a well-by-well basis and the purchaser
generally takes delivery at the wellhead. Mississippi oil, which
accounted for approximately 90% of the Company's oil production in
1999, is primarily light to medium sour crude and sells at a
significant discount to the NYMEX price. The balance of the oil
production, Louisiana oil, is primarily light sweet crude, which
typically sells at a smaller discount to NYMEX.
In the fourth quarter of 1998, the Company entered into new
contracts for a portion of its Mississippi production which provided
floor pricing (see "Production Price Hedging").
Natural Gas Marketing
Virtually all of Denbury's natural gas production is close to
existing pipelines and consequently, the Company generally has a
variety of options to market its natural gas. The Company sells the
majority of its natural gas on one year contracts with prices
fluctuating month-to-month based on published pipeline indices with
slight premiums or discounts to the index.
Production Price Hedging
The Company enters into various financial contracts to hedge its
exposure to commodity price risk associated with anticipated future oil
and natural gas production. Information as to these activities is set
forth under "Management's Discussion and Analysiss - Market Risk
Management", appearing on pages 42-44 of the Annual Report. Such
information is incorporated herein by reference.
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
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<PAGE>
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
Currently, there are no federal, state or local laws that regulate
the price for sales of natural gas, NGLs and crude oil by the Company.
However, the rates charged and terms and conditions for the movement
of gas in interstate commerce through certain intrastate pipelines and
production area hubs are subject to regulation under the Natural Gas
Policy Act of 1978 ("NGPA"). Pipeline and hub construction activities
are, to a limited extent, also subject to regulations under the Natural
Gas Act of 1938 ("NGA"). The NGA also establishes comprehensive
controls over interstate pipelines, including the transportation and
resale of gas interstate commerce. While these NGA controls do not
apply directly to the company, their effect on natural gas markets can
be significant in terms of competition and cost of transportation
services. The Federal Energy Regulatory Commission ("FERC")
administers the NGA and the NGPA.
Through a series of orders, most recently the Order No. 636 Series,
FERC has taken significant steps to increase competition in the sale,
purchase, storage and transportation of natural gas. FERC's regulatory
programs generally allow more accurate and timely price signals from
the consumer to the producer. Nonetheless, the ability to respond to
market forces can and does add to price volatility, inter-fuel
competition and pressure on the value of transportation other services.
Additional proposals and proceedings that might affect the natural
gas industry are considered from time to time by Congress, FERC, state
regulatory bodies and the courts. The Company cannot predict when or
if any such proposals might become effective and their effect, if any,
on the Company's operations. Historically, the natural gas industry
has been heavily regulated; therefore, there is no assurance that the
less stringent regulatory approach recently pursued by FERC, Congress
and the states will continue indefinitely into the future.
Oil Price Controls
Sales of crude oil, condensate and gas liquids by the Company are
not currently regulated and are made at market prices.
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<PAGE>
Gathering Regulations
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 in the future. Thus the Company's gathering operations could
be adversely affected should they be subject in the future to the
application of state or federal regulation of rates and services.
Environmental Regulations
The Company's operations are subject to numerous laws and
regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. Public interest in
the protection of the environment has increased dramatically in recent
years. The trend of more expansive and stricter environmental
legislation and regulations could continue. To the extent laws are
enacted or other governmental action is taken that restricts drilling
or imposes environmental protection requirements that result in
increased costs to the oil and gas industry in general, the business
and prospects of the Company could be adversely affected.
The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes.
Certain wastes generated by the Company's oil and natural gas
operations that are currently exempt from treatment as "hazardous
wastes" may in the future be designated as "hazardous wastes," and
therefore be subject to more rigorous and costly operating and disposal
requirements.
The Company currently owns or leases numerous properties that for
many years have been used for the exploration and production of oil and
gas. Most of these properties have been operated by prior owners,
operators and third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under the Company's control.
These properties and the wastes disposed thereon may be subject to
Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), Federal Resource Conservation and Recovery Act and
analogous state laws. Under such laws, the Company could be required
to remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators) or property
contamination (including groundwater contamination) or to perform
remedial plugging operations to prevent future contamination.
The Company's operations may be subject to the Clean Air Act
("CAA") and comparable state and local requirements. Certain
provisions of CAA may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the
operations of the Company. The EPA and states have been developing
regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several
years for air pollution control equipment in connection with
maintaining or obtaining operating permits and approvals addressing
other air emission-related issues. However, the Company does not
believe its operations will be materially adversely affected by any
such requirements.
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<PAGE>
Federal regulations require certain owners or operators of
facilities that store or otherwise handle oil, such as the Company, to
prepare and implement spill prevention, control, countermeasure and
response plans relating to the possible discharge of oil into surface
waters. The Oil Pollution Act of 1990 ("OPA") contains numerous
requirements relating to the prevention of and response to oil spills
into waters of the United States. The OPA subjects owners of
facilities to strict joint and several liability for all containment
and cleanup costs and certain other damages arising from a spill,
including but not limited to, the costs of responding to a release of
oil to surface waters. Regulations are currently being developed under
the OPA and state laws concerning oil pollution prevention and other
matters that may impose additional regulatory burdens on the Company.
The Resource Conservation and Recovery Act ("RCRA") is the
principal federal statute governing the treatment, storage and disposal
of hazardous wastes. RCRA imposes stringent operating requirements
(and liability for failure to meet such requirements) on a person who
is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a hazardous waste treatment, storage or
disposal facility. At present, RCRA includes a statutory exemption
that allows most crude oil and natural gas exploration and production
wastes to be classified as nonhazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. At various times
in the past, proposals have been made to amend RCRA and various state
statutes to rescind the exemption that excludes crude oil and natural
gas exploration and production wastes from regulation as hazardous
waste under such statutes. Repeal or modifications of this exemption
by administrative, legislative or judicial process, or through changes
in applicable state statutes, would increase the volume of hazardous
waste to be managed and disposed of by the Company. Hazardous wastes
are subject to more rigorous and costly disposal requirements than are
non-hazardous wastes. Any such change in the applicable statues may
require the Company to make additional capital expenditures or incur
increased operating expenses.
Some states have enacted statutes governing the handling,
treatment, storage and disposal of naturally occurring radioactive
material ("NORM"). NORM is present in varying concentrations in
subsurface and hydrocarbon reservoirs around the world and may be
concentrated in scale, film and sludge in equipment that comes in
contact with crude oil and natural gas production and processing
streams. Mississippi legislation prohibits the transfer of property
for residential or other unrestricted use if the property contains NORM
above prescribed levels.
The Company also is subject to a variety of federal, state, and
local permitting and registration requirements relating to protection
of the environment. Management believes that the Company is in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements
will not have a material adverse impact on the Company.
Other Business Matters
The Company's operations are subject to the usual hazards incident
to the drilling and operation of oil and gas wells, and the processing
and transportation of natural gas and NGLs, such as cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fire,
pollution and other environmental risks. In general, many of these
risks increase when drilling at greater depths under higher pressure
conditions. In addition, certain of the Company's operations are in
water and subject to the additional hazards of marine operations, such
as capsizing, collision and damage or loss from severe weather. Other
operations involve the production, handling, processing and
transportation of hazardous substances. These hazards can cause
personal injury and loss of life, severe damage to and destruction of
property and equipment, environmental damage and suspension of
operations. Litigation arising from a catastrophic occurrence in the
future at one of the Company's locations could result in the Company
being named as a defendant in lawsuits asserting potentially large
claims. In accordance with customary industry practices, insurance is
maintained for the Company against some, but not all, of the
consequences of these risks. Losses and liabilities arising from such
events could reduce revenues and increase costs to the Company to the
extent not covered by insurance or otherwise already reserved.
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<PAGE>
Taxation
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
Estimates of net proved oil and gas reserves as of December 31,
1999, 1998 and 1997 have been prepared by Netherland, Sewell and
Associates, Inc., independent petroleum engineers located in Dallas,
Texas. See Note 9 "Supplemental Reserve Information" of the
Consolidated Financial Statements and pages 6 and 7 of the Annual
Report for disclosure of reserve data. Such information is
incorporated herein by reference.
Item 2. Properties
-------------------
See Item 1. Business - "Oil and Gas Operations." The Company also
has various operating leases for rental of office space, office
equipment, and vehicles. See Note 7 "Commitments and Contingencies" of
the Consolidated Financial Statements for the future minimum rental
payments and such information is incorporated herein by reference.
Item 3. Legal Proceedings
--------------------------
In the opinion of management, there are no material pending legal
proceedings to which the Company or any of its subsidiaries is a party
or of which any of their property is the subject. However, due to the
nature of its business, certain legal or administrative proceedings
arise from time to time in the ordinary course of its business. See
Note 7, "Commitments and Contingencies" of the Consolidated Financial
Statements for further disclosure regarding legal proceedings and
contingencies and such information is included herein by reference.
Item 4. Submission of Matters to a Vote of Security Holders
------------------------------------------------------------
No matters were submitted for a vote of security holders during the
fourth quarter of 1999.
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PART II
Item 5. Market for the Common Stock and Related Matters
--------------------------------------------------------
Information as to the markets in which the Company's common stock
is traded, the quarterly high and low prices for such stock during the
last two years, the restriction on the payment of dividends with
respect to the common stock, and the approximate number of stockholders
of record at February 1, 2000, is set forth under "Common Stock Trading
Summary" appearing on Page 68 of the Annual Report. Such information
is incorporated herein by reference.
Item 6. Selected Financial Data
--------------------------------
Selected Financial Data for the Company for each of the last five
years are set forth under "Financial Highlights" appearing on page 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," appearing on pages 29
through 44 of the Annual Report and is incorporated herein by
reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
-------------------------------------------------------------------
The information required by Item 7A is set forth under "Market
Risk Management" in "Management's Discussion and Analysis," appearing
on pages 42 through 44 of the Annual Report and is incorporated herein
by reference.
Item 8. Financial Statements and Supplementary Data
---------------------------------------------------
The Company's consolidated financial statements, accounting policy
disclosures, notes to financial statements, business segment
information and independent auditors' report are presented on pages 45
through 67 of the Annual Report. Selected quarterly financial data are
set forth under "Unaudited Quarterly Information" appearing on page 67
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
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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
("Proxy Statement") for the Annual Meeting of Shareholders to be held
May 24, 2000, ("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 1999.
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, 2000, 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.
-13-
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
------------------------------------------------------------------------
(a) Financial Statements and Schedules. Financial statements and
schedules filed as a part of this report are presented on pages 45
through 68 of the Annual Report and are incorporated herein by
reference.
Exhibits. The following exhibits are filed as a part of this report.
Exhibit No. Exhibit
----------- -------
3(a) Certificate of Incorporation of Denbury
Resources Inc. filed with the Delaware
Secretary of State on April 20, 1999
(incorporated by reference as Exhibit 3(a) of
the Registrant's Form 10-Q for the quarter
ended March 31, 1999).
3(b) Bylaws of Denbury Resources Inc., a Delaware
corporation, adopted April 20, 1999
(incorporated by reference as Exhibit 3(b) of
the Registrant's Form 10-Q for the quarter
ended March 31, 1999).
4(a) Form of Indenture between Denbury Management
and Chase Bank of Texas, National
Association, as trustee (incorporated by
reference as Exhibit 4(b) of Registrant's
Registration Statement on Form S-3 dated
February 19, 1998).
4(b) First Supplemental Indenture dated as of
April 21, 1999, between Denbury Resources
Inc., a Delaware corporation, and Chase Bank
of Texas, National Association, as Trustee,
relating to Denbury Management, Inc.'s 9%
Senior Subordinated Notes due 2008
(incorporated by reference as Exhibit 4(a) of
the Registrant's Form 10-Q for the quarter
ended March 31, 1999).
10(a) Common Share Purchase Warrant representing
right of Internationale Nederlanden (U.S.)
Capital Corporation to purchase 150,000
Common Shares of Newscope Resources Ltd.
(incorporated by reference as Exhibit 10(c)
of the Registrant's Registration Statement on
Form F-1 dated August 25, 1995).
10(b) Denbury Resources Inc. Stock Option Plan
(incorporated by reference as Exhibit 4(f) of
the Registrant's Registration Statement on
Form S-8, No. 333-1006 dated February 2,
1996, and as amended by the Registrant's
Registration Statements on Form S-8, Nos.
333-27995, 333-55999 and 333-70485, dated
May 29, 1997, June 4, 1998 and January 12,
1999, respectevely).
10(c) Denbury Resources Inc. Stock Purchase Plan
(incorporated by reference as Exhibit 4(g) of
the Registrant's Registration Statement on
Form S-8, No. 333-1006 dated February 2,
1996, and as amended by the Registrant's
Registration Statement on Form S-8, No.
333-70485, dated January 12, 1999).
10(d) ** Form of indemnification agreement between
Denbury Resources Inc. and its officers and
directors (incorporated by reference as
Exhibit 10 of the Registrant's Form 10-Q for
the quarter ended June 30, 1999).
-14-
<PAGE>
Exhibit No. Exhibit
----------- -------
10(e) 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(f) 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(g) Second Amendment to First Restated Credit
Agreement, by and among Denbury Management,
as borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A., as
administrative agent, and NationsBank of
Texas, N.A., as bank, entered into as of
February 25, 1998 (incorporated by reference
as Exhibit 10(l) of the Registrant's Form 10-
K for the year ended December 31, 1997).
10(h) Third Amendment to First Restated Credit
Agreement, by and among Denbury Management,
as borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A., as
administrative agent, and NationsBank of
Texas, N.A., as bank, entered into as of
August 10, 1998 (incorporated by reference as
Exhibit 10 of the Registrant's Form 10-Q for
the quarter ended June 30, 1998).
10(i) Consent letter and form of Fourth Amendment
to First Restated Credit Agreement, by and
among Denbury Management, as borrower,
Denbury Resources Inc., as guarantor,
NationsBank of Texas, N.A. as bank, dated
November 30, 1998 (incorporated by reference
as Exhibit 10(b) to the Registrant's Form S-3
dated January 19, 1999).
10(j) Fourth Amendment to First Restated Credit
Agreement, by and among Denbury Management,
as borrower, Denbury Resources Inc., as
guarantor, NationsBank of Texas, N.A., as
administrative agent, and NationsBank of
Texas, N.A., as bank, entered into as of
February 19, 1999 (incorporated by reference
as Exhibit 10(m) of the Registrant's Form 10-
K for the year ended December 31, 1998).
10(k) Fifth amendment to First Restated Credit
Agreement dated April 21, 1999 between the
Company and NationsBank of Texas, N.A., as
agent, and each of the financial institutions
described on the signature page therein
(incorporated by reference as Exhibit 10(b)
of the Registrant's Form 10-Q for the quarter
ended March 31, 1999).
10(l) Sixth amendment to the first Restated Credit
Agreement dated September 30, 1999 between
the Company and Bank of America, N.A., as
agent, and each of the financial institutions
described on the signature page therein
(incorporated by reference as Exhibit 10 of
the Registrant's Form 10-Q for the quarter
ended September 30, 1999).
10(m) Stock Purchase Agreement between TPG Partners
II, L.L.C. and the Company dated as of
December 16, 1998 (incorporated by reference
as Exhibit 99.1 of the Registrant's Form 8-K
dated December 17, 1998).
13* Annual Report to Shareholders.
21* List of Subsidiaries of Denbury Resources Inc.
23* Consent of Deloitte & Touche LLP
27* Financial Data Schedule
* Filed herewith.
** Compensation arrangements.
(b) Form 8-Ks filed during the fourth quarter of 1999.
None
-16-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, Denbury Resources Inc. has duly caused
this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
DENBURY RESOURCES INC.
March 17, 2000 /s/ Phil Rykhoek
------------------------------------
Phil Rykhoek
Chief Financial Officer
and Secretary
March 17, 2000 /s/ Mark Allen
------------------------------------
Mark Allen
Chief Accounting Officer
and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
Denbury Resources Inc. and in the capacities and on the dates
indicated.
March 17, 2000 /s/ Ronald G. Greene
------------------------------------
Ronald G. Greene
Chairman of the Board and
Director
March 17, 2000 /s/ Gareth Roberts
------------------------------------
Gareth Roberts
Director, President and
Chief Executive Officer
(Principal Executive Officer)
March 17, 2000 /s/ Phil Rykhoek
------------------------------------
Phil Rykhoek
Chief Financial Officer
and Secretary
(Principal Financial Officer)
March 17, 2000 /s/ Mark Allen
------------------------------------
Mark Allen
Chief Accounting Officer
and Controller
(Principal Accounting Officer)
March 17, 2000 /s/ Wilmot L. Matthews
------------------------------------
Wilmot L. Matthews
Director
March 17, 2000 /s/ Wieland F. Wettstein
------------------------------------
Wieland F. Wettstein
Director
-17-
EXHIBIT 13
PAGE 1, PAGE 6, PAGES 11 THROUGH 16 INCLUSIVE, PAGE 19, PAGE 26 AND
PAGES 29 THROUGH 68 INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO
STOCKHOLDERS FOR THE YEAR ENDED DECEMBER 31, 1999, 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>
YEAR ENDED DECEMBER 31,
---------------------------------------------- AVERAGE
AMOUNTS IN THOUSANDS OF ANNUAL
U.S. DOLLARS UNLESS NOTED 1999 1998 1997 1996 1995 GROWTH (2)
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
PRODUCTION (DAILY)
Oil (Bbls) 12,090 13,603 7,902 4,099 1,995 57%
Gas (Mcf) 27,948 36,605 36,319 24,406 13,271 20%
BOE (6:1) 16,748 19,704 13,955 8,167 4,207 41%
REVENUE (NET OF ROYALTIES) 81,575 81,883 85,333 52,880 20,032 42%
UNIT SALES PRICE
Oil (per Bbl) 13.08 10.29 17.25 18.98 14.90 -3%
Gas (per Mcf) 2.34 2.31 2.68 2.73 1.90 5%
CASH FLOW FROM OPERATIONS(1) 31,619 30,096 56,607 34,140 9,394 35%
NET INCOME (LOSS) 4,614 (287,145) 14,903 8,744 714 59%
AVERAGE COMMON SHARES
OUTSTANDING 39,928 25,926 20,224 13,104 6,870 55%
PER SHARE:
Cash flow from
operations: (1)
Basic 0.79 1.16 2.80 2.61 1.37 -13%
Diluted 0.79 1.15 2.64 2.39 1.37 -13%
Net income (loss):
Basic 0.12 (11.08) 0.74 0.67 0.10 5%
Diluted 0.12 (11.08) 0.70 0.63 0.10 5%
OIL AND GAS CAPITAL
INVESTMENTS 54,967 102,652 305,427 86,857 28,524 18%
TOTAL ASSETS 252,566 212,859 447,548 166,505 77,641 34%
LONG-TERM LIABILITIES 154,976 226,436 256,637 7,481 5,077 135%
STOCKHOLDERS' EQUITY
(DEFICIT) AND
PREFERRED STOCK 72,428 (32,265) 160,223 142,504 68,501 1%
PROVEN RESERVES
Oil (MBbls) 51,832 28,250 52,018 15,052 6,292 69%
Gas (MMcf) 50,438 48,803 77,191 74,102 48,116 1%
MBOE (6:1) 60,238 36,383 64,883 27,403 14,312 43%
Discounted future cash
flow - 10% 462,870 115,019 361,329 316,098 96,965 48%
PER BOE DATA (6:1)
Revenue 13.34 11.38 16.75 17.69 13.05 1%
Production taxes (0.60) (0.56) (0.82) (0.94) (0.78) -6%
Lease operating expenses (4.25) (3.49) (3.54) (3.57) (3.64) 4%
----------------------------------------------------------------------------------------
Production netback 8.49 7.33 12.39 13.18 8.63 0%
Administrative expenses (1.21) (1.02) (1.30) (1.50) (1.25) -1%
Interest (expense) income (2.22) (2.13) 0.02 (0.26) (1.26) 15%
Other 0.11 - - - - -
----------------------------------------------------------------------------------------
CASH FLOW (1) 5.17 4.18 11.11 11.42 6.12 -4%
----------------------------------------------------------------------------------------
(1) Exclusive of the net change in non-cash working capital balances.
(2) Computed using 1995 as a base year.
</TABLE>
Reporting Format
Unless otherwise noted, the disclosures in this report have (i) dollar
amounts presented in U.S. dollars, (ii) production volumes expressed on
a net revenue interest basis, and (iii) gas volumes converted to
equivalent barrels at 6:1.
Page 1
<PAGE>
SELECTED OPERATING DATA
OIL AND GAS RESERVES
Our reserves at December 31, 1999, 1998 and 1997 were estimated by
Netherland, Sewell & Associates, Inc., an independent Dallas-based
engineering firm. The reserves were prepared using constant prices and
costs in accordance with the guidelines of the Securities and Exchange
Commission ("SEC"), based on the prices received on a field-by-field
basis as of December 31 of each year. The reserves do not include any
value for probable or possible reserves which may exist, nor do they
include any value for undeveloped acreage. The reserve estimates
represent our net revenue interest in our properties.
Year Ended December 31,
---------------------------
1999(3) 1998 1997
------- ------ -------
ESTIMATED PROVED RESERVES:
Oil (MBbls) ...................... 51,832 28,250 52,018
Natural Gas (MMcf) ............... 50,438 48,803 77,191
Oil Equivalent (MBOE) ............ 60,238 36,383 64,883
PERCENTAGE OF MBOE:
Proved producing ................. 41% 39% 40%
Proved non-producing ............. 25% 38% 26%
Proved undeveloped ............... 34% 23% 34%
REPRESENTATIVE OIL AND GAS PRICES: (1)
Oil - NYMEX ...................... $ 25.60 $ 12.00 $ 18.32
Natural Gas - NYMEX Henry Hub .... 2.12 2.15 2.58
PRESENT VALUES:(2)
Discounted estimated future net
cash flow before income taxes
(PV10 Value) (thousands) ....... $462,870 $115,019 $361,329
Standardized measure of discounted
estimated future net cash flow
after net income taxes (thousands) $448,374 $115,019 $335,308
_______________
(1) The oil prices as of each respective year-end were based on
NYMEX prices per Bbl and NYMEX Henry Hub ("NYMEX") prices per
MMBtu, with these representative prices adjusted by field to
arrive at the appropriate corporate net price.
(2) Determined based on year-end unescalated prices and costs
in accordance with the guidelines of the SEC, discounted at
10% per annum.
(3) For comparative purposes, we also prepared a December 31,
1999 reserve report using a NYMEX oil price of $18.50 and a
NYMEX gas price of $2.50, with these prices also adjusted
by field. The PV10 Value in this report was $281.6 million
with 56.2 MMBOE of proved reserves.
CAPITAL EXPENDITURES
The major components of our capital expenditure programs over the last
three years are as follows:
(Amounts in Thousands) Year Ended December 31,
---------------------------
1999 1998 1997
------ ------- -------
Property acquisitions:
Proved ...................... $20,488 $13,674 $149,145
Unevaluated ................. 1,283 6,604 77,664
Exploration .................... 7,672 12,222 20,734
Development .................... 25,524 70,152 57,884
------ ------- -------
Total capital expenditures .. $54,967 $102,652 $305,427
====== ======= =======
Page 6
<PAGE>
FIELD SUMMARIES
Denbury operates in two core areas, Louisiana and Mississippi. Our
five largest fields constitute approximately 80% of our total proved
reserves on a BOE and PV10 Value basis. Within these five fields we
own an average 94% working interest and operate 98% of the wells.
These five largest fields are located in four counties in Mississippi
and one parish in Louisiana. The concentration of value in a
relatively small number of fields allows us to benefit substantially
from any operating cost reductions or production enhancements and
allows us to effectively manage the properties from our two field
offices in Houma, Louisiana and Laurel, Mississippi. In the table
below, we have included our nine largest fields which comprise
approximately 88% of our PV10 Value.
<TABLE>
Proved Reserves as of 1999
December 31, 1999 (1) Average Production
-------------------------------- ---------------------
Natural PV10 PV10 Gross Average Net
Oil Gas Value Value % Oil Natural Gas Productive Revenue
(MBbls) (MMcf) (000's) of Total (Bbls/d) (Mcf/d) Wells (2) Interest
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Louisiana
Lirette 134 16,537 $ 21,027 4.6% 125 8,376 11 60%
Atchafalaya Bay 252 3,436 8,922 1.9% 267 2,753 3 44%
Bayou Rambio 28 3,975 7,568 1.6% 44 4,037 4 62%
Other Louisiana 341 13,740 18,585 4.0% 327 9,481 29 41%
------ ------ ------- ----- ------ ------ --- ----
Total Louisiana 755 37,688 56,102 12.1% 763 24,647 47 47%
------ ------ ------- ----- ------ ------ --- ----
Mississippi
Heidelberg 31,458 7,988 238,192 51.5% 5,547 963 157 80%
Little Creek 6,146 - 58,440 12.6% 587(3) - 36 83%
Eucutta 4,902 - 41,672 9.0% 2,176 127 46 78%
King Bee 1,583 - 13,522 2.9% 415(3) - 4 66%
Quitman 1,410 - 10,321 2.2% 709 - 19 77%
Davis 1,442 - 8,708 1.9% 546 - 20 92%
Other Mississippi 3,985 3,778 32,823 7.1% 1,289 1,614 66 50%
------ ------ ------- ----- ------ ------ --- ----
Total Mississippi 50,926 11,766 403,678 87.2% 11,269 2,704 348 74%
------ ------ ------- ----- ------ ------ --- ----
Other 151 984 3,090 0.7% 58 597 - -
------ ------ ------- ----- ------ ------ --- ----
Company Total 51,832 50,438 $462,870 100.0% 12,090 27,948 395 71%
====== ====== ======= ====== ====== ====== === ====
(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, 1999. The oil price at that date was a
NYMEX price of $25.60 per Bbl adjusted by field and a
NYMEX natural gas price average of $2.12 per MMBtu also
adjusted by field.
(2) Includes only productive wells in which the Company has
a working interest as of December 31, 1999.
(3) These fields were acquired during 1999. The average
production during the period they were owned by the
Company was 1,520 Bbls/d for Little Creek Field and 592
Bbls/d for King Bee Field.
</TABLE>
Page 7
<PAGE>
ACQUISITIONS
Acquisitions have historically been an integral part of our strategy
and are the primary source of "feedstock" for our exploitation
activities. Although we are primarily interested in acquiring good
properties at good prices, if possible, we try 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
our investment opportunities while still providing significant upside
potential.
Through December 31, 1999, approximately 75% of our oil and gas
reserves have been obtained from acquisitions and the balance from
development of these properties. During the last four years we have
made four key acquisitions, the first being in May 1996. At that time,
we acquired properties in our core areas from Amerada Hess Corporation
for approximately $37.2 million. In December 1997, we acquired oil
properties in the Heidelberg Field from Chevron U.S.A., Inc. for
approximately $202 million. During 1999, we acquired a tertiary
recovery oil field (Little Creek) for $12.3 million and the King Bee
oil field for $4.9 million, both of which are in Mississippi. The
Eucutta Field acquired in the Hess acquisition and the Heidelberg,
Little Creek and King Bee Fields are four out of our top five fields as
of December 31, 1999, based on their PV10 Value.
HESS ACQUISITION
The initial production rates during our first two months of ownership
on the Hess properties averaged 2,945 BOE/d. Subsequent internal
development and exploitation of these properties has made this
acquisition very profitable for us, as production peaked in the second
quarter of 1998 at 9,730 BOE/d, a 230% increase from initial levels.
The production level has decreased in subsequent quarters along with
production declines on several of our horizontal oil wells drilled at
Eucutta Field in late 1997 and early 1998 and a general decrease in
subsequent development work to replace this production. During 1999,
the production averaged 4,120 BOE/d and has generally stabilized at the
January 2000 average production rate of approximately 3,900 BOE/d. As
of December 31, 1999, the proven reserves from this acquisition totaled
8.1 million BOEs with a PV10 Value using December 31, 1999 prices of
$70 million.
CHEVRON ACQUISITION
We have increased production each quarter on our largest acquisition to
date, the Heidelberg Field. When we acquired the property, production
was approximately 2,900 BOE/d. As a result of our subsequent
development work, production for 1998 averaged 3,760 BOE/d and during
the fourth quarter of that year was 4,250 BOE/d. During 1999, we began
to have a production response from the waterflood units at this field.
We had commenced activity on the East Heidelberg Waterflood Unit in
early 1998, the largest waterflood, at which time production was
approximately 250 Bbls/d. By the fourth quarter of 1999, production had
increased to approximately 1,700 Bbls/d. Overall, the average
production at Heidelberg was 4,541 BOE/d, 5,626 BOE/d,
Page 8
<PAGE>
6,140 BOE/d, and 6,500 BOE/d for the first through fourth quarters of
1999, respectively with an annual average of 5,708 BOE/d. As of
December 31, 1999, the proven reserves at Heidelberg Field totaled
32.8 million BOEs with a PV10 Value using December 31, 1999 prices of
$238.2 million.
1999 ACQUISITIONS
During 1999 we completed acquisitions totaling $20.5 million, primarily
composed of the aforementioned Little Creek and King Bee Fields. The
proven reserves from these acquisitions totaled 8.2 million BOEs with a
PV10 Value using December 31,1999 prices of $72 million. These
properties contributed an average of approximately 1,000 BOE/d to our
1999 average production and approximately 2,400 BOE/d to our average
production during the fourth quarter.
BUSINESS STRATEGY
As part of our corporate strategy, we believe in the following
fundamental principles:
* remain focused in specific regions;
* acquire properties where we believe additional value can be created
through a combination of exploitation, development, exploration and
marketing;
* acquire properties that give us a majority working interest and
operational control or where we believe we can ultimately obtain it;
* maximize the value of our properties by increasing production and
reserves while reducing cost; and
* maintain a highly competitive team of experienced and incentivized
personnel.
Illustration not incorporated by reference.
Page 11
<PAGE>
OPERATIONS
As oil prices improved during 1999 we gradually increased our activity
level. During 1999, we spent a total of $34.5 million on exploration
and development expenditures and approximately $20.5 million on
acquisitions. During 1999, we implemented a more conservative capital
spending policy, whereby after the first quarter we essentially limited
our development and exploration expenditures to our estimated cash flow
from operations. We plan to maintain a similar fiscal policy in 2000.
Over one-half of the 1999 budget, excluding acquisitions, was spent at
Heidelberg, our largest field, and we anticipate that a similar
percentage of the 2000 capital expenditures will be expended at
Heidelberg. During 1999, we drilled a total of 20 wells, all but four
of which were development wells. During 1999, the drilling expenditures
totaled $8.6 million, geological, geophysical and acreage expenditures
totaled $5.7 million and the balance of $20.2 million was expended on
recompletions, workovers and associated facilities.
MISSISSIPPI
In Mississippi, the majority of our production is oil, produced largely
from depths of less than 10,000 feet. The fields in this region are
characterized by relatively small geographic areas that generate
prolific production from stacked or multiple pay sands. Our Mississippi
production is usually associated with large amounts of saltwater, which
is disposed of in saltwater disposal wells or re-injected for secondary
recovery operation. The vast majority of wells require artificial lift
equipment. The combination of these factors increase the operating
costs on a per barrel basis as compared to our properties in Louisiana
which are predominately gas producers. We place considerable emphasis
on reducing operating costs in order to maximize the cash flow from
this area. We had a working interest in 348 producing wells in
Mississippi as of the close of 1999, with total proved reserves of 52.9
million BOEs and PV10 Value of $403.7 million using year-end 1999
prices.
Heidelberg Field
Our most important and biggest property is the Heidelberg field,
acquired from Chevron in December 1997. This field was discovered in
1944 and has produced an estimated 193 MMBbls of oil and 36 Bcf of gas
since its discovery. This Field is a large salt-cored anticline that is
divided due to subsequent faulting into western and eastern segments.
Production is from a series of normally pressured Cretaceous and
Jurassic Age sandstone formations situated between 4,500 feet and
11,500 feet. There are 11 producing formations in the Heidelberg Field
containing 40 individual reservoirs, with the majority of the past and
current production coming from the Eutaw and Christmas sands at depths
of approximately 5,000 feet.
Page 12
<PAGE>
Eutaw Sands
By the end of the first quarter of 2000, we should have five waterflood
units in place at Heidelberg; four on the East side and one expanded
unit on the West. These waterflood units produce from the shallow
(approximately 4,400 feet) Eutaw formation. The Eutaw formation
consists of 10 distinct reservoirs, all of which are currently being
waterflooded. To date, the cumulative production from these sands is
estimated at 81 million barrels, or approximately 22% of the estimated
original oil in place. We believe that a properly designed and executed
waterflood program should increase the recovery factor to 36%, similar
to that expected from the nearby and analogous Eucutta Field.
Shortly after we acquired Heidelberg Field, we implemented an inverted
5-spot waterflood in East Fault Block No. 1. East Fault Block No. 1
began to show response in late 1998 and early 1999 and the net
production from the waterflood has increased from approximately 250
Bbls/d when water injection commenced to approximately 1,700 Bbls/d by
the fourth quarter of 1999. The response has continued to exceed the
projections of our independent engineers and we expect additional
production increases in 2000. As of year-end 1999, our proven reserves
included 12.1 million BOEs attributable to this unit with a PV10 Value
of $84 million. There are three additional recently formed waterflood
units in East Heidelberg. These units are not as large as East Fault
Block No. 1, but the reservoir and fluid properties are nearly
identical. Water injection commenced in two of these units during the
fourth quarter of 1999. Although we expect these additional units to
have a response similar to the response experienced in East Fault Block
No. 1, the actual daily production rates will be lower as these units
cover a smaller geographical area.
Illustration not incorporated by reference.
Water injection was commenced by Chevron in the West Heidelberg Eutaw
sands late in 1996. This unit has not responded as well as the East
unit, which we ascribe to the lack of a proper waterflood pattern. We
have begun to modify the original line drive waterflood into
an inverted 5 spot pattern, we are drilling additional producing and
Page 13
<PAGE>
injection wells, and we are upgrading the lift capacity. While it is
too early to forecast absolute results, the production has increased in
this unit from approximately 300 Bbls/d in mid 1998 to approximately
700 Bbls/d as of the fourth quarter of 1999. Approximately 25% of our
2000 budget is scheduled for Heidelberg waterflood units, which entails
the drilling, reactivating or conversion of approximately 15 production
wells and 15 injection wells, pump upgrades, facility work and other
development activities.
Illustration not incorporated by reference.
Christmas Sands
The Christmas formation, located just below the Eutaw formation, is the
second most prolific formation at Heidelberg. The Christmas formation
consists of four sand packages that occur throughout the field. Since
its discovery, the Christmas sands have produced approximately 69
MMBbls. We believe that poor sweep efficiency is experienced in this
reservoir due to low gravity oils, stratified permeability, and the
presence of a strong water drive. We have confirmed the poor sweep
efficiency by drilling wells in close proximity to existing wells and
encountered relatively undrained areas within these sands. We currently
plan to drill eight additional wells in the Christmas sands during
2000. As of year-end 1999, our proven reserves included 7.8 million
BOEs attributable to the Christmas sands with a PV10 Value of $63
million using year-end prices.
Other Sands
Several additional zones below the Christmas formation, including the
Tuscaloosa, Paluxy, Rodessa, Hosston, Cotton Valley and Smackover
formations, have produced on a cumulative basis a combined 15 MMBbls
and 10 Bcf through December 1999. We believe that additional reserve
potential may exist for extensions of existing reservoirs, potential
new reservoirs and additional waterflood opportunities within the
Heidelberg Field area. We currently plan to drill an additional five
wells in these deeper sands during 2000. Although our drilling plans
may appear modest for 2000, we can produce a large percentage of the
reserves in these deeper sands through existing wells. The wells
planned for 2000 are positioned to delineate newly discovered
reservoirs in 1999 while providing additional production or injection
opportunities for planned waterfloods. As of year-end 1999, our proven
reserves included 4.4 million BOEs attributable to these sands with a
PV10 Value of $51.6 million using year-end prices.
We are also developing the Selma Chalk sand at a depth of approximately
3,400-3,600 feet. This sand, while named the Chalk, is actually a
blanket sand reservoir that overlies the entire field. Selma gas was
historically used as lease fuel with very little of the gas actually
being sold. Development of the Selma gas began in 1990 but little
Page 14
<PAGE>
development occurred between 1990 and 1999. This formation was
originally developed on 320-acre spacing, but we have obtained approval
to reduce the spacing to 80 acres and may ultimately propose 40 acre
spacing. We plan to drill an additional five to six wells in this
formation during 2000.
We have increased Heidelberg production each quarter since we took over
operations. When we acquired the property, production was approximately
2,900 BOE/d. As a result of our subsequent development work, production
for 1998 averaged 3,760 BOE/d and during the fourth quarter of that
year was 4,250 BOE/d. During 1999, the production continued to climb
with overall production at Heidelberg averaging 4,541 BOE/d, 5,626
BOE/d, 6,140 BOE/d, and 6,500 BOE/d for the first through fourth
quarters of 1999, respectively, with an annual average of 5,708 BOE/d.
As of December 31, 1999, the proven reserves at Heidelberg totaled 32.8
million BOEs with a PV10 Value of $238.2 million using December 31,
1999 prices.
Graph not incorporated by reference.
Little Creek Field
Our second largest field based on PV10 Value at year-end 1999 was
Little Creek Field, acquired in the third quarter of 1999 for $12.3
million. Little Creek is a tertiary recovery (carbon dioxide flood)
project with 36 producing wells and 17 injection wells. We have a 99%
working interest in this field that produces light sweet oil from the
Tuscaloosa formation. Although operating costs in Little Creek are
higher than our corporate average due to the tertiary recovery
operations, its oil receives a price with a significantly lower
discount to NYMEX than our corporate average, thus almost offsetting
the higher operating costs.
This field was discovered in 1958 and the pilot phase of CO2 flooding
began in 1974. Five phases are currently planned, with the first two
phases virtually completed. These first two phases increased the
ultimate recovery factor in that portion of the field by approximately
14%. Phase III was implemented in 1997 and our 2000 plans include
implementing phase IV. Based on an incremental recovery factor of 10.6%
for the third through fifth phases, our proven reserves as of year-end
were 6.1 million BOEs with a PV10 Value of $58.4 million using year-end
prices. Assuming Phases III, IV and V perform as well as the first two
phases, there may be an additional two to three million barrels to
recover. Production at this field averaged 1,629 BOE/d during the
fourth quarter. Production from Little Creek is expected to increase
throughout 2000 and peak during 2003 at an estimated net rate of 3,300
BOE/d.
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<PAGE>
Illustration not incorporated by reference.
Eucutta Field
We acquired the Eucutta Field in our May 1996 Amerada Hess purchase.
The field is located about 18 miles east of Laurel, Mississippi and
about 10 miles from Heidelberg Field. Since its discovery in 1943, this
field has produced 50 MMBbls.
The Eucutta Field is divided into a shallow Eutaw sand unit in which we
have a 78% working interest and the deeper Tuscaloosa, Wash-Fred,
Paluxy, Rodessa, Sligo and Hosston sand zones in which we have 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.
Late in 1999, we began isolating lower Eutaw sands that we thought were
in communication with the existing waterflood. We have established
nearly 400 BOE/d of production within these lower Eutaw sands.
Additional testing will be required to accurately predict the
additional reserves from these intervals.
In late 1997, we established new production in the Paluxy interval in a
series of six stacked sands. Production peaked in this field in the
second quarter of 1998 as a result of eight additional horizontal wells
drilled in the last half of 1997 and first half of 1998. Production for
1999 averaged 2,200 BOE/d and as of December 31, 1999, the proven
reserves at Eucutta totaled 4.9 million BOEs with a PV10 Value of $41.7
million using year-end prices.
Other Mississippi Fields
In addition to the above fields, we own a working interest in 109
producing wells in 32 fields in Mississippi, which in the aggregate
averaged approximately 3,000 Bbls/d and 1.6 MMcf/d of net production
during 1999. As of December 31, 1999, the proven reserves on these
other Mississippi fields totaled 9.0 million BOEs with a PV10 Value of
$65.4 million using year-end prices.
SOUTHERN LOUISIANA
Our southern Louisiana producing fields are typically large complex
structural features containing multiple stacked 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 via water-
drive.
The majority of the our southern Louisiana fields lie in the Houma
embayment area of Terrebonne and LaFourche Parishes. The area is
characterized by complex geological structures that have produced
prolific reserves, typical of the lower Gulf Coast geosyncline. The
advent
Illustration not incorporated by reference.
Page 16
<PAGE>
and availability of 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. We currently own or
have license to work on over 550 square miles of 3-D seismic data and
plan to continue to expand our data ownership. We believe 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 geo-pressured sections below 12,000 feet.
The majority of our exploration plans for 2000 are located in
Terrebonne Parish and are the result of 3-D seismic interpretation.
We participated in two successful exploratory wells located in the Main
Pass area, offshore Louisiana, during 1999. Current plans include the
drilling of two additional wells to fully develop these two
discoveries. The combined rate from the four wells is expected to
exceed 25 MMcf/d based on testing of the first two wells. Facilities
are currently being designed, with installation scheduled for the late
third quarter of 2000. Based on our 19% net interest, our production is
estimated at approximately 5 MMcf/d. We have several additional
prospects in the Main Pass area that may be drilled in 2000 or 2001.
We had a working interest in 47 producing wells in Louisiana as of the
close of 1999, with total proved reserves of 7.0 million BOEs and a
PV10 Value of $56.1 million using year-end 1999 prices.
Lirette Field
Lirette is our largest gas field and our largest Louisiana property in
terms of PV10 Value. 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 since its
initial discovery in 1937. The field is located in six to ten feet of
inland water and produces from depths of 8,000 feet to 16,000 feet.
During 1999 we acquired an additional interest in this field, bringing
our current working interest to over 90%. During 1999 the net
production from this field averaged approximately 8.4 MMcf/d and 125
Bbls/d from 11 wells and as of December 31, 1999, we had total proved
reserves of 2.9 million BOEs with a PV10 Value of $21.0 million using
year-end 1999 prices. During 2000 we will have a 66% working interest
in an exploratory well we expect to drill in the first half of the year
which will target a 3-D identified fault block in the Tex W sands.
Other Louisiana Fields
In addition to the Lirette Field, we own a working interest in 36
producing wells at 29 other fields in Louisiana, which in the aggregate
averaged approximately 16.3 MMcf/d and 638 Bbls/d of net production
during 1999. As of December 31, 1999, the proven reserves on these
other Louisiana fields totaled 4.1 million BOEs with a PV10 Value of
$35.1 million using year-end prices.
Page 19
<PAGE>
SELECTED ABBREVIATIONS
Bbl One stock tank barrel, of 42 U.S. gallons liquid
volume, used herein in reference to crude oil or
other liquid hydrocarbons.
Bbls/d Barrels of oil produced per day.
Bcf One billion cubic feet of natural gas.
BOE One barrel of oil equivalent using the ratio of one
barrel of crude oil, condensate or natural gas liquids
to 6 Mcf of natural gas.
BOE/d BOEs produced per day.
Btu British thermal unit, which is the heat required to
raise the temperature of a one-pound mass of water
from 58.5 to 59.5 degrees Fahrenheit.
MBbls One thousand barrels of crude oil or other liquid
hydrocarbons.
MBOE One thousand BOEs.
MBtu One thousand Btus.
Mcf One thousand cubic feet of natural gas.
Mcf/d One thousand cubic feet of natural gas produced
per day.
MMBbls One million barrels of crude oil or other liquid
hydrocarbons.
MMBOE One million BOEs.
MMBtu One million Btus.
MMcf One million cubic feet of natural gas.
PV10 Value When used with respect to oil and natural gas
reserves, PV10 Value means the estimated future gross
revenue to be generated from the production of proved
reserves, net of estimated production and future
development costs, using prices and costs in effect at
the determination date, without giving effect to non-
property-related expenses such as general and
administrative expenses, debt service and future
income tax expense or to depreciation, depletion and
amortization, discounted to present value using an
annual discount rate of 10% in accordance with the
guidelines of the Securities and Exchange Commission.
Proved Reserves that can be expected to be recovered through
Developed existing wells with existing equipment and operating
Reserves methods.
Proved The estimated quantities of crude oil, natural gas and
Reserves natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Reserves that are expected to be recovered from new
Undeveloped wells on undrilled acreage or from existing wells
Reserves where a relatively major expenditure is required.
Tcf One trillion cubic feet of natural gas.
Working The operating interest which gives the owner the right
Interest to drill, produce and conduct operating activities on
the property as well as to a share of production.
Page 26
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region,
primarily onshore in Louisiana and Mississippi. Denbury's primary
strategy is to acquire properties which it believes have significant
upside potential and to then increase the value of these properties
through the efficient development, enhancement and operation of those
properties. Denbury's corporate headquarters is in Dallas, Texas, and
it has two primary field offices in Houma, Louisiana and Laurel,
Mississippi.
CAPITAL RESOURCES AND LIQUIDITY
As a result of depressed oil prices in 1998 which continued into
the first part of 1999, the Company's cash flow and results of
operations were adversely affected during 1998 and the first quarter of
1999. This reduction in cash flow also contributed to an increase in
the Company's debt levels, which as a multiple of cash flow were at
historic highs as of December 31, 1998. As a result, the Company
sought additional capital and in December 1998 entered into an
agreement to sell $100 million of common stock to our largest
shareholder, the Texas Pacific Group ("TPG"), which occurred on April
21, 1999 (see "1999 Sale of Equity and Move of Domicile" below).
<TABLE>
Graph depicting the NYMEX crude oil price postings by month from
January 1996 through December 1999:
<C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Jan-96 Feb-96 Mar-96 Apr-96 May-96 Jun-96 Jul-96 Aug-96 Sep-96 Oct-96 Nov-96 Dec-96
18.70 18.78 21.18 23.29 21.09 20.43 21.25 21.91 23.93 24.89 23.55 25.12
Jan-97 Feb-97 Mar-97 Apr-97 May-97 Jun-97 Jul-97 Aug-97 Sep-97 Oct-97 Nov-97 Dec-97
25.18 22.17 20.97 19.73 20.87 19.22 19.66 19.95 19.78 21.28 20.22 18.32
Jan-98 Feb-98 Mar-98 Apr-98 May-98 Jun-98 Jul-98 Aug-98 Sep-98 Oct-98 Nov-98 Dec-98
16.73 16.08 15.05 15.47 14.93 13.67 14.08 13.38 14.98 14.46 12.96 11.24
Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99
12.49 12.02 14.68 17.30 17.77 17.92 20.10 21.28 23.79 22.67 24.77 26.09
</TABLE>
During 1999, the Company made significant strides in rebuilding its
balance sheet and improving its financial condition. Oil prices
increased sharply during 1999 from a NYMEX average of approximately
$13.00 per Bbl during the first quarter to approximately $24.50 per Bbl
during the fourth. The Company's production also increased throughout
1999 from a first quarter average of 15,417 barrels of oil equivalent
produced per day ("BOE/d") to a fourth quarter average of 18,491 BOE/d,
an increase of 20%. This was accomplished through a combination of
both acquisitions and an increase in the Company's base production.
FEBRUARY 1999 AMENDMENT TO BANK CREDIT FACILITY. On February 19,
1999, the Company amended its credit facility with Bank of America, as
agent for a group of eight other banks. Under this amendment, the
borrowing base was set at $110 million, of which $60 million was
classified as within their normal credit guidelines. The credit
facility's other restrictions continued, such as a prohibition on the
payment of dividends and a prohibition on most debt, liens and
corporate guarantees. This amendment:
* provided certain relief on the minimum equity and interest coverage
tests;
* changed the facility to one secured by substantially all of the
Company's oil and natural gas properties;
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<PAGE>
* required that as long as the borrowing base is larger than the
normal credit guideline borrowing base (currently $60 million), at
least 75% of the funds borrowed must be used for either qualifying
acquisitions or capital expenditures to maintain, enhance or
develop proved reserves ("Qualified Purpose"); and
* increased the interest rate to a range from LIBOR plus 1.0% to
LIBOR plus 1.75% (depending on the amounts outstanding) and LIBOR
plus 2.125% on all debt if the outstanding debt exceeds the
borrowing base under normal credit guidelines, currently set at $60
million.
After the repayment of the credit facility in April 1999 with the
proceeds from the TPG stock sale, $9.6 million remained outstanding on
the facility, leaving a total borrowing capacity at that time of
approximately $100 million. Since April, the Company has borrowed
$17.9 million on this facility for two acquisitions, resulting in $27.5
million of outstanding bank debt as of December 31, 1999. At the
October 1, 1999 re-determination of the borrowing base, the conforming
borrowing base of $60 million and the total borrowing base of $110
million were re-affirmed, leaving the Company with a total borrowing
capacity of $82.5 million as of December 31, 1999. The Company also
made a slight modification to the bank agreement as of September 30,
1999, which reduced from $25 million to $15 million the amount that
could be borrowed by the Company for expenditures other than a
Qualified Purpose. During 1999, all of the Company's borrowings were
for a Qualified Purpose.
Graph depicting the Company's bank debt by quarter for 1999 (in
millions of dollars):
1st Qtr 2nd Qtr 3rd Qtr 4th Qtr
109.6 17.5 27.5 27.5
The next scheduled borrowing base re-determination will be as of
April 1, 2000. There can be no assurance that the banks will not
reduce the borrowing base at that time, as such redetermination will
depend on current and expected oil and natural gas prices at that time,
the Company's development and acquisition results during 1999, the then
current level of debt and several other factors, some of which are
beyond the Company's control.
1999 SALE OF EQUITY AND MOVE OF DOMICILE. In April 1999, our
stockholders voted to move Denbury's domicile from Canada to the United
States as a Delaware corporation and to sell 18,552,876 shares of
common stock to an affiliate of TPG for $100 million or $5.39 per
share. As part of the move of domicile, the Company's wholly-owned
subsidiary, Denbury Management, Inc. ("DMI"), was merged into the new
Delaware parent which expressly assumed all liabilities of DMI,
including DMI's obligation for the 9% Senior Subordinated Notes due
2008 and DMI's outstanding bank credit facility. As a result of this
transaction, TPG's ownership of the Company's outstanding common stock
increased from 32% to 60%. The Company intends to use the proceeds from
Page 30
<PAGE>
the TPG equity sale for acquisitions, although in the interim, the
funds have been used to reduce its outstanding bank debt.
The TPG equity infusion and related reduction in debt, the improved
oil prices and the production increases have all made a positive impact
on the Company's earnings and cash flow during 1999. These factors are
also expected to continue to impact future periods. The Company's debt
to cash flow ratio was reduced from 7.5 times as of the end of 1998 to
less than 3.0 times for the fourth quarter of 1999 on an annualized
basis. Without the $2.8 million of cash outflow during the fourth
quarter of 1999 on the oil hedge that expired in December 1999 (3,000
Bbls/d at $14.24 per Bbl - see "Market Risk Management"), this debt
ratio would have been reduced even more to approximately 2.4 times.
Furthermore, the Company's debt to PV10 Value and debt per BOE went
from 196% and $6.18, respectively, as of December 31, 1998 to 33% and
$2.53, respectively, as of December 31, 1999.
The improved product prices have also allowed the Company to pursue
oil development opportunities that were uneconomical at the low oil
prices that prevailed in the second half of 1998 and first quarter of
1999. However, there can be no assurance that the recent increase in
oil prices will be sustained. In addition, with the funds made
available by the equity sale to TPG, the Company intends to pursue oil
and gas acquisitions which, if accomplished, should be accretive to the
Company's operating results. There can be no assurance that suitable
acquisitions will be identified in the future or that any such
acquisitions will be successful in achieving desired profitability
objectives. Without suitable acquisitions or the capital to fund such
acquisitions, the Company's future growth could be limited or even
eliminated.
Graph comparing the Company's 1999 development expenditures to its cash
flow, by quarter for 1999 (in millions of dollars):
1st Qtr 2nd Qtr 3rd Qtr 4th Qtr
Development expenditures 4.7 8.1 9.5 12.2
Cash flow from operations 2.5 6.6 9.5 13.0
The Company's development budget for 2000 is $60 million with
approximately 50% of these expenditures targeted for the Heidelberg
Field. Slightly more than half of these anticipated expenditures at
the Heidelberg Field are for additional drilling, pump upgrades,
facility and other development work on the waterflood units. The
balance of the planned expenditures is for further developmental
drilling in other areas of the field, primarily in the Christmas
formation. An additional 20% of the 2000 budget relates to
recompletions and workovers in various other fields, and an additional
10% to 15% of the budget is devoted to exploratory drilling, seismic or
other exploratory type expenditures. During 2000, the Company plans to
follow a similar fiscal policy as it did during 1999 and keep its
development and exploration expenditures at approximately the same
level as cash flow from operations. As such, although the level of the
Company's projected cash flow is highly variable and difficult
to predict due to volatility in product prices, the success of
Page 31
<PAGE>
its drilling and developmental work and other factors, the Company
currently does not expect its development spending in 2000 to
materially increase its debt. The Company also expects that this
spending level should lead to a slight increase in production
throughout the year. If acquisitions are unavailable at attractive
rates, the Company does have an inventory of potential development
projects that it could commence, subject to the availability and
allocation of capital resources.
SOURCES AND USES OF FUNDS
During 1999, the Company spent approximately $34.5 million on
exploration and development expenditures and approximately $20.5
million on acquisitions. The exploration and development expenditures
included approximately $8.6 million spent on drilling, $5.7 million of
geological, geophysical and acreage expenditures and $20.2 million
spent on facilities and workover costs. These exploration and
development expenditures were funded primarily by cash flow from
operations. The acquisitions were funded by both cash flow and
incremental bank debt of $17.9 million (See also "1999 Acquisitions").
Graph depicting the Company's capital expenditures during the last
three years (in millions of dollars):
1997 1998 1999
----- ----- -----
Development 81.3 89.0 34.5
Acquisitions 224.1 13.7 20.5
----- ----- -----
Total 305.4 102.7 55.0
===== ===== =====
During 1998, the Company spent approximately $89.0 million on
exploration and development activities and approximately $13.7 million
on acquisitions. The exploration and development expenditures included
approximately $53.0 million spent on drilling, $17.8 million of
geological, geophysical and acreage expenditures and $18.2 million
spent on workover costs. These expenditures were funded by bank debt
($60.0 million), cash flow from operations ($20.3 million) and from
cash and other sources ($22.4 million). Of the total 1998 expenditures
of $102.7 million, approximately 26% or $27 million of the development
expenditures were directed to long-term projects such as production
facilities and waterflood units, plus undeveloped properties such as
acreage and seismic that were not expected to benefit the Company until
1999 or beyond.
During 1997, the Company spent approximately $81.3 million on oil
and natural gas exploration and development activities and
approximately $224.1 million on acquisitions, the majority of which
related to the $202 million acquisition from Chevron in December. The
exploration and development expenditures included approximately $55.9
million spent on drilling, $9.0 million of geological, geophysical and
acreage expenditures and the balance of $16.4 million spent on workover
costs. These expenditures were funded by available cash ($3.2
million), cash flow from operations ($62.3 million) and bank debt
($239.9 million).
RESULTS OF OPERATIONS
Operating Income
Production volumes on a BOE basis were 15% lower during 1999 when
compared to 1998, as indicated below. This decline was generally the
result of a curtailment in
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<PAGE>
spending during the last half of 1998 when oil prices declined.
Production volumes for the Company peaked in the second quarter of 1998
and then declined each quarter thereafter through the first quarter
of 1999. Beginning with the second quarter of 1999, production has
increased each quarter, corresponding with the increase in oil prices
and a general resumption of development activities and increased
spending. Even though total production volumes were lower in 1999,
because of improved oil prices, there was very little change in net
operating income between the two years. These statistics and other data
are set forth in the following chart.
Year Ended December 31,
---------------------------------------------------------------------
1999 1998 1997
---------------------------------------------------------------------
Operating income (thousands)
Oil sales $57,713 $51,080 $49,748
Natural gas sales 23,862 30,803 35,585
Less production taxes (3,662) (4,049) (4,156)
Less lease operating
expenses (26,029) (25,113) (18,062)
---------------------------------------------------------------------
Operating income $51,884 $52,721 $63,115
---------------------------------------------------------------------
Unit prices - including impact
of hedges (1)
Oil price per Bbl $ 13.08 $ 10.29 $ 17.25
Gas price per Mcf 2.34 2.31 2.68
Unit prices - excluding impact
of hedges (1)
Oil price per Bbl $ 15.03 $ 10.29 $ 17.25
Gas price per Mcf 2.42 2.32 2.68
---------------------------------------------------------------------
Netback per BOE (2)
Sales price $ 13.34 $ 11.38 $ 16.75
Production taxes (0.60) (0.56) (0.82)
Lease operating expenses (4.25) (3.49) (3.54)
---------------------------------------------------------------------
Production netback $ 8.49 $ 7.33 $ 12.39
---------------------------------------------------------------------
Average daily production volume
Bbls 12,090 13,603 7,902
Mcf 27,948 36,605 36,319
BOE (2) 16,748 19,704 13,955
---------------------------------------------------------------------
(1) See also "Market Risk Management" below for information concerning
the Company's hedging transactions.
(2) Barrel of oil equivalent using the ratio of one barrel of oil to
six Mcf of natural gas ("BOE").
Page 33
<PAGE>
PRODUCTION. Prior to 1998, the Company's average daily production
increased each quarter for several years in a row, fueled by a
combination of internal growth and acquisitions. The Company's
production peaked during the second quarter of 1998 at 21,927 BOE/d and
then began to decline due to (i) shutting in uneconomic wells, (ii)
declines on existing production, particularly from horizontal wells,
and (iii) the postponement of several oil development projects due to
low oil prices. This decline continued through the first quarter of
1999, after which oil prices began to increase and the Company resumed
its development program. In addition, about this same time the Company
began to experience a production response from its Heidelberg
waterflood units that had been initiated in the prior year. Since the
first quarter of 1999, production has increased gradually each quarter.
Graph depicting the Company's average daily production by quarter from
1996 through 1999 ( MBOE per day):
1996 1997
------------------------- -------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
---- ---- ---- ---- ---- ---- ---- ----
Oil 2.1 3.7 4.8 5.8 7.2 7.5 8.1 8.7
Natural Gas 3.4 4.1 4.4 4.3 5.1 5.9 6.1 7.2
---- ---- ---- ---- ---- ---- ---- ----
Total 5.5 7.8 9.2 10.1 12.3 13.4 14.2 15.9
==== ==== ==== ==== ==== ==== ==== ====
1998 1999
------------------------- -------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
---- ---- ---- ---- ---- ---- ---- ----
Oil 14.7 15.6 12.8 11.3 10.3 11.5 12.5 14.0
Natural Gas 6.7 6.3 6.6 4.8 5.1 4.5 4.5 4.5
---- ---- ---- ---- ---- ---- ---- ----
Total 21.4 21.9 19.4 16.1 15.4 16.0 17.0 18.5
==== ==== ==== ==== ==== ==== ==== ====
The Company's recent acquisitions and subsequent development work
thereon are the primary factors leading to the Company's production
increases in recent years. During 1996, the Company completed a key
acquisition for $37 million from Amerada Hess. In December 1997 it
completed a $202 million acquisition from Chevron.
The initial production rates for the first two months of ownership
on the properties acquired from Amerada Hess averaged 2,945 BOE/d, with
virtually all of the subsequent production increases coming from
internal development and exploitation of these properties. The
production on these Hess properties peaked in the second quarter of
1998 at 9,730 BOE/d. During the third quarter of 1998, the average
production on these properties began to decline and for 1999 averaged
4,120 BOE/d. This decrease is primarily due to production declines on
several horizontal oil wells drilled at Eucutta Field in late 1997 and
early 1998 and the lack of subsequent development work to replace this
production. The production from these fields has generally stabilized
and for the month of January 2000 averaged approximately 3,900 BOE/d.
The Company has increased production each quarter on its largest
acquisition to date, the Heidelberg Field, acquired from Chevron in
December 1997. At the time of acquisition, this property was producing
approximately 2,900 BOE/d. As a result of
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<PAGE>
development work on this field, particularly during the first six
months of 1998, production for 1998 averaged 3,760 BOE/d and for the
fourth quarter averaged 4,250 BOE/d. During 1999, production
increased significantly from the waterflood units at Heidelberg,
particularly the East Heidelberg Waterflood Unit. Activity on this
unit had commenced in early 1998 and production on this unit increased
from approximately 250 Bbls/d in the summer of 1998 to approximately
1,700 Bbls/d for the fourth quarter of 1999. Overall, the average
production at Heidelberg was 4,541 BOE/d, 5,626 BOE/d, 6,140 BOE/d
and 6,500 BOE/d for the first through fourth quarters of 1999,
respectively, with an annual average of 5,708 BOE/d.
1999 ACQUISITIONS. During 1999 the Company completed acquisitions
totaling $20.5 million, primarily comprised of a $12.3 million
acquisition of a tertiary recovery oil field (Little Creek) in Southern
Mississippi and a $4.9 million acquisition of the King Bee Field, also
in Mississippi. The proven reserves from these acquisitions totaled
8.1 million BOEs with a present value of future net revenues discounted
at 10% ("PV10 Value") using December 31, 1999 prices of $72 million.
These properties contributed approximately 1,000 BOE/d to our average
daily production rate in 1999 and approximately 2,400 BOE/d to the
fourth quarter average.
Graph depicting the Company's average net oil price by year (dollars
per Bbl):
1997 1998 1999
------ ----- -----
17.25 10.29 13.08
REVENUE. Oil and natural gas revenues have not changed
dramatically from 1997 to 1999, although the components underlying the
revenue have changed substantially. Between 1997 and 1998, even though
production increased 41%, oil and natural gas revenues dropped 4% due
to a 40% drop ($6.96 per Bbl) in the average oil prices and a 14% drop
($0.37 per Mcf) in the average natural gas prices. Based on 1998
production levels, these reduced product prices caused 1998 oil and
natural gas revenues to decrease by approximately $40 million compared
to revenues if 1997 average prices had continued. Between 1998 and
1999 production decreased 15%, but oil and natural gas revenues
declined less than 1% due to a 27% increase ($2.79 per Bbl) in the net
oil price and a slight increase in natural gas prices. Included in the
1999 net oil price is an $8.6 million loss on oil hedging, which
equates to approximately $1.95 per Bbl. Approximately $5.8 million of
this loss relates to a 3,000 Bbls/d swap at $14.24 per Bbl that ended
in December 1999. The Company also realized a $126,000 loss on its
natural gas hedges and expensed $672,000 that it paid to reduce its gas
Graph depicting the Company's average net gas price by year (dollars
per Mcf):
1997 1998 1999
---- ---- ----
2.68 2.31 2.34
Page 35
<PAGE>
hedges for November 1999 through December 2000 to its current level of
24 MMBtu/d (see "Market Risk Management").
OPERATING EXPENSES. Between 1997 and 1998 overall production taxes
and operating expenses increased primarily due to an increase in the
number of properties, principally from the Hess and Chevron
acquisitions. Even though the number of properties increased,
production increased at a faster pace, allowing the Company to reduce
its production taxes and operating expenses on a BOE basis by 7%
between 1997 and 1998. Between 1998 and 1999 total production and
operating expenses were relatively unchanged, although the cost per BOE
increased 20% between the two years. This increase is even more
pronounced for the fourth quarter of 1999, when operating costs per BOE
were $5.56. This increase in operating expenses was the result of
several wells being returned to production, an increase in production
taxes related to higher product prices, and the addition of Little
Creek Field during the third quarter of 1999, which has a higher
operating cost per barrel due to tertiary recovery operations.
Operating costs on this field averaged $12.45 per BOE during the time
the Company owned the property in 1999. Expenses are expected to
remain high on this field as the Company is initiating additional
phases of tertiary recovery, although operating expenses are expected
to be approximately $3 to $4 per BOE less than the current levels over
the life of the property as the Company is able to recover and recycle
more carbon dioxide in the future.
For the properties acquired in the Hess acquisition, operating
expenses declined from the 1996 level of $5.35 per BOE to $3.39 per BOE
for 1998, but increased to $4.63 per BOE for 1999 as a result of the
production declines. Operating expenses per BOE on the Heidelberg
Field acquired from Chevron have decreased from their initial level of
$6.38 per BOE when acquired in late 1997 to an average of $5.04 per BOE
in 1998, and an average of $5.12 per BOE for 1999. The savings were a
result of general cost saving measures and increased productivity per
well through overall production increases, partially offset in 1999 by
the increased cost of waterflood operations as several wells were
returned to production.
General and Administrative Expenses
As outlined below, general and administrative ("G&A") expenses have
increased along with the Company's growth.
Year Ended December 31,
------------------------------------------------------------------
1999 1998 1997
------------------------------------------------------------------
Net G&A Expenses (Thousands)
Gross expenses $20,119 $18,962 $13,909
State franchise taxes 346 785 428
Operator overhead charges (10,278) (9,749) (5,502)
Capitalized
exploration expenses (2,812) (2,657) (2,225)
------------------------------------------------------------------
Net expenses $ 7,375 $ 7,341 $ 6,610
------------------------------------------------------------------
Average G&A cost per BOE $ 1.21 $ 1.02 $ 1.30
Employees as of December 31 220 205 157
------------------------------------------------------------------
Page 36
<PAGE>
On a BOE basis, G&A costs decreased 22% between 1997 and 1998 but
increased 19% between 1998 and 1999, largely related to the changes in
production levels. On a gross basis, G&A expenses have increased each
year as indicated above, with an average increase in net G&A expenses
of 6% over the three year period.
Generally, the Company was very active during 1997 and the first
part of 1998, but then significantly reduced its field expenditures and
activity during the second half of 1998 due to the decline in oil
prices. The activity level has gradually resumed in 1999, beginning
with the second quarter, as oil prices have rebounded. Although an
annual comparison between 1998 and 1999 reveals only minor changes, the
trend is significantly different. Gross G&A increased between 1997 and
1998 primarily due to the acquisition of Heidelberg Field in late 1997
and a corresponding increase in the number of employees employed by the
Company. Between 1998 and 1999, the single largest component of the
increase in gross G&A expenses was a reinstatement of a bonus accrual
in the third quarter of 1999, as no accrual was made during the last
half of 1998 or the first half of 1999. Also contributing to the
increase in 1999 were increased consultant fees as a result of the
increased activity and increased rent expense as a result of an
increase in office space and the expiration of a lease in May 1999
which was below the current market rate.
As briefly discussed above, the net G&A is also affected by the
amount of overhead charged during the period. The respective well
operating agreements allow the Company, when it is the operator, to
charge a well with a specified overhead rate during the drilling phase
and to also charge a monthly fixed overhead rate for each producing
well. As a result of the Heidelberg acquisition in late 1997 and the
addition of several producing wells, the gross G&A recovered through
these types of charges (listed in the above as "Operators Overhead
Charges") increased from $5.5 million in 1997 to $9.7 million in 1998.
As a result of the resumption in development activity in 1999 as
compared to 1998, this recovery further increased to $10.3 million.
Interest and Financing Expenses
Year Ended December 31,
------------------------------------------------------------------
Amounts in Thousands Except Per
Unit Amounts 1999 1998 1997
------------------------------------------------------------------
Interest expense $15,795 $17,534 $1,111
Non-cash interest expense (834) (627) (91)
------------------------------------------------------------------
Cash interest expense 14,961 16,907 1,020
Interest and other income (1,415) (1,623) (1,123)
------------------------------------------------------------------
Net cash interest expense (income) $13,546 $15,284 $ (103)
------------------------------------------------------------------
Average net cash interest
expense (income) per BOE $ 2.22 $ 2.13 $(0.02)
Average debt outstanding 172,010 205,087 12,700
Average interest rate (1) 8.7% 8.2% 8.0%
------------------------------------------------------------------
(1) Includes commitment fees but excludes amortization of debt issue
costs.
Page 37
<PAGE>
During the first half of 1997, the Company had minimal debt
outstanding as virtually all of the bank debt had been retired during
the fourth quarter of 1996 with proceeds from a public offering of
common stock completed in October 1996. Late in the fourth quarter of
1997, the Company borrowed $202 million of the $240 million of bank
debt outstanding as of December 31, 1997 to fund the Chevron
acquisition. This bank debt remained outstanding for only two months.
On February 26, 1998 this bank debt was repaid with proceeds from a
debt and equity offering, leaving an outstanding bank loan of $40
million for the rest of the first quarter of 1998, plus $125 million of
recently issued 9% Senior Subordinated Notes. This bank debt increased
throughout 1998, from $40 million as of March 31, 1998 to $70 million
as of June 30, to $90 million as of September 30, to $100 million as of
December 31, 1998, or total debt as of December 31, 1998 of $225
million. These transactions resulted in substantially higher interest
expense for 1998 as compared to 1997, on both an absolute and BOE
basis.
In 1999, the Company began the year with $225 million of total debt
and further increased this to $234.6 million by the end of the first
quarter. This debt was reduced by $100 million in April 1999 with the
proceeds from the TPG equity infusion (see "1999 Sale of Equity and
Move of Domicile" above). An additional $17.9 million was borrowed
during the remainder of the second and third quarters to fund
acquisitions, bringing the total bank debt to $27.5 million as of
December 31, 1999, or total outstanding debt of $152.5 million after
inclusion of the $125 million of 9% Senior Subordinated Notes. The net
result was a lower average level of debt in 1999 than in 1998,
resulting in a decrease of 10% in net interest expense during 1999. On
a BOE basis, net cash interest expense increased slightly (4%) between
1998 and 1999 as a result of the overall decline in production.
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") increased between
1997 and 1998 along with the additional capitalized cost and decreased
between 1998 and 1999 as a result of the reduced oil and gas property
basis after the full cost pool writedowns at June 30, 1998 and December
31, 1998 and the increase in reserve quantities during 1999.
Year Ended December 31,
------------------------------------------------------------------
Amounts in Thousands Except Per
Unit Amounts 1999 1998 1997
------------------------------------------------------------------
Depletion and depreciation $24,277 $ 50,820 $31,587
Site restoration provision 384 419 408
Depreciation of other fixed assets 854 995 724
------------------------------------------------------------------
Total amortization $25,515 $ 52,234 $32,719
------------------------------------------------------------------
Average DD&A cost per BOE $ 4.17 $ 7.26 $ 6.42
Writedown of oil and gas
properties $ - $280,000 $ -
------------------------------------------------------------------
Page 38
<PAGE>
Due to changes in oil prices, the Company's proved oil reserves
changed significantly between year-end 1997, 1998 and 1999. The oil
price affects reserve quantities, as a reduced oil price causes wells
to reach the end of their economic life much sooner and also makes
certain proved undeveloped locations uneconomical. Conversely, a
higher oil price extends these economic lives, thus adding to the
reserve quantities. The oil prices used in the December 31, 1997
reserve report were based on a NYMEX oil price of $18.32 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. This price was reduced to $12.00
per Bbl at December 31, 1998 to reflect the current prices at that
time, and increased to a price of $25.60 per Bbl as of December 31,
1999. The Company's average net realized oil prices used in the
December 31, 1997, 1998 and 1999 reserve reports were $14.43, $7.37 and
$21.42 per Bbl, respectively. The change in year-end prices caused a
reduction in reserves quantities solely related to prices of 15.1
million BOE between 1997 and 1998 and an increase in reserves solely
due to prices of 15.8 million BOE between 1998 and 1999. The Company
also lost approximately 9.8 million BOE in 1998 which in part was
related to price, in that the Company postponed or canceled repairs and
upgrades on oil wells resulting in steeper declines, and in part
related to poor performances on three of the Company's gas properties
in Louisiana and an unsuccessful Louisiana development well.
Conversely, the Company added 8.2 million BOE from acquisitions and 5.9
million BOE from other development work in 1999 and had other minor
upward revisions which totaled 153,000 BOE. In summary, the Company's
total proved reserves were 64.9 million BOE as of December 31, 1997,
36.4 million BOE as of December 31, 1998 and 60.2 million BOE as of
December 31, 1999.
These fluctuations in oil prices also significantly impacted oil
reserve values. Under full cost accounting rules, the Company is
required each quarter to perform a ceiling test calculation. In
determining the limitation on property carrying values, Securities and
Exchange Commission accounting rules require the discounting of
estimated future net revenues from its proved reserves at 10% per year
using unescalated current prices ("PV10 Value"). The PV10 Value of the
Company's proved reserves was $361 million as of December 31, 1997,
$115 million as of December 31, 1998 and $463 million as of December
31, 1999. Due to the significant drop in PV10 Value in 1998, the
Company had full cost pool writedowns at June 30, 1998 and December 31,
1998 of $165 million and $115 million, respectively. The change in
reserve quantities between the respective years, coupled with the
writedowns in 1998, which reduced the Company's cost basis by $280
million, caused the DD&A rate per BOE (excluding writedowns) to
increase from $6.42 per BOE for 1997 to $7.26 per BOE in 1998, and to
decrease to $4.17 per BOE in 1999.
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
Page 39
<PAGE>
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.
Income Taxes
Due to a net loss each year for tax purposes, the Company does not
have any current tax provision. As a result of the previously
discussed $280.0 million writedown of oil and natural gas properties
and the resulting net pre-tax loss of $302.8 million for the year ended
December 31, 1998, a deferred income tax provision for 1998 using the
effective tax rate of 37% would have resulted in a $96.4 million net
deferred tax asset. Based upon management's review of the Company's
ability to generate sufficient future taxable income prior to the
expiration of the Company's net loss carryovers, the Company fully
impaired the $96.4 million net deferred tax asset. At December 31,
1999, the Company continues to believe that it is more likely than not
that future taxable income will not be sufficient to realize the
benefit from the Company's deferred tax assets within the expiration
period of the Company's net operating losses. In reaching this
conclusion, the Company estimated its future profitability based on oil
and gas pricing indicative of historic trends and consistent with the
Company's long-term forecasting and anticipated levels of projected
capital spending, a portion of which are intangible drilling costs
which are deducted in the year the costs are incurred. For the year
ended December 31, 1999, the deferred tax provision using the effective
tax rate of 37% and based on net income before tax of $4.6 million
would have resulted in a deferred income tax provision of $1.7 million.
However, the Company utilized a portion of its deferred tax assets and
its corresponding valuation allowance to offset this provision, leaving
a net deferred tax asset as of December 31, 1999 of $95.1 million, all
of which is still fully impaired.
Year Ended December 31,
------------------------------------------------------------------
Amounts in Thousands Except Per
Unit Amounts 1999 1998 1997
------------------------------------------------------------------
Deferred income tax (benefit) $ - $(15,620) $ 8,895
provision (thousands)
Average income tax (benefit)
provision per BOE $ - $( 2.17) $ 1.75
Effective tax rate - 5% 37%
------------------------------------------------------------------
Net operating loss carryforwards $ 139,859 $118,619 $ 47,841
------------------------------------------------------------------
Net deferred tax asset (liability) $ 95,137 $ 96,402 $(15,620)
Valuation allowance (95,137) (96,402) -
------------------------------------------------------------------
Total net deferred tax asset
(liability) $ - $ - $(15,620)
------------------------------------------------------------------
Page 40
<PAGE>
RESULTS OF OPERATIONS
Between 1997 and 1998, production increased and most expenses,
other than interest expense, improved on a BOE basis. Nonetheless, as a
result of the decline in product prices in 1998, net income and cash
flow from operations decreased substantially on both a gross and per
share basis as outlined below. In addition, during 1998, the Company
incurred a $280.0 million non-cash charge to operations to writedown
the carrying value of its oil and natural gas properties as previously
discussed. Between 1998 and 1999, even though production was down,
improved product prices coupled with the reduced DD&A per BOE resulted
in net income for the year as outlined below. Cash flow from
operations was only slightly higher (5%) in 1999 as compared to 1998 as
the improved product prices were almost offset by the decreased
production level. Each of these factors are more fully discussed in
the preceding paragraphs.
Graph depicting the Company's cash flow from operations by quarter,
excluding the change in working capital items (in millions of dollars):
1997 1998 1999
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
14.9 12.0 13.2 16.4 11.5 9.1 6.8 2.8 2.5 6.6 9.5 13.0
Year Ended December 31,
--------------------------------------------------------------------
Amounts in Thousands Except Per
Share Amounts 1999 1998 1997
--------------------------------------------------------------------
Net income (loss) $ 4,614 $(287,145) $14,903
Net income (loss) per common share:
Basic $ 0.12 $ (11.08) $ 0.74
Diluted 0.12 (11.08) 0.70
Cash flow from operations (1) $31,619 $ 30,096 $56,607
--------------------------------------------------------------------
(1) Represents cash flow provided by operations, exclusive of the net
change in non-cash working capital balances.
Page 41
<PAGE>
The following table summarizes the cash flow, DD&A and results of
operations on a BOE basis for the comparative periods. Each of the
individual components are discussed above.
Year Ended December 31,
---------------------------------------------------------------------
Per BOE Data 1999 1998 1997
---------------------------------------------------------------------
Revenue $ 13.34 $ 11.38 $16.75
Production taxes (0.60) (0.56) (0.82)
Lease operating expenses (4.25) (3.49) (3.54)
---------------------------------------------------------------------
Production netback 8.49 7.33 12.39
General and administrative expenses (1.21) (1.02) (1.30)
Net cash interest (expense) income (2.22) (2.13) 0.02
Other 0.11 - -
---------------------------------------------------------------------
Cash flow from operations(1) 5.17 4.18 11.11
DD&A (4.17) (7.26) (6.42)
Deferred income taxes - 2.17 (1.75)
Writedown of oil and natural
gas properties - (38.93) -
Other non-cash items (0.25) (0.09) (0.01)
---------------------------------------------------------------------
Net income (loss) $ 0.75 $(39.93) $ 2.93
---------------------------------------------------------------------
(1) Represents cash flow provided by operations, exclusive of the net
change in non-cash working capital balances.
Market Risk Management
The Company uses fixed and variable rate debt to partially finance
budgeted expenditures. These agreements expose the Company to market
risk related to changes in interest rates. The Company does not hold
or issue derivative financial instruments for trading purposes.
The following table presents the carrying and fair value of the
Company's debt along with average interest rates. Fair values are
calculated as the net present value of the expected cash flows of the
financial instrument.
Expected Maturity Dates
-----------------------------------------------------------------------
Amounts in Thousands 2000- 2003- Fair
2001 2002 2007 2008 Total Value
-----------------------------------------------------------------------
Variable rate debt:
Bank debt $ - $27,500 $ - $ - $ 27,500 $ 27,500
The average interest rate on the bank debt at December 31, 1999 is 7.15%.
Fixed rate debt:
Subordinated debt - - - 125,000 125,000 113,800
The interest rate on the subordinated debt is a fixed rate of 9%.
Page 42
<PAGE>
The Company also enters into various financial contracts to hedge
its exposure to commodity price risk associated with anticipated future
oil and natural gas production. These contracts consist of price
ceilings and floors, no-cost collars and fixed price swaps.
As of December 31, 1998, the Company had zero-cost financial
contracts ("collars") in place that hedged a total of 40 million cubic
feet of natural gas per day ("MMcf/d") through August 1999 and 30
MMcf/d thereafter through December 2000. The first set of contracts
had a weighted average ceiling price of approximately $2.95 per MMBtu
and the second set of contracts had a ceiling price of $2.58 per MMBtu.
Both contracts had a floor price of $1.90 per MMBtu. During the first
half of 1999, the Company collected $603,000 on these contracts, but
during the second half the Company paid out $729,000 related to these
hedges. During the second half of 1999, the Company also retired 6
MMcf/d of the 30 MMcf/d collar at a cost of approximately $672,000.
The net out of pocket cost during 1999 on the natural gas collars was
$798,000, including the cost of the buyouts. The remaining contracts
hedge approximately 90% of the Company's natural gas production, based
upon fourth quarter production levels.
During the fourth quarter of 1998, the Company modified certain of
its oil sales contracts. These contracts, which were generally for a
period of 18 months, provided that approximately 45% of the Company's
oil production at that time had a price floor of between $8.00 and
$10.00 per Bbl which equates to a NYMEX oil price of between $15.00 and
$16.00 per Bbl. As compensation for the price floors, the contracts
provided that the Company's discount to NYMEX increases as oil prices
rise. The incremental funds received by the Company in late 1998 and
early 1999 from the price floors have been approximately equally offset
by the reduced funds during the last half of 1999, as a result of an
additional discount to NYMEX as oil prices rose. The majority of these
types of sale contracts expire in April 2000.
During March and April 1999, the Company entered into two collars
to hedge a portion of its oil production. The first contract was a
fixed price swap for 3,000 Bbls/d for the period of April through
December 1999 at a price of $14.24 per Bbl. The second contract was a
collar to hedge 3,000 Bbls/d for the period of May 1999 through
December 2000 with a floor price of $14.00 per Bbl and a ceiling price
of $18.05 per Bbl. The Company paid approximately $8.6 million on
these contracts during 1999, which lowered the effective net oil price
received by the Company for the year by $1.95 per barrel. The
remaining contract collar hedges just over 20% of the Company's current
oil production based on the fourth quarter production levels.
In the aggregate, the Company paid a net amount of $9.4 million
during 1999 on its commodity hedges. All of the remaining contracts in
effect at December 31, 1999 expire in December 2000. Gain or loss on
these derivative commodity contracts would be offset by a corresponding
gain or loss on the hedged commodity positions. Based on the futures
market prices at December 31, 1999, the Company would expect to pay
approximately $4.5 million on the oil hedge contract and pay
approximately $183,000 on the natural gas hedge contracts. If the
Page 43
<PAGE>
futures market prices were to increase 10% from those in effect at
December 31, 1999, the Company would be required to make additional
cash payments of approximately $2.4 million under the oil contract and
$800,000 under the gas contracts. If the futures market prices were to
decline 10% from those in effect as December 31, 1999, the Company
would reduce the payments due under the natural gas commodity contracts
by $183,000 and reduce the payments due under the oil contracts by $2.4
million.
Year 2000 Issues
Year 2000 issues relate to the ability of computer programs or
equipment to accurately calculate, store or use dates after December
31, 1999. To date in 2000, the Company has not had any significant
problems relating to these issues. The company did not incur any
significant costs relating to the assessment and remediation of year
2000 issues.
Forward-Looking Information
The statements contained in this Annual Report on Form 10-K that
are not historical facts, including, but not limited to, statements
found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as
that term is defined in Section 21E of the Securities and Exchange Act
of 1934, as amended, that involve a number of risks and uncertainties.
Such forward-looking statements may be or may concern, among other
things, capital expenditures, drilling activity, acquisition plans and
proposals and dispositions, development activities, cost savings,
production efforts and volumes, hydrocarbon reserves, hydrocarbon
prices, liquidity, Year 2000 issues, regulatory matters and
competition. Such forward-looking statements generally are accompanied
by words such as "plan," "estimate," "expect," "predict," "anticipate,"
"projected," "should," "assume," "believe" or other words that convey
the uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations,
estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans,
anticipated actions, the timing of such actions and the Company's
financial condition and results of operations. As a consequence,
actual results may differ materially from expectations, estimates or
assumptions expressed in or implied by any forward-looking statements
made by or on behalf of the Company. Among the factors that could
cause actual results to differ materially are: fluctuations of the
prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating
hazards, acquisition risks, requirements for capital, general economic
conditions, competition and government regulations, as well as the
risks and uncertainties discussed in this annual report, including,
without limitation, the portions referenced above, and the
uncertainties set forth from time to time in the Company's other public
reports, filings and public statements.
Page 44
<PAGE>
Independent Auditors' Report
To the Stockholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources
Inc. as of December 31, 1999 and 1998 and the related consolidated
statements of operations, stockholders' equity (deficit) and cash flows
for each of the three years in the period ended December 31, 1999.
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 generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly
in all material respects, the financial position of the Company as of
December 31, 1999 and 1998 and the results of its operations and its
cash flows for each of the three years in the period ended December 31,
1999, in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 22, 2000
Page 45
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEETS
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31,
-------------------
1999 1998
------- -------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents ...................... $ 11,768 $ 2,049
Accrued production receivables ................. 15,836 5,495
Trade and other receivables .................... 2,942 16,390
------- -------
Total current assets ................ 30,546 23,934
------- -------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties ................. 587,412 508,571
Unevaluated oil and natural gas properties...... 41,371 65,645
Less accumulated depletion and depreciation..... (417,828) (393,552)
------- -------
Net property and equipment .............. 210,955 180,664
------- -------
OTHER ASSETS ...................................... 11,065 8,261
------- -------
TOTAL ASSETS ........................... $252,566 $212,859
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities........ $ 18,042 $ 13,570
Oil and gas production payable ................. 7,120 5,118
------- -------
Total current liabilities .............. 25,162 18,688
------- -------
LONG-TERM LIABILITIES
Long-term debt ................................. 152,500 225,000
Provision for site reclamation costs 1,820 1,436
Other .......................................... 656 -
------- -------
Total long-term liabilities............. 154,976 226,436
------- -------
STOCKHOLDERS' EQUITY (DEFICIT)
Preferred stock, $.001 par value,
25,000,000 shares authorized; none
issued and outstanding....................... - -
Common stock, $.001 par value, 100,000,000
shares authorized; 45,718,486 and
26,801,680 shares issued and outstanding
at December 31, 1999 and December 31,
1998, respectively........................... 46 27
Paid-in-capital in excess of par................ 327,829 227,769
Accumulated deficit ............................ (255,447) (260,061)
------- -------
Total stockholders' equity (deficit).... 72,428 (32,265)
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) $252,566 $212,859
======= =======
</TABLE>
See Notes to Consolidated Financial Statements.
Page 46
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF OPERATIONS
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
AMOUNTS IN THOUSANDS EXCEPT PER
SHARE AMOUNTS (U.S. DOLLARS) 1999 1998 1997
------- -------- -------
<S> <C> <C> <C>
REVENUES
Oil, natural gas and related
product sales ................ $81,575 $ 81,883 $85,333
Interest income and other ...... 1,415 1,623 1,123
------- -------- -------
Total revenues ........... 82,990 83,506 86,456
------- -------- -------
EXPENSES
Production ..................... 29,691 29,162 22,218
General and administrative ..... 7,029 6,556 6,182
Interest ....................... 15,795 17,534 1,111
Depletion and depreciation ..... 25,515 52,234 32,719
Franchise taxes ................ 346 785 428
Writedown of oil and natural
gas properties ............... - 280,000 -
------- -------- -------
Total expenses .......... 78,376 386,271 62,658
------- -------- -------
Income (loss) before income taxes ... 4,614 (302,765) 23,798
Income tax benefit (provision) ...... - 15,620 (8,895)
------- -------- -------
NET INCOME (LOSS) ................... $ 4,614 $(287,145) $14,903
======= ======== =======
NET INCOME (LOSS) PER COMMON SHARE
Basic........................... $ 0.12 $ (11.08) $ 0.74
Diluted......................... 0.12 (11.08) 0.70
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING
Basic........................... 39,928 25,926 20,224
Diluted......................... 39,987 25,926 21,445
</TABLE>
See Notes to Consolidated Financial Statements.
Page 47
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1999 1998 1997
------- -------- -------
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss) ............... $ 4,614 $(287,145) $ 14,903
Adjustments needed to reconcile
to net cash flow provided
by operations:
Depletion and depreciation ..... 25,515 52,234 32,719
Writedown of oil and natural
gas properties ............... - 280,000 -
Deferred income taxes .......... - (15,620) 8,895
Other .......................... 1,490 627 90
------- -------- -------
31,619 30,096 56,607
Changes in working capital items
relating to operations:
Accrued production receivables.. (10,341) 3,197 3,214
Trade and other receivables..... 13,448 (1,028) (11,719)
Accounts payable and accrued
liabilities .................. 4,472 (11,046) 13,713
Oil and gas production payable.. 2,002 (934) 502
------- -------- -------
NET CASH FLOW PROVIDED BY OPERATIONS 41,200 20,285 62,317
------- -------- -------
CASH FLOW USED FOR INVESTING
ACTIVITIES:
Oil and natural gas
expenditures ................. (34,479) (88,978) (81,282)
Acquisition of oil and
natural gas properties ....... (20,488) (13,674) (224,145)
Net purchases of other assets... (1,381) (1,145) (2,132)
Cash restricted for future site
reclamation .................. (2,347) - -
Disposition of oil and gas
properties ................... 400 - -
------- -------- -------
NET CASH USED FOR INVESTING ACTIVITIES (58,295) (103,797) (307,559)
------- -------- -------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments ................ (100,000) (200,000) -
Bank borrowings ................ 27,500 60,000 239,900
Issuance of subordinated debt .. - 125,000 -
Net proceeds from issuance
of common stock .............. 100,079 94,657 2,816
Costs of debt financing ........ (765) (3,402) (1,511)
Other .......................... - (20) (90)
------- -------- -------
NET CASH PROVIDED BY FINANCING
ACTIVITIES ....................... 26,814 76,235 241,115
------- -------- -------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS ................... 9,719 (7,277) (4,127)
Cash and cash equivalents at
beginning of year ................ 2,049 9,326 13,453
------- -------- -------
CASH AND CASH EQUIVALENTS AT END OF
YEAR ............................. $ 11,768 $ 2,049 $ 9,326
======= ======== =======
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid during the year
for interest .................... $ 15,805 $ 11,821 $ 447
</TABLE>
See Notes to Consolidated Financial Statements.
Page 48
<PAGE>
<TABLE>
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
PAID-IN RETAINED
COMMON STOCK CAPITAL IN EARNINGS
DOLLAR AMOUNTS IN ($.001 PAR VALUE) EXCESS OF (ACCUMULATED
THOUSANDS OF U.S. DOLLARS Shares Amount PAR DEFICIT) TOTAL
---------- ----- -------- --------- ---------
<S> <C> <C> <C> <C> <C>
BALANCE - JANUARY 1, 1997 20,055,757 $ 20 $130,303 $ 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 20 133,119 27,084 160,223
---------- ----- -------- --------- ---------
Issued pursuant to employee
stock option plan......... 132,256 - 954 - 954
Issued pursuant to employee
stock purchase plan....... 101,561 - 1,139 - 1,139
Conversion of warrants...... 625,000 1 4,624 - 4,625
Public placement of
common stock ............. 5,554,180 6 87,933 - 87,939
Net loss ................... - - - (287,145) (287,145)
---------- ----- -------- --------- ---------
BALANCE - DECEMBER 31, 1998 26,801,680 27 227,769 (260,061) (32,265)
---------- ----- -------- --------- ---------
Issued pursuant to employee
stock purchase plan....... 363,930 - 1,544 - 1,544
Sale of common stock to TPG 18,552,876 19 98,516 - 98,535
Net income ................. - - - 4,614 4,614
---------- ----- -------- --------- ---------
BALANCE - DECEMBER 31, 1999 45,718,486 $ 46 $327,829 $(255,447) $ 72,428
========== ===== ======== ========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
Page 49
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
At a special meeting of the stockholders held on April 20, 1999, the
stockholders approved, among other things, a move of the Company's
corporate domicile from Canada to the United States as a Delaware
Corporation. The move of domicile was completed on April 21, 1999 and
along with the move, the Company's wholly-owned subsidiary, Denbury
Management, Inc. ("DMI"), was merged into the new Delaware parent
company, Denbury Resources Inc. This move of domicile did not have any
effect on the operations and assets of the Company, and as part of the
move and merger, Denbury Resources Inc. expressly assumed any and all
liabilities of its subsidiary, DMI, including the obligation for the 9%
Senior Subordinated Notes due 2008 and the outstanding bank credit
facility. The financial statements and notes herein have been modified
for all periods presented to reflect the capital structure of the
Company after the move of domicile.
The Company operates as one business segment with operating activities
related to exploration, development and production of oil and natural
gas in the U.S. Gulf Coast region, primarily onshore in Louisiana and
Mississippi.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in
accordance with generally accepted accounting principles ("GAAP") in
the United States and include the accounts of the Company and its
subsidiaries, all of which are wholly-owned. Prior to the Company's
move of its corporate domicile from Canada to the United States as a
Delaware corporation, the Company's financial statements were prepared
in accordance with Canadian GAAP rather than United States GAAP. No
adjustments to the financial statements were necessary for the switch
to U.S. GAAP from Canadian GAAP, as there were no differences between
the two accounting methods that impacted the Company's financial
statements for the years presented herein. All material intercompany
balances and transactions have been eliminated.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS. The Company follows the full-cost method of
accounting for oil and natural gas properties. Under this method, all
costs related to acquisitions, exploration and development of oil and
natural gas reserves are capitalized and accumulated in a single cost
center representing the Company's activities undertaken exclusively in
the United States. Such costs include lease acquisition costs,
geological and geophysical expenditures, lease rentals on undeveloped
properties, costs of drilling both productive and non-productive wells
and general and administrative expenses directly related to exploration
and development activities and do not include any costs related to
production, general corporate overhead or similar activities. Proceeds
received from disposals are credited against accumulated costs except
when the sale represents a significant disposal of reserves, in which
case a gain or loss is recognized.
Page 50
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
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 net capitalized costs of oil and gas properties
are limited to the lower of unamortized cost or the cost center
ceiling. The cost center ceiling is defined as the sum of (i) the
present value of estimated future net revenues from proved reserves
(discounted at 10%), based on unescalated year-end oil and natural gas
prices; (ii) plus the cost of properties not being amortized; (iii)
plus the lower of cost or estimated fair value of unproved properties
included in the costs being amortized, if any; (iv) less related income
tax effects.
E) JOINT INTEREST OPERATIONS. Substantially all of the Company's oil
and natural gas exploration and production activities are conducted
jointly with others. These financial statements reflect only the
Company's proportionate interest in such activities and any amounts due
from other partners are included in the trade receivables.
Restricted Cash
At December 31, 1999, the Company had approximately $2.3 million of
restricted cash held in escrow for future site reclamation costs. This
restricted cash is included in Other Assets in the Consolidated Balance
Sheet. The Company had no restricted cash at December 31, 1998.
Net Income (Loss) Per Common Share
Basic net income or loss per common share is computed by dividing the
net income or loss attributable to common stockholders by the weighted
average number of shares of common stock outstanding during the period.
Diluted net income or loss per common share is calculated in the same
manner but also considers the impact to net income and common shares
for the potential dilution from stock options, stock warrants and any
other outstanding convertible securities.
Page 51
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
The following is a reconciliation of the numerator and denominator used
for the computation of basic and diluted net income or loss per common
share.
YEAR ENDED DECEMBER 31,
----------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE DATA 1999 1998 1997
------ -------- ------
Net income (loss)......................... $ 4,614 $(287,145) $14,903
====== ======= ======
Weighted average common shares - basic.... 39,928 25,926 20,224
Effect of diluted securities:
Stock options.......................... 59 - 793
Stock warrants......................... - - 428
------ -------- ------
Weighted average common shares - diluted.. 39,987 25,926 21,445
====== ======= ======
Net income (loss) per common share
Basic.................................. $ 0.12 $ (11.08) $ 0.74
Diluted................................ 0.12 (11.08) 0.70
====== ======= ======
For the year ended December 31, 1999, approximately 1.6 million shares
of common stock under options were excluded from the diluted net income
per share computation as the exercise price exceeded the average market
price of the Company's common stock. Warrants representing 75,000
shares of common stock were also excluded from the 1999 diluted net
income per share computation as the exercise price exceeded the average
market price of the Company's common stock. For the year ended
December 31, 1998, all dilutive securities were excluded from the
calculation of diluted loss per share, as their effect would have been
anti-dilutive.
Statement of Cash Flows
For purposes of the Statement of Cash Flows, cash equivalents include
time deposits, certificates of deposit and all liquid debt instruments
with maturities at the date of purchase of three months or less.
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and
sold. Any amounts due from purchasers of oil and natural gas are
included in accrued production receivables.
The Company follows the "sales method" of accounting for its oil and
natural gas revenue, whereby the Company recognizes sales revenue on
all oil or natural gas sold to its purchasers, regardless of whether
the sales are proportionate to the Company's ownership in the property.
A receivable or liability is recognized only to the extent that the
Company has an imbalance on a specific property greater than the
expected remaining proved reserves. As of December 31, 1999 and 1998,
the Company's aggregate oil and natural gas imbalances were not
material to its consolidated financial statements.
Page 52
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
The Company recognizes revenue and expenses of purchased producing
properties commencing from the closing or agreement date, at which time
the Company also assumes control.
Income Taxes
Income taxes are accounted for using the liability method under which
deferred income taxes are recognized for the tax consequences of
"temporary differences" by applying enacted statutory tax rates
applicable to future years to differences between the financial
statement carrying amounts and the tax basis of existing assets and
liabilities. The effect on deferred taxes for a change in tax rates is
recognized in income in the period that includes the enactment date.
Comprehensive Income
Effective January 1, 1998, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 130, "Reporting Comprehensive
Income." This statement establishes standards for reporting of
comprehensive income and its components in the financial statements.
For the years ended December 31, 1999, 1998 and 1997, there were no
differences between net income (loss) and comprehensive income.
Financial Instruments with Off-Balance Sheet Risk and Concentrations of
Credit Risk
The Company's product price hedging activities are described in Note 6
to the consolidated financial statements. The Company enters into
financial transactions to hedge anticipated future production. Hedge
accounting is utilized when there is a high degree of correlation
between price movements in the derivative and the underlying item
designated as being hedged. The impact of changes in the market value
of the financial transactions, which serve as hedges, is deferred until
the related physical transaction is completed. The changes, when
recognized, are included in oil and gas revenues. If a financial
transaction that has been accounted for as a hedge is closed before the
date of the anticipated future transaction, the accumulated change in
the value of the financial transactions is deferred until the related
physical transaction is completed. In the event it becomes likely that
an anticipated transaction will not occur or that adequate correlation
no longer exists, hedge accounting is terminated and future changes in
the fair value of the derivative are recognized as gains or losses in
the statement of operations. Credit risk relating to these hedges is
minimal because of the credit risk standards required for counter-
parties and monthly settlements. The Company only has entered into
hedging contracts with large and financially strong companies.
The Company's financial instruments that are exposed to concentrations
of credit risk consist primarily of cash equivalents, short-term
investments and trade and accrued production receivables in addition to
the product price hedges discussed above. The Company's cash
equivalents and short-term investments represent high-quality
securities placed with various investment grade institutions. This
investment practice limits the Company's exposure to concentrations of
credit risk. The Company's trade and accrued production receivables
are dispersed among various customers and purchasers; therefore,
concentrations of credit risk are limited.
Page 53
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
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, 1999 and 1998, the carrying value of the Company's
bank debt and most other financial instruments approximates their fair
market value. The Company's bank debt is based on a floating interest
rate and thus adjusts to market as interest rates change. During 1998,
the Company issued $125 million of 9% Senior Subordinated Notes due
2008. As of December 31, 1999 and 1998, these notes had a market value
of approximately $113.8 million and $110.0 million, respectively, based
on quoted market prices. Based on market prices as of December 31,
1999, the Company would expect to pay approximately $4.5 million on its
oil hedge contract and pay approximately $183,000 on its natural
gas hedge contracts (See Note 6). 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.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities."
This statement establishes accounting and reporting standards for
derivative instruments and hedging activities. It requires the
recognition of all derivatives as either assets or liabilities in the
statement of financial position and measurement of these instruments at
fair value. The Company is required to adopt this statement in the
first quarter of 2001. The Company does not expect the adoption of
this statement to have a significant impact on the Company's financial
position or results of operations.
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, 1999 and 1998 and the year
in which they were incurred follows:
Page 54
<PAGE>
<TABLE>
DECEMBER 31, 1999 DECEMBER 31, 1998
------------------------------- -------------------------
Costs Incurred During: Costs Incurred During:
---------------------- ----------------------
1999 1998 1997 Total 1998 1997 Total
----- ----- ------ ------ ------ ------ ------
AMOUNTS IN THOUSANDS
<S> <C> <C> <C> <C> <C> <C> <C>
Property
acquisition costs $1,283 $4,693 $30,566 $36,542 $ 4,693 $48,896 $53,589
Exploration costs 1,427 3,402 - 4,829 8,260 3,796 12,056
----- ----- ------ ------ ------ ------ ------
Total $2,710 $8,095 $30,566 $41,371 $12,953 $52,692 $65,645
===== ===== ====== ====== ====== ====== ======
</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.
1998 Writedown of Oil and Gas Properties Resulting From Full Cost
Ceiling Test
During the first quarter of 1998, the Company excluded the Heidelberg
Field acquired late in 1997 from the full cost ceiling test because the
Company believed, based on its success with similar properties in
Mississippi, that the value of this property was at least equal to its
carrying cost. Had this property been included in the ceiling test
calculation as of March 31, 1998, the Company would have had a
writedown of the property carrying costs of approximately $35 million.
During the second quarter of 1998, oil prices continued to decline,
with a drop of approximately $2.50 in the net realized oil price from
March 31 to June 30, 1998. Due to the continued low oil prices, in
June 1998 the Company announced that it was reducing its drilling
activity and capital expenditure budget on its oil properties,
including Heidelberg Field, until oil product prices recover. As a
result of this curtailment, it was unlikely that the proved reserves
and production from this property would increase as quickly as
originally anticipated, thus causing a decline in the current value of
this property. Therefore, as of June 30, 1998, the Company included
the Heidelberg Field in the full cost pool for its ceiling test, which
coupled with the reduction in oil prices, resulted in a $165 million
writedown of the full cost pool as of that date. This writedown was
computed using June 30, 1998 prices, a drop of approximately $5.92 per
Bbl from the net prices used in the December 31, 1997 reserve report.
As of December 31, 1998, the average net realized oil price had
deteriorated an additional $1.53 per Bbl from the June 30, 1998 prices.
As a result of this further decrease in price, coupled with some
downward revisions in the proven reserves, the Company recognized an
additional ceiling test writedown of $115 million, for a total
writedown for the year ended December 31, 1998 of $280 million.
Capitalized Costs
The Company capitalized general and administrative costs that directly
relate to exploration and development activities of $2.8 million, $2.7
million and $2.2 million for the years ended December 31, 1999, 1998
and 1997, respectively. Amortization per BOE, excluding the full cost
pool writedown, was $4.17, $7.26 and $6.42 for the years ended December
31, 1999, 1998 and 1997, respectively.
Page 55
<PAGE>
NOTE 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31,
---------------------
1999 1998
------- -------
AMOUNTS IN THOUSANDS
Senior bank loan ............... $ 27,500 $100,000
9% Senior Subordinated Notes
due 2008 ..................... 125,000 125,000
------- -------
152,500 225,000
Less portion due within one year - -
------- -------
Total long-term debt....... $152,500 $225,000
======= =======
Senior Bank Loan
The Company has a credit facility with Bank of America, as agent for a
group of eight other banks. The credit facility is a five year
revolving credit facility that matures on December 31, 2002. This
credit facility has several restrictions including, among others: (i) a
prohibition on the payment of dividends, (ii) a requirement for a
minimum equity balance, (iii) a requirement to maintain positive
working capital, as defined, (iv) a minimum interest coverage test and
(v) a prohibition of most debt and corporate guarantees. The borrowing
base under the credit facility is subject to review every six months
and at December 31, 1998 was set at $130 million.
On February 19, 1999, the Company amended its credit facility with Bank
of America, which among other things, modified the debt covenants so
that the Company would be in compliance with the bank loan agreement.
Under this amendment, the borrowing base was reduced to $110 million,
of which $60 million was classified as within their normal credit
guidelines. This amendment also:
* provided certain relief on the minimum equity and interest
coverage tests;
* changed the facility to one secured by substantially all of
the Company's oil and natural gas properties;
* required that as long as the borrowing base is larger than the
normal credit guideline borrowing base (currently $60
million), at least 75% of the funds borrowed must be used for
either qualifying acquisitions or capital expenditures made to
maintain, enhance or develop proved reserves ("Qualified
Purpose"); and
* increased the interest rate to a range from LIBOR plus 1.0% to
LIBOR plus 1.75% (depending on the amounts outstanding) and
LIBOR plus 2.125% on all debt if the outstanding debt exceeds
the borrowing base under normal credit guidelines, currently
set at $60 million.
The Company also made a slight modification to the bank agreement as of
September 30, 1999, which reduced from $25 million to $15 million the
amount that could be borrowed by the Company for expenditures other
than a Qualified Purpose. During 1999, all of the Company's borrowings
were for a Qualified Purpose.
As of December 31, 1999, the Company had $27.5 million outstanding
under the facility, at an interest rate of 7.15%, $1,570,000 of letters
of credit outstanding, a total borrowing base of $110 million and a
conforming borrowing base of $60 million. The next scheduled re-
determination of the
Page 56
<PAGE>
borrowing base will be as of April 1, 2000, based on December 31, 1999
assets and proved reserves.
Subordinated Debt
On February 26, 1998, DMI, a wholly-owned subsidiary of the Company
issued $125 million in aggregate principal amount of 9% Senior
Subordinated Notes due 2008 which require semi-annual interest payments
only until maturity. In April 1999, DMI was merged into Denbury
Resources Inc., which expressly assumed all liabilities of DMI
including the 9% Senior Subordinated Notes (See Note 1 - Organization
and Nature of Operations).These notes contain certain debt covenants,
including covenants that limit (i) indebtedness, (ii) certain
restricted payments including dividends, (iii) sale/leaseback
transactions, (iv) transactions with affiliates, (v) liens, (vi) asset
sales and (vii) mergers and consolidations. The net proceeds to the
Company from the debt offering were approximately $121.8 million,
before offering expenses.
Indebtedness Repayment Schedule
The Company's indebtedness as of December 31, 1999 is repayable as
follows:
AMOUNTS IN THOUSANDS
--------------------------------------
YEAR
2000 .................. $ -
2001 .................. -
2002 .................. 27,500
2003 .................. -
2004 .................. -
Thereafter ............ 125,000
-------
Total indebtedness ... $152,500
=======
NOTE 4. INCOME TAXES
The components of the Company's income tax provision (benefit) is as
follows:
YEAR ENDED DECEMBER 31,
------------------------------
AMOUNTS IN THOUSANDS 1999 1998 1997
------ ------- -------
Deferred
Federal..................... $ - $(15,620) $ 8,589
State....................... - - 306
------ ------- -------
Total income tax provision (benefit) $ - $(15,620) $ 8,895
====== ======= =======
The Company's income tax provision (benefit) varies from the amount
that would result from applying the statutory income tax rate to income
before income taxes as follows:
YEAR ENDED DECEMBER 31,
-------------------------------
AMOUNTS IN THOUSANDS 1999 1998 1997
------ -------- -------
Income tax provision (benefit)
calculated using the
statutory income tax rate ........ $ 1,615 $(105,968) $ 8,329
State taxes, prior period
adjustments and other ............ (350) (6,054) 566
Change in valuation allowance ...... (1,265) 96,402 -
------ -------- -------
Total income tax provision (benefit) $ - $ (15,620) $ 8,895
====== ======== =======
Page 57
<PAGE>
In 1998, a valuation allowance was established to fully impair the
Company's $96.4 million net deferred tax asset balance based upon
management's review of the Company's ability to generate sufficient
future taxable income prior to the expiration of the Company's net
operating loss carryforwards. At December 31, 1999, the Company
continues to believe that it is more likely than not that future
taxable income will not be sufficient to realize the benefit from the
Company's deferred tax assets within the expiration period of the
Company's net operating losses. In reaching this conclusion, the
Company estimated its future profitability based on oil and gas pricing
indicative of historic trends and consistent with the Company's long-
term forecasting and anticipated levels of projected capital spending,
a portion of which are intangible drilling costs which are deducted in
the year the costs are incurred. The Company at December 31, 1999 had
net operating loss carryforwards for U.S. federal income tax purposes
of approximately $139.9 million and approximately $73.0 million for
alternative minimum tax purposes. The net operating losses are
scheduled to expire as follows:
INCOME ALTERNATIVE
AMOUNTS IN THOUSANDS TAX MINIMUM TAX
------------------------------- -----------
YEAR
2004 ..................$ 39 $ -
2005 .................. 11 -
2006 .................. 644 500
2007 .................. 714 99
2008 .................. 5,016 4,888
2009 .................. 3,376 2,868
2010 .................. 3,467 3,420
2011 .................. 5,061 1,115
2012 .................. 29,513 4,125
2013 .................. 70,778 40,244
2014 .................. 21,240 15,774
Deferred income taxes relate to temporary differences based on tax laws
and statutory rates in effect at the December 31, 1999 and 1998 balance
sheet dates. At December 31, 1999 and 1998, all deferred tax assets
and liabilities were noncurrent as follows:
DECEMBER 31,
------------------------
AMOUNTS IN THOUSANDS 1999 1998
------ ------
Deferred tax assets:
Loss carryforwards............. $51,748 $43,587
Basis difference of exploration
and production assets........ 43,883 53,269
Deferred tax liabilities:
Other.......................... (494) (454)
------ ------
Net deferred tax asset.......... 95,137 96,402
Less: Valuation allowance...... (95,137) (96,402)
------ ------
Total net deferred tax asset .. $ - $ -
====== ======
Page 58
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
NOTE 5. STOCKHOLDERS' EQUITY
Authorized
The Company is authorized to issue 100 million shares of Common Stock,
par value $.001 per share, and 25 million shares of Preferred Stock,
par value $.001 per share. The preferred shares may be issued in one
or more series with rights and conditions determined by the board of
directors.
1999 Sale of Stock to the Texas Pacific Group
In April 1999, the stockholders voted to sell 18,552,876 shares of
common stock to an affiliate of the Texas Pacific Group ("TPG") for
$100 million or $5.39 per share. As a result of this transaction,
TPG's ownership of the Company's outstanding common stock increased
from approximately 32% to approximately 60%. The net proceeds from
this sale of common stock of approximately $98.5 million were used to
pay down the Company's revolving credit facility.
1998 Equity Offering
On February 26, 1998, the Company closed on a public offering of
5,240,780 shares of common stock at a price to the public of $16.75 per
share and a net price to the Company of $15.955 per share (the "Equity
Offering"). Concurrently with the Equity Offering, TPG purchased
313,400 shares of common stock from the Company at $15.955 per share,
equal to the price to the public per share less underwriting discounts
and commissions (the "TPG Purchase"). The net proceeds to the Company
from the Equity Offering and TPG Purchase was approximately $88.6
million, before offering expenses.
Warrants
At December 31, 1999, 75,000 warrants were outstanding at an exercise
price of Cdn. $8.40 expiring on May 5, 2000. Each warrant entitles the
holder thereof to purchase one share of common stock at any time prior
to the expiration date.
Stock Option Plan
The Company maintains a Stock Option Plan which authorizes the grant of
options for up to 4,535,000 shares of common stock. Under the terms of
the plan, incentive and non-qualified options may be issued to
officers, key employees and consultants. Options generally become
exercisable over a four year vesting period with the specific terms of
vesting determined by the Board of Directors at the time of grant. The
options expire over terms not to exceed ten years from the date of
grant, ninety days after termination of employment or permanent
disability or one year after the death of the optionee. The options
are granted at the fair market value at the time of grant which is
generally defined as the average closing price of the Company's shares
of common stock for the ten trading days prior to issuance. The plan
is administered by the Stock Option Committee of the Board.
Page 59
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
Following is a summary of stock option activity during the years ended
December 31, 1999, 1998 and 1997:
<TABLE>
YEAR ENDED DECEMBER 31,
1999 1998 1997
---------------------- ----------------------- ----------------------
Weighted Weighted Weighted
Number Average Price Number Average Price Number Average Price
--------- ----- --------- ----- --------- -----
<S> <C> <C> <C> <C> <C> <C>
Outstanding at
beginning of year 1,890,531 $13.04 1,546,256 $11.06 1,053,000 $ 7.63
Granted ........... 1,830,503 4.38 488,559 17.71 797,162 14.13
Exercised ......... - - (132,256) 7.29 (280,656) 6.95
Forfeited ......... (403,650) 9.78 (12,028) 7.15 (23,250) 11.51
--------- ----- --------- ----- --------- -----
Outstanding at
end of year ..... 3,317,384 $ 8.66 1,890,531 $13.04 1,546,256 $11.06
========= ===== ========= ===== ========= =====
Exercisable at
end of year ..... 622,001 $ 9.39 398,474 $ 8.85 391,872 $ 7.57
========= ===== ========= ===== ========= =====
Weighted average fair
value of options granted $ 2.56 $ 7.64 $ 4.02
===== ===== =====
</TABLE>
The Company applies the intrinsic value method in accounting for
options granted under the Stock Option Plan and accordingly no
compensation cost is recognized. Had compensation expense been
recognized based on the fair value of the options on the date they were
granted, the Company's net income (loss) and net income (loss) per
common share would have been reduced (increased) to the following pro
forma amounts:
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
------ -------- ------
NET INCOME (LOSS):
As reported (thousands) ................ $ 4,614 $(287,145) $14,903
Pro forma (thousands) .................. 772 (289,463) 14,130
NET INCOME (LOSS) PER COMMON SHARE:
As reported:
Basic .............................. $ 0.12 $ (11.08) $ 0.74
Diluted ............................ 0.12 (11.08) 0.70
Pro forma:
Basic .............................. $ 0.02 $ (11.16) $ 0.70
Diluted ............................ 0.02 (11.16) 0.66
The Company estimated the fair value of each option grant using the
Black-Scholes option pricing method while using the following
weighted average assumption:
1999 1998 1997
----- ----- -----
Risk-free interest rate 4.7% 6.2% 5.7%
Expected life (in years) 5 years 5 years 3 years
Expected volatility 64.7% 29.6% 39.2%
Dividend yield - - -
Page 60
<PAGE>
Notes to Consolidated Financial Statements
Years Ended December 31, 1999, 1998 and 1997
The following table summarizes information on the Company's stock
options outstanding at December 31, 1999.
<TABLE>
Options Outstanding Options Exercisable
---------------------------------- --------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices at 12/31/99 Life Price at 12/31/99 Price
----------------- --------- --------- ----- ------- -----
<S> <C> <C> <C> <C> <C>
$ 3.77 - $ 5.50 1,657,019 8.9 years $ 4.25 - $ -
5.51 - 8.00 319,740 5.0 years 6.56 308,134 6.53
8.01 - 11.50 221,725 6.4 years 9.92 220,843 9.93
11.51 - 14.50 628,125 7.0 years 13.38 16,693 13.44
14.51 - 22.25 490,775 7.9 years 18.32 76,331 18.46
--------- --------- ----- ------- -----
$ 3.77 - $22.25 3,317,384 7.9 years $ 8.66 622,001 $ 9.39
--------- --------- ----- ------- -----
</TABLE>
Stock Purchase Plan
The Company maintains a Stock Purchase Plan which authorizes the sale
of up to 750,000 shares of common stock to all full-time employees.
Under the plan, the employees may contribute up to 10% of their base
salary and the Company matches 75% of the employee contribution. The
combined funds are used to purchase previously unissued Common Stock of
the Company based on its current market value at the end of each
quarter. The Company recognizes compensation expense for the 75%
Company matching portion, which totaled $501,000, $648,000 and $383,000
for the years ended December 31, 1999, 1998 and 1997, respectively.
This plan is administered by the Stock Purchase Plan Committee of the
Board.
401(k) Plan
The Company offers a 401(k) Plan to which employees may contribute tax
deferred earnings subject to Internal Revenue Service limitations. The
Company matches 50% of employee contributions up to an employee
contribution of 6% of their salary. This Company match becomes vested
over a six year period. During 1999 and 1998, the Company made
matching contributions of $239,000 and $217,000, respectively, to the
401(k) Plan.
NOTE 6. PRODUCT PRICE HEDGING CONTRACTS
The Company enters into various financial contracts to hedge its
exposure to commodity price risk associated with anticipated future oil
and natural gas production. These contracts consist of price ceilings
and floors, no-cost collars and fixed price swaps.
As of December 31, 1998, the Company had zero-cost financial contracts
("collars") in place that hedged a total of 40 million cubic feet of
natural gas per day ("MMcf/d") through August 1999 and 30 MMcf/d
thereafter through December 2000. The first set of contracts had a
weighted average ceiling price of approximately $2.95 per MMBtu and the
second set of contracts had a ceiling price of $2.58 per MMBtu. Both
contracts had a floor price of $1.90 per MMBtu. During the first
half of 1999, the Company collected $603,000 on these contracts, but
Page 61
<PAGE>
during the second half the Company paid out $729,000 related to these
hedges. During the second half of 1999, the Company also retired 6
MMcf/d of the 30 MMcf/d collar at a cost of approximately $672,000.
The net out of pocket cost during 1999 on the natural gas collars was
$798,000, including the cost of the buyouts. The remaining contracts
hedge approximately 90% of the Company's natural gas production, based
upon fourth quarter production levels.
During the fourth quarter of 1998, the Company modified certain of its
oil sales contracts. These contracts, which were generally for a
period of eighteen months, provided that approximately 45% of the
Company's oil production at that time had a price floor of between
$8.00 and $10.00 per Bbl, which equates to a NYMEX oil price of between
$15.00 and $16.00 per Bbl. As compensation for the price floors, the
contracts provided that the Company's discount to NYMEX increases as
oil prices rise. The incremental funds received by the Company in late
1998 and early 1999 from the price floors has been approximately
equally offset by the reduced funds during the last half of 1999 as a
result of an additional discount to NYMEX as oil prices rose. The
majority of these types of sale contracts expire in April 2000.
During March and April 1999, the Company entered into two collars to
hedge a portion of its oil production. The first contract was a fixed
price swap for 3,000 Bbls/d for the period of April through December,
1999 at a price of $14.24 per Bbl. The second contract was a collar to
hedge 3,000 Bbls/d for the period of May, 1999 through December, 2000
with a floor price of $14.00 per Bbl and a ceiling price of $18.05 per
Bbl. The Company paid approximately $8.6 million on these contracts
during 1999, which lowered the effective net oil price received by the
Company for the year by $1.95 per barrel. The remaining contract
collar hedges just over 20% of the Company's current oil production
based on the fourth quarter production levels.
In the aggregate, the Company paid a net amount of $9.4 million during
1999 on its commodity hedges. All of the remaining contracts in effect
at December 31, 1999 expire in December 2000. Gain or loss on these
derivative commodity contracts would be offset by a corresponding gain
or loss on the hedged commodity positions. Based on the futures market
prices at December 31, 1999, the Company would expect to pay
approximately $4.5 million on the oil hedge contract and pay
approximately $183,000 on the natural gas hedge contracts. If the
futures market prices were to increase 10% from those in effect at
December 31, 1999, the Company would be required to make additional
cash payments of approximately $2.4 million under the oil contract and
$800,000 under the gas contracts. If the futures market prices were to
decline 10% from those in effect at December 31, 1999, the Company
would reduce the payments due under the oil contract by $2.4 million
and reduce the payments due under the natural gas commodity contracts
by $183,000.
Page 62
<PAGE>
NOTE 7. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1999, long-term commitments
for these items require the following future minimum rental payments:
AMOUNTS IN THOUSANDS
2000 ............... $ 1,275
2001 ............... 1,261
2002 ............... 1,243
2003 ............... 1,123
2004 ............... 1,175
Thereafter ......... 5,747
------
Total lease commitments $11,824
======
The Company is subject to various possible contingencies which arise
primarily from interpretation of federal and state laws and regulations
affecting the oil and natural gas industry. Such contingencies include
differing interpretations as to the prices at which oil and natural gas
sales may be made, the prices at which royalty owners may be paid for
production from their leases, environmental issues and other matters.
Although management believes it has complied with the various laws and
regulations, administrative rulings and interpretations thereof,
adjustments could be required as new interpretations and regulations
are issued. In addition, production rates, marketing and environmental
matters are subject to regulation by various federal and state
agencies.
In June of 1997, a well blow-out occurred at the Lake Chicot Field, for
which the Company is operator, in St. Martin Parish, Louisiana in which
four individuals that were employees of other third party entities were
killed, none of whom were employees or contractors of the Company. In
connection with this blow-out, a lawsuit is pending, the matter of
Mallard Bay Drilling L.L.C., as owner and operator of Mr. Beldon,
otherwise designated Mallard Rig 52, Case No. 97-1223 in the United
States District Court, Lafayette - Opelousas Division, Louisiana
alleging various defective and dangerous conditions, violation of
certain rules and regulations and acts of negligence. The Company
believes that all litigation to which it is a party is covered by
insurance and none of such legal proceedings can be reasonably expected
to have a material adverse effect on the Company's financial condition,
results of operations or cash flows.
The Company and its subsidiaries are involved in various other
lawsuits, claims and regulatory proceedings incidental to their
businesses. In the opinion of management, the outcome of such matters
will not have a material adverse effect on the Company's business,
consolidated financial position, results of operations or cash flows.
NOTE 8. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under
short-term contracts at the current area market price. The loss of any
purchaser would not be expected to have a material adverse effect upon
operations. For the year ended December 31, 1999, the Company sold 10%
or more of its net production of oil and natural gas to the following
purchasers: Genesis Crude Oil 23%, Southland Corporation 21%, Hunt
Refining 12% and Dynegy Crude Gathering 12%.
Page 63
<PAGE>
Costs Incurred
The following table summarizes costs incurred and capitalized in oil
and natural gas property acquisition, exploration and development
activities. Property acquisition costs are those costs incurred to
purchase, lease, or otherwise acquire property, including both
undeveloped leasehold and the purchase of reserves in place.
Exploration costs include costs of identifying areas that may warrant
examination and in examining specific areas that are considered to have
prospects containing oil and natural gas reserves, including costs of
drilling exploratory wells, geological and geophysical costs and
carrying costs on undeveloped properties. Development costs are
incurred to obtain access to proved reserves, including the cost of
drilling development wells, and to provide facilities for extracting,
treating, gathering and storing the oil and natural gas.
Costs incurred in oil and natural gas activities for the years ended
December 31, 1999, 1998 and 1997 are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------
AMOUNTS IN THOUSANDS 1999 1998 1997
------ ------- -------
Property acquisitions:
Proved ............ $20,488 $ 13,674 $149,145
Unevaluated ....... 1,283 6,604 77,664
Exploration ........ 7,672 12,222 20,734
Development ........ 25,524 70,152 57,884
------ ------- -------
Total costs incurred $54,967 $102,652 $305,427
====== ======= =======
Property Acquisitions
During 1999, the Company completed acquisitions totaling $20.5 million,
primarily comprised of a $12.3 million acquisition of a tertiary
recovery oil field (Little Creek) in southern Mississippi and a $4.9
million acquisition of the King Bee Field, also in Mississippi.
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 and was accounted
for under purchase accounting. The results of operations from this
purchase were consolidated effective December 31, 1997. Pro forma
results of operations of the Company as if the Chevron Acquisition had
occurred at the beginning of 1997 are as follows:
YEAR ENDED DECEMBER 31,
1997
-----------
(AMOUNTS IN THOUSANDS EXCEPT (UNAUDITED)
PER SHARE AMOUNTS)
Revenues ...................... $104,695
Net income .................... 9,966
Net income per common share:
Basic ........................ 0.49
Diluted ...................... 0.46
In computing the pro forma results, depreciation, depletion and
amortization expense was computed using the units of production method,
and an adjustment was made to interest expense reflecting the bank debt
that was required to fund the acquisition. The pro forma results do
not reflect any increases in general and administrative expense.
Page 64
<PAGE>
NOTE 9. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31,
1999, 1998 and 1997 were prepared by Netherland & Sewell, independent
petroleum engineers located in Dallas, Texas. The reserves were
prepared in accordance with guidelines established by the Securities
and Exchange Commission and, accordingly, were based on existing
economic and operating conditions. Oil and natural gas prices in
effect as of the reserve report date were used without any escalation
except in those instances where the sale is covered by contract, in
which case the applicable contract prices including fixed and
determinable escalations were used for the duration of the contract,
and thereafter the last contract price was used (See "Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves" below for a discussion
of the effect of the different prices on reserve quantities and
values.) Operating costs, production and ad valorem taxes and future
development costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and
timing of development expenditures. The following reserve data
represents estimates only and should not be construed as being exact.
Moreover, the present values should not be construed as the current
market value of the Company's oil and natural gas reserves or the costs
that would be incurred to obtain equivalent reserves. All of the
reserves are located in the United States.
<TABLE>
Estimated Quantities of Reserves
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1999 1998 1997
---------------- ----------------- -----------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR......... 28,250 48,803 52,018 77,191 15,052 74,102
Revisions of previous estimates..... 83 418 (7,267) (15,369) 3,398 1,098
Revisions due to price changes...... 15,884 75 (14,921) (990) (1,525) (317)
Extensions, discoveries and other
additions........................ 4,383 8,910 678 1,951 6,373 11,205
Production ......................... (4,413) (10,201) (4,965) (13,361) (2,884) (13,257)
Acquisition of minerals in place.... 7,722 2,693 2,998 21 31,604 4,360
Sales of minerals in place.......... (77) (260) (291) (640) - -
------ ------ ------ ------ ------ ------
BALANCE AT END OF YEAR .............. 51,832 50,438 28,250 48,803 52,018 77,191
====== ====== ====== ====== ====== ======
PROVED DEVELOPED RESERVES
Balance at beginning of year........ 20,357 44,995 31,355 69,805 13,371 58,634
Balance at end of year.............. 32,767 41,635 20,357 44,995 31,355 69,805
</TABLE>
Page 65
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
("Standardized Measure") does not purport to present the fair market
value of the Company's oil and natural gas properties. An estimate of
such value should consider, among other factors, anticipated future
prices of oil and natural gas, the probability of recoveries in excess
of existing proved reserves, the value of probable reserves and acreage
prospects, and perhaps different discount rates. It should be noted
that estimates of reserve quantities, especially from new discoveries,
are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices, adjusted for fixed and determinable
escalations, to the estimated future production of year-end proved
reserves. The product prices used in calculating these reserves have
varied widely during the three year period. These prices have a
significant impact on both the quantities and value of the proven
reserves as the reduced oil price causes wells to reach the end of
their economic life much sooner and also makes certain proved
undeveloped locations uneconomical, both of which reduce the reserves.
The following representative oil and natural gas year-end prices were
used in the Standardized Measure. These prices were adjusted by field
to arrive at the appropriate corporate net price.
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------ ------- -------
Oil (NYMEX).......... $25.60 $12.00 $18.32
Gas (NYMEX Henry Hub) 2.12 2.15 2.58
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.
DECEMBER 31,
-------------------------------
AMOUNTS IN THOUSANDS 1999 1998 1997
--------- -------- --------
Future cash inflows ..................... $1,222,590 $ 317,148 $ 957,718
Future production costs ................. (370,385) (112,521) (285,968)
Future development costs ................ (69,642) (23,887) (68,287)
--------- -------- --------
Future net cash flows before taxes ..... 782,563 180,740 603,463
10% annual discount for estimated timing
of cash flows ......................... (319,693) (65,721) (242,134)
--------- -------- --------
Discounted future net cash flows
before taxes .......................... 462,870 115,019 361,329
Discounted future income taxes .......... (14,496) - (26,021)
--------- -------- --------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS ........................ $ 448,374 $ 115,019 $ 335,308
========= ======== ========
Page 66
<PAGE>
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:
YEAR ENDED DECEMBER 31,
-------------------------------
AMOUNTS IN THOUSANDS 1999 1998 1997
--------- -------- --------
BEGINNING OF YEAR ...................... $115,019 $335,308 $241,872
Sales of oil and natural gas produced,
net of production costs .............. (51,884) (52,721) (63,115)
Net changes in sales prices ............ 253,244 (198,836) (132,905)
Extensions and discoveries, less
applicable future development
and production costs .................. 48,918 6,605 75,632
Previously estimated development costs
incurred ............................. 8,402 30,742 10,088
Revisions of previous estimates,
including revised estimates of
development costs, reserves and rates
of production ....................... 6,433 (76,532) 264
Accretion of discount .................. 11,502 33,531 24,187
Purchase of minerals in place .......... 71,631 12,869 131,080
Sales of minerals in place ............. (395) (1,968) -
Net change in income taxes ............. (14,496) 26,021 48,205
--------- -------- --------
END OF YEAR ............................ $448,374 $115,019 $335,308
======== ======== ========
Unaudited Quarterly Information
The following table presents unaudited summary financial information on
a quarterly basis for 1999 and 1998:
------------------------------------------------------------------------
IN THOUSANDS EXCEPT PER
SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
------------------------------------------------------------------------
1999
Revenues.................... $15,064 $18,228 $22,378 $27,320
Expenses.................... 18,092 17,736 19,974 22,574
Net income (loss)........... (3,028) 492 2,404 4,746
Net income (loss) per share:
Basic...................... (0.11) 0.01 0.05 0.10
Diluted.................... (0.11) 0.01 0.05 0.10
Cash flow from operations(a) 2,497 6,598 9,547 12,977
Cash flow used for
investing activities...... 6,917 13,232 21,841 16,305
Cash flow provided by
financing activities...... 9,155 7,441 10,179 39
1998
Revenues.................... $25,555 $22,883 $19,599 $15,469
Expenses.................... 26,608 195,067 22,022 142,574
Net loss.................... (680) (121,939)(b) (2,423) (162,103)(b)
Net loss per share:
Basic...................... (0.03) (4.57) (0.09) (6.05)
Diluted.................... (0.03) (4.57) (0.09) (6.05)
Cash flow from operations(a) 11,455 9,052 6,817 2,772
Cash flow used for
investing activities...... 26,689 50,120 17,781 9,207
Cash flow provided by
financing activities...... 14,826 30,906 20,501 10,002
(a) Exclusive of the net change in non-cash working capital balances.
(b) Includes full cost ceiling writedown of oil and natural gas
properties of $165 million and $115 million for the quarters ended
June 30, 1998 and December 31, 1998, respectively.
Page 67
<PAGE>
Common Stock Trading Summary
The following table summarizes the high and low last reported sales
prices on days in which there were trades of the Company's common stock
on the New York Stock Exchange ("NYSE"), and on The Toronto Stock
Exchange ("TSE") (as reported by such exchange) for each quarterly
period for the last two fiscal years. The trades on the NYSE are
reported in U.S. dollars and the TSE trades are reported in Canadian
dollars.
As of February 1, 2000, to the best of the Company's knowledge, the
common stock was held of record by approximately 1,300 holders, of
which approximately 300 were U.S. residents holding approximately 80%
of the outstanding common stock of the Company.
The Company has never paid any dividends on its common stock and
currently does not anticipate paying any dividends in the foreseeable
future. The company is restricted from declaring or paying any cash
dividends on its common stock under its bank loan agreement.
NYSE (U.S. $) TSE (CDN $)
----------------------------------------------------------------------
HIGH LOW HIGH LOW
----------------------------------------------------------------------
1999
First quarter................. $ 6.69 $ 3.81 $ 10.00 $ 5.50
Second quarter................ 5.00 3.38 7.45 5.00
Third quarter................. 5.44 4.00 7.45 5.90
Fourth quarter................ 5.31 3.69 7.50 5.25
----------------------------------------------------------------------
1999 annual.................. $ 6.69 $ 3.38 $ 10.00 $ 5.00
----------------------------------------------------------------------
1998
First quarter................. $ 20.63 $ 16.13 $ 29.00 $23.00
Second quarter................ 17.75 12.75 25.00 18.50
Third quarter................. 13.50 6.00 19.90 8.75
Fourth quarter................ 8.50 3.50 13.10 5.40
----------------------------------------------------------------------
1998 annual.................. $ 20.63 $ 3.50 $ 29.00 $ 5.40
----------------------------------------------------------------------
Page 68
EXHIBIT 21
LIST OF SUBSIDIARIES
JURISDICTION OF
NAME OF SUBSIDIARY INCORPORATION STATUS
------------------ --------------- ---------------------------
Tallahatchie State of Texas Wholly owned subsidiary of
Resources, Inc. Denbury Resources Inc. - dormant
Denbury Marine, State of Wholly owned subsidiary of
L.L.C. Louisiana Denbury Resources Inc. - marine
company
Denbury Energy State of Texas Wholly owned subsidiary of
Services, Inc. Denbury Resources Inc. - marketing
company
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
Denbury Resources Inc.
We consent to the incorporation by reference in Registration Statement
Nos. 333-1006, 333-27995, 333-55999 and 333-70485 of Denbury Resources
Inc. on Forms S-8 of our report dated February 22, 2000, appearing in
this Annual Report on Form 10-K of Denbury Resources Inc. for the year
ended December 31, 1999.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 17, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM THE DENBURY RESOURCES INC. DECEMBER 31, 1999
FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 11,768
<SECURITIES> 0
<RECEIVABLES> 18,778
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 30,546
<PP&E> 628,783
<DEPRECIATION> 417,828
<TOTAL-ASSETS> 252,566
<CURRENT-LIABILITIES> 25,162
<BONDS> 152,500
0
0
<COMMON> 46
<OTHER-SE> 72,382
<TOTAL-LIABILITY-AND-EQUITY> 252,566
<SALES> 81,575
<TOTAL-REVENUES> 82,990
<CGS> 0
<TOTAL-COSTS> 62,581
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 15,795
<INCOME-PRETAX> 4,614
<INCOME-TAX> 0
<INCOME-CONTINUING> 4,614
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,614
<EPS-BASIC> .12
<EPS-DILUTED> .12
</TABLE>
