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Filed Pursuant to Rule 424(b)(1)
Registration Number 333-43207
PROSPECTUS
$125,000,000
DMI LOGO
Denbury Management, Inc.
9% SENIOR SUBORDINATED NOTES DUE 2008
Fully and Unconditionally Guaranteed on a Senior Subordinated Basis by
Denbury Resources Inc.
------------------------
Interest payable March 1 and September 1
------------------------
Interest on the 9% Senior Subordinated Notes Due 2008 (the "Notes") of Denbury
Management, Inc. ("DMI") will be payable semi-annually on March 1 and September
1 of each year, commencing September 1, 1998. The Notes are redeemable at the
option of DMI, in whole or in part, on or after March 1, 2003, at the redemption
prices set forth herein, together with accrued and unpaid interest, if any, to
the date of redemption. In addition, at any time prior to March 1, 2001, DMI may
redeem in the aggregate up to 35% of the original principal amount of the Notes
with the proceeds of one or more Stock Offerings (as defined herein), at 109% of
their principal amount, plus accrued interest. Upon a Change of Control (as
defined herein), each holder of the Notes may require DMI to purchase all or a
portion of such holder's Notes at 101% of the aggregate principal amount
thereof, together with accrued and unpaid interest, if any, to the date of
purchase. See "Description of the Notes."
Concurrently with the offering made hereby (the "Debt Offering"), Denbury
Resources Inc., DMI's parent company ("DRI"), is offering 4,557,200 of its
Common Shares (the "Equity Offering" and, together with the Debt Offering, the
"Offerings") pursuant to a simultaneous underwritten public offering. In
addition, in connection with the Equity Offering, entities affiliated with the
Texas Pacific Group, DRI's largest shareholder, will purchase from DRI 313,400
Common Shares (the "TPG Purchase"). The closing of the Debt Offering is
conditioned upon the consummation of the Equity Offering and the TPG Purchase.
The Notes will be general unsecured obligations of DMI, subordinated in right of
payment to all existing and future Senior Indebtedness (as defined herein) of
DMI, but senior in right of payment to all existing and future subordinated
indebtedness of DMI. As of September 30, 1997, after giving pro forma effect to
the Transactions (as defined herein), DMI and its subsidiaries would have had
$23.1 million of Senior Indebtedness outstanding under the Credit Facility (as
defined herein) and $141.9 million available under the Credit Facility which,
when borrowed, will constitute Senior Indebtedness. The Notes will be fully and
unconditionally guaranteed on a senior subordinated basis by DRI.
------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 13 FOR A DISCUSSION OF INFORMATION THAT
SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS.
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
------------------------
PRICE 99.932% AND ACCRUED INTEREST
------------------------
<TABLE>
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UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC(1) COMMISSIONS(2) COMPANY(1)(3)
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Per Note....................................... 99.932% 2.500% 97.432%
Total.......................................... $124,915,000 $3,122,875 $121,792,125
</TABLE>
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(1) Plus accrued interest from February 26, 1998, if any.
(2) DMI has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriters."
(3) Before deducting expenses, estimated at $600,000.
------------------------
The Notes are offered, subject to prior sale, when, as and if accepted by
the Underwriters named herein and subject to approval of certain legal matters
by Cravath, Swaine & Moore, counsel for the Underwriters. It is expected that
delivery of the Notes will be made on or about February 26, 1998 at the office
of Morgan Stanley & Co. Incorporated, New York, N.Y., against payment therefor
in immediately available funds.
------------------------
MORGAN STANLEY DEAN WITTER NATIONSBANC MONTGOMERY
SECURITIES LLC
February 20, 1998
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CORE OPERATING AREAS
---------------------
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE NOTES.
SPECIFICALLY, THE UNDERWRITERS MAY OVER-ALLOT IN CONNECTION WITH THIS OFFERING
AND MAY BID FOR AND PURCHASE THE NOTES IN THE OPEN MARKET. FOR A DESCRIPTION OF
THESE ACTIVITIES, SEE "UNDERWRITERS."
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IT IS EXPECTED THAT DELIVERY OF THE NOTES WILL BE MADE AGAINST PAYMENT
THEREFOR ON OR ABOUT THE DATE SPECIFIED IN THE LAST PARAGRAPH OF THE COVER PAGE
OF THIS PROSPECTUS, WHICH IS THE FOURTH BUSINESS DAY FOLLOWING THE DATE HEREOF
(SUCH SETTLEMENT CYCLE BEING HEREIN REFERRED TO AS "T+4"). PURCHASERS OF NOTES
SHOULD NOTE THAT TRADING OF THE NOTES ON THE DATE HEREOF MAY BE AFFECTED BY THE
T+4 SETTLEMENT. SEE "UNDERWRITING."
NO DEALER, SALESMAN, OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT
BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE
UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED BY THIS PROSPECTUS
BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT
AUTHORIZED, OR IN WHICH THE PERSON MAKING THE OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO SO OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY DISTRIBUTION OF
SECURITIES MADE HEREUNDER OR THEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE
AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE
THE DATE HEREOF OR THEREOF OR THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS
IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF.
---------------------
TABLE OF CONTENTS
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PAGE
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Information Incorporated by
Reference........................... 3
Prospectus Summary.................... 5
Risk Factors.......................... 13
Forward-Looking Statements............ 19
Equity Offering....................... 19
Use of Proceeds....................... 20
Capitalization........................ 21
Unaudited Pro Forma Consolidated
Financial Information............... 22
Selected Consolidated Financial
Data................................ 27
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 28
Business and Properties............... 37
Management............................ 53
Principal Shareholders................ 56
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Interests of Management in Certain
Transactions........................ 58
Description of Certain Indebtedness... 59
Description of the Notes.............. 61
Certain U.S. Federal Income Tax
Considerations...................... 93
Service and Enforcement of Legal
Process............................. 95
Underwriters.......................... 96
Legal Matters......................... 97
Experts............................... 97
Available Information................. 98
Glossary.............................. 99
Index to Consolidated Financial
Statements.......................... F-1
Summary Reserve Report................ A-1
</TABLE>
INFORMATION INCORPORATED BY REFERENCE
The following documents of the Company which have been previously filed
with the Securities and Exchange Commission (the "Commission") are incorporated
in this Prospectus: (i) Annual Report on Form 10-K for the year ended December
31, 1996; (ii) Quarterly Reports on Form 10-Q for the quarters ended March 31,
1997, June 30, 1997 and September 30, 1997; (iii) proxy statement dated May 21,
1997; (iv) reports on Form 8-K dated September 12, 1997, December 8, 1997,
December 16, 1997, and January 20, 1998.
All documents filed by the Company pursuant to Section 13(a), 13(c), 14 and
15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"),
subsequent to the date of this Prospectus and prior to the termination of the
offering of securities to be made hereunder shall be deemed to be incorporated
herein by reference and made a part hereof from the date of filing of such
documents.
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Any statement contained herein or in a document incorporated or deemed to
be incorporated by reference herein shall be deemed to be modified or superseded
for purposes of this Prospectus to the extent that a statement contained herein,
therein or in any other subsequently filed document that also is or is deemed to
be incorporated by reference herein modifies or supersedes such statement. Any
statement so modified or superseded shall not be deemed, except as so modified
or superseded, to constitute a part of this Prospectus.
Any person receiving a copy of this Prospectus may obtain from the Company
without charge a copy of any and all documents or part thereof incorporated
herein by reference (other than exhibits and schedules to such documents unless
such exhibits or schedules are specifically incorporated by reference into the
information the Prospectus incorporates), upon written or oral request. Requests
should be directed to Phil Rykhoek, Chief Financial Officer and Corporate
Secretary, Denbury Resources Inc., 17304 Preston Road, Suite 200, Dallas, Texas,
75252, telephone: (972) 673-2000.
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PROSPECTUS SUMMARY
The following summary is qualified in its entirety by reference to, and
should be read in conjunction with, the more detailed information and
Consolidated Financial Statements included elsewhere in this Prospectus. All
dollar amounts in this Prospectus, unless otherwise indicated, are expressed in
United States dollars and all financial data is presented in accordance with
Canadian generally accepted accounting principles. The December 31, 1997
estimated proved reserve data included throughout this Prospectus have been
prepared by Netherland, Sewell & Associates, Inc. ("Netherland & Sewell"),
independent petroleum engineers. Unless the context otherwise requires, the
terms "Denbury" and the "Company" refer to Denbury Resources Inc., a Canadian
corporation, and its wholly owned subsidiaries, the term "DRI" refers to Denbury
Resources Inc. only, the term "DMI" refers to the wholly owned subsidiary of
DRI, Denbury Management, Inc., a Texas corporation. The term "Transactions"
refers collectively to (i) the Chevron Acquisition (as defined herein) and (ii)
the Offerings and the TPG Purchase and the application of the estimated net
proceeds therefrom. Certain information contained in this summary and elsewhere
in this Prospectus, including information with respect to the Company's plans
and strategy for its business, are forward-looking statements. Prospective
investors should carefully consider the information set forth under "Risk
Factors" for a discussion of important factors that could cause actual results
to differ materially from the forward-looking statements contained in this
Prospectus. Certain oil and gas industry terms used herein are defined in the
Glossary included elsewhere in this Prospectus.
THE COMPANY
OVERVIEW
Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. The Company believes the Gulf Coast
represents one of the most attractive regions in North America given the
region's prolific production history, complex geology (with multiple producing
horizons) and the opportunities that have been created by advanced technologies
such as 3-D seismic and various drilling, completion and recovery techniques. As
of December 31, 1997, the Company had proved reserves of 52.0 MMBbls and 77.2
Bcf or 64.9 MMBOE, including 27.6 MMBOE attributable to the Chevron Acquisition.
At such date, the PV10 Value of these reserves was $361.3 million, of which
$276.5 million was attributable to proved developed reserves. Denbury operates
wells comprising approximately 83% of its PV10 Value. The eight largest fields
in which the Company has an interest constitute approximately 82% of its
estimated proved reserves and, within these eight fields, Denbury owns an
average working interest of 91%.
Over the last four years, the Company has achieved rapid growth in proved
reserves, production and cash flow by concentrating on the acquisition of
properties which it believes have significant upside potential and through the
efficient development, enhancement and operation of its properties. For the
four-year period ended December 31, 1997, the Company increased its proved
reserves at a compound annual growth rate of 83%, from 5.8 MMBOE to 64.9 MMBOE.
Over the four-year period ended December 31, 1996, the Company also increased
its average net daily production at a compound annual growth rate of 90%, from
1,193 BOE/d to 8,167 BOE/d, with a further increase to 14,195 BOE/d for the
third quarter of 1997. For the same four-year period, EBITDA increased at a
compound annual growth rate of 126%, from $3.0 million to $34.9 million. EBITDA
for the twelve months ended September 30, 1997 was $51.9 million.
Since 1993, when the Company began to focus its operations exclusively in
the United States, through December 31, 1995, the Company spent a total of $43.4
million on acquisitions. In May 1996, the Company acquired properties in its
core areas of Mississippi and Louisiana from Amerada Hess Corporation ("Amerada
Hess") for approximately $37.2 million (the "Hess Acquisition"). As of June 30,
1996, these acquired properties were producing approximately 2,945 BOE/d and had
proved reserves of approximately 5.9 MMBOE. Since that date, the Company's
extensive development and exploitation on these properties has resulted in an
82% increase in their production to 5,373 BOE/d for the third quarter of 1997
and a 141% increase in their proved reserves to 14.2 MMBOE as of December 31,
1997.
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On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, which is adjacent to the Company's other primary oil properties in
Mississippi, from Chevron U.S.A. Inc. ("Chevron") for approximately $202.0
million (the "Chevron Acquisition"). These properties are located approximately
nine miles from the Eucutta Field, the property with the highest PV10 Value of
those acquired by the Company in the Hess Acquisition. The estimated proved
reserves as of December 31, 1997 for the Chevron Acquisition properties are
approximately 27.6 MMBOE (43% of the Company's total proved reserves at December
31,1997), with average net daily production of approximately 2,940 BOE/d for the
third quarter of 1997. As a result of the significant amount of future
development and exploitation to be performed on these properties and the
increase in future reserves and production that the Company expects to result
from such development and exploitation, the Company has attributed approximately
$75.0 million of the purchase price to unevaluated properties. The Company
believes that the properties acquired in the Chevron Acquisition provide
exploitation opportunities similar to those of the Mississippi properties
acquired in the Hess Acquisition. The Company's estimated 1998 development
budget for the Heidelberg Field is approximately $30.0 million. See
"-- Acquisition of Chevron Properties."
BUSINESS STRATEGY
The Company seeks to: (i) achieve attractive returns on capital through
prudent acquisitions, development and exploratory drilling and efficient
operations; (ii) maintain a conservative balance sheet to preserve maximum
financial and operational flexibility; and (iii) create strong employee
incentives through equity ownership. The Company believes that its growth to
date in proved reserves, production and cash flow is a direct result of its
adherence to the following fundamental principles which are at the core of the
Company's long-term growth strategy:
REGIONAL FOCUS. The Company intends to continue the regional focus of its
operations. By focusing its efforts in the Gulf Coast region, primarily
Louisiana and Mississippi, the Company has been able to accumulate substantial
geological and reservoir data and operating experience which it believes
provides it with significant competitive advantages. For example, the Company
believes it is better able to identify, evaluate and negotiate potential
acquisitions, and develop and operate its properties in an efficient and low-
cost manner. The Company believes the Gulf Coast represents one of the most
attractive regions in North America given the region's prolific production
history, complex geology (with multiple producing horizons) and the
opportunities that have been created by advanced technologies such as 3-D
seismic and various drilling, completion and recovery techniques. Moreover,
because of the region's proximity to major pipeline networks serving important
northeastern U.S. markets, the Company typically realizes natural gas prices in
excess of those realized in many other producing regions.
DISCIPLINED ACQUISITION STRATEGY. The Company intends to continue to
acquire properties where it believes significant additional value can be
created. Such properties are typically characterized by: (i) long production
histories; (ii) complex geological formations with multiple producing horizons
and substantial exploitation potential; (iii) a history of limited operational
focus and capital investment, often due to their relatively small size and
limited strategic importance to the previous owner; and (iv) the potential for
the Company to gain control of operations. The Company believes that due to
continuing rationalization of properties, primarily by major integrated and
independent energy companies, future acquisition opportunities should continue
to be available. In addition, the Company seeks to maintain a well-balanced
portfolio of oil and natural gas development, exploitation and exploration
projects in order to minimize the overall risk profile of its investment
opportunities while still providing significant upside potential. The recent
Hess and Chevron Acquisitions are examples of the types of opportunities the
Company seeks.
OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company intends to
continue to acquire working interest positions that give it operational control
or that the Company believes may lead to operational control. As the operator of
properties comprising approximately 83% of its total PV10 Value, the Company
believes it is better able to manage and monitor production and more effectively
control expenses, the allocation of capital and the timing of field development.
Once a property is acquired, the Company employs its technical and operational
expertise to fully evaluate a field's future potential. If favorable, it will
consolidate its working interest positions, primarily through negotiated
transactions, which tend to be attractively priced compared to
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acquisitions available in competitive situations. The consolidation of ownership
allows the Company to: (i) enhance the effectiveness of its technical staff by
concentrating on relatively few wells; (ii) increase production while adding
virtually no additional personnel; and (iii) increase ownership in a property so
that the potential benefits of value enhancement activities justify the
allocation of Company resources.
EXPLOITATION OF PROPERTIES. The Company intends to maximize the value of
its properties through a combination of increasing production, increasing
recoverable reserves or reducing operating costs. During 1997, the Company's
primary methodology for achieving these objectives was the use of horizontal
drilling, which it also intends to emphasize in 1998. Horizontal drilling has
historically produced oil at faster rates and with lower operating costs on a
BOE basis than traditional vertical drilling. The Company also utilizes a
variety of other techniques to maximize property values, including: (i)
undertaking surface improvements such as rationalizing, upgrading or redesigning
production facilities; (ii) making downhole improvements such as resizing
downhole pumps or reperforating existing production zones; (iii) reworking
existing wells into new production zones with additional potential; and (iv)
utilizing exploratory drilling, which is frequently based on various advanced
technologies such as 3-D seismic.
EXPERIENCED AND INCENTIVIZED PERSONNEL. The Company intends to maintain a
highly competitive team of experienced and technically proficient employees and
motivate them through a positive work environment and stock ownership in the
Company. The Company's 29 geological and engineering professionals have an
average of over 15 years of experience in the Gulf Coast region. The Company
believes that employee ownership, which is encouraged through the Company's
stock option and stock purchase plans, is essential for attracting, retaining
and motivating quality personnel. As of January 1, 1998, approximately 86% of
the Company's employees were participating in the Company's stock purchase plan.
The Company believes that all employees are important to the success of the
Company and as such grants bonuses and stock options to both management and
employees on a basis roughly proportional to salaries.
ACQUISITION OF CHEVRON PROPERTIES
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202.0
million. The Chevron Acquisition represents the largest acquisition by the
Company to date. The Heidelberg Field is adjacent to the Company's other primary
oil properties in Mississippi and includes 122 producing wells, 96 of which the
Company will operate. The Company purchased an average working interest of 94%
and an average net revenue interest of 81% in these 96 wells, which wells
account for approximately 99% of the field's average net daily production. The
average net daily production from these properties during the third quarter of
1997 was approximately 2,840 Bbls/d and 600 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75 million of the purchase price to unevaluated
properties.
The Company has identified several potential development projects during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 15 wells and recompleting 30
wells in new zones. In addition, the Company has identified over 40 potential
drilling locations in addition to other potential secondary and tertiary
recovery projects. Horizontal wells drilled by the Company in 1997 at nearby
Davis, Quitman and Eucutta Fields improved daily production rates significantly
as compared to vertical wells drilled in the same fields. Consequently, the
Company anticipates that 30 of the 40 proposed future wells in the Heidelberg
Field will be horizontal wells. The Company's total 1998 development budget for
the Heidelberg Field is approximately $30.0 million.
TPG PURCHASE
In December 1995, the Texas Pacific Group initially invested in the Company
through a $40.0 million private placement of securities followed by a $9.6
million purchase of Common Shares in October 1996. TPG
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currently owns approximately 40% of the outstanding Common Shares. In connection
with the Offerings, TPG is purchasing an additional 313,400 Common Shares (the
"TPG Purchase"). See "Interests of Management in Certain Transactions." After
giving effect to the Equity Offering and the TPG Purchase, TPG will own
approximately 34% of the outstanding Common Shares.
TPG was founded by David Bonderman, James G. Coulter and William S. Price
III in 1993 to pursue private and public investment opportunities. The
principals of TPG operate limited partnerships with committed capital of over
$3.2 billion. TPG has several investments in its portfolio, including America
West Airlines, Beringer Wine Estates, Belden & Blake Corporation, Continental
Airlines, Del Monte Foods, Ducati Motor, Favorite Brands International, J. Crew
Group Inc., Paradyne, St. Joe Communications and Virgin Cinemas.
THE DEBT OFFERING
Issuer..................... Denbury Management, Inc.
Guarantors................. Denbury Resources Inc. and, under certain
circumstances, certain subsidiaries of DMI.
Securities Offered......... $125,000,000 aggregate principal amount of 9%
Senior Subordinated Notes Due 2008.
Maturity Date.............. March 1, 2008.
Interest Rate and Payment
Dates.................... The Notes will bear interest at a rate of 9% per
annum. Interest on the Notes will accrue from the
date of issuance thereof and will be payable
semi-annually on March 1 and September 1 of each
year, commencing September 1, 1998.
Optional Redemption........ Except as set forth below, the Notes will not be
redeemable at the option of DMI prior to March 1,
2003. Thereafter, the Notes will be redeemable at
the option of DMI, in whole or in part, at the
redemption prices set forth herein, together with
accrued and unpaid interest, if any, to the date of
redemption. If at any time or from time to time
before March 1, 2001, DRI consummates a Stock
Offering following which there is a Public Market
(as defined herein), DMI may, at its option, use
all or a portion of the proceeds therefrom to
redeem up to 35% of the original principal amount
of the Notes at a redemption price equal to 109% of
the aggregate principal amount thereof, together
with accrued and unpaid interest, if any, to the
date of redemption; provided, however, that (i) at
least $81.0 million in aggregate principal amount
of Notes remains outstanding immediately after each
such redemption or such redemption retires the
Notes in their entirety and (ii) such redemption
occurs within 60 days following the closing of such
Stock Offering. See "Description of the
Notes -- Optional Redemption."
Repurchase Obligation upon
Change of Control........ Upon the occurrence of a Change of Control, each
holder of Notes will have the right to require DMI
to purchase all or a portion of such holder's Notes
at a price equal to 101% of the aggregate principal
amount thereof, together with accrued and unpaid
interest to the date of purchase. See "Risk
Factors -- Risks Relating to a Change of Control"
and "Description of the Notes -- Certain
Covenants -- Change of Control."
Ranking.................... The Notes will be unsecured, general obligations of
DMI subordinated in right of payment to all
existing and future Senior Indebtedness of DMI. The
Notes will rank pari passu in right of payment with
any future senior
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subordinated indebtedness of DMI and will be senior
in right of payment to all existing and future
subordinated indebtedness of DMI. As of September
30, 1997, after giving pro forma effect to the
Transactions, DMI would have had approximately
$23.1 million of outstanding Senior Indebtedness
and no outstanding subordinated indebtedness. The
Company may incur additional indebtedness under the
Credit Facility after the Offerings, and such
indebtedness will constitute Senior Indebtedness.
See "Risk Factors -- Subordination of the Notes and
Guaranties" and "Description of the
Notes -- Ranking."
Guaranties................. The Notes will be fully and unconditionally
guaranteed on a senior subordinated basis by DRI,
of which DMI is a direct wholly owned subsidiary.
The DRI Guaranty (as defined herein) will be a
general, unsecured obligation of DRI, subordinated
in right of payment to all existing and future
Senior Indebtedness of DRI. As of September 30,
1997, after giving pro forma effect to the
Transactions, DRI would have had $23.1 million of
Senior Indebtedness outstanding, all of which would
have represented its guarantee of Senior
Indebtedness of DMI under the Credit Facility. In
addition, in certain circumstances, the Notes will
in the future be fully and unconditionally
guaranteed on a senior subordinated basis by
certain subsidiaries of DMI. See "Risk Factors --
Subordination of the Notes and Guaranties,"
"Description of the Notes -- Ranking" and
"-- Future Subsidiary Guarantors."
Certain Covenants.......... The indenture pursuant to which the Notes will be
issued (the "Indenture") will contain certain
covenants for the benefit of the holders,
including, among others, covenants limiting the
incurrence of additional indebtedness, the payment
of dividends, the redemption of capital stock, the
making of certain investments, the incurrence of
dividend and other payment restrictions affecting
subsidiaries, the issuance of capital stock of
subsidiaries, asset sales, the creation of liens,
certain sale and leaseback transactions,
transactions with affiliates and certain mergers
and consolidations. However, these limitations will
be subject to a number of important qualifications
and exceptions. See "Description of the
Notes -- Certain Covenants."
Use of Proceeds............ The net proceeds from the Debt Offering, together
with the net proceeds from the Equity Offering and
the TPG Purchase, will be used to reduce the
Company's outstanding indebtedness under the Credit
Facility, incurred primarily in connection with the
Chevron Acquisition. Following such repayment, the
Company will continue to have borrowing
availability under the Credit Facility to fund
future acquisitions, development activities and
working capital. See "Use of Proceeds."
Concurrent Equity
Offering................. Concurrently with the Debt Offering, DRI is
offering 4,557,200 (5,240,780 if the underwriters'
over-allotment option is exercised in full) of its
Common Shares, no par value (the "Common Shares"),
by a separate prospectus. The closing of the Debt
Offering is conditioned on the concurrent closing
of the Equity Offering and the TPG Purchase;
however, the closing of the Equity Offering is not
conditioned on the closing of the Debt Offering.
RISK FACTORS
Prior to making an investment decision, prospective investors should
consider carefully, together with other information contained in this
Prospectus, the risk factors discussed under the caption "Risk Factors" herein.
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SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA
The summary historical consolidated financial data of the Company set forth
below as of and for the years ended December 31, 1994, 1995 and 1996 have been
derived from the audited consolidated financial statements of the Company. The
summary historical consolidated financial data for the nine-month periods ended
September 30, 1996 and 1997, and as of September 30, 1997, have been derived
from unaudited consolidated financial statements of the Company which, in
management's opinion include all adjustments (consisting of only normal
recurring adjustments) necessary to present fairly the results for such periods.
The operating results for such periods are not necessarily indicative of the
operating results to be expected for a full fiscal year. The summary unaudited
pro forma consolidated financial data for the Company set forth below have been
derived from the Pro Forma Financial Statements (as defined herein) included
elsewhere in this Prospectus. The summary historical and pro forma consolidated
financial data are qualified in their entirety by, and should be read in
conjunction with, "Unaudited Pro Forma Consolidated Financial Information,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Company's consolidated financial statements included
elsewhere in this Prospectus (the "Consolidated Financial Statements").
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NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
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PRO PRO
FORMA FORMA
1994 1995 1996 1996(a) 1996 1997 1997(a)
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(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
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INCOME STATEMENT DATA:
Revenue:
Oil, natural gas and related
product sales............... $12,692 $20,032 $52,880 $ 76,542 $34,709 $60,083 $ 74,117
Interest income............... 23 77 769 769 425 986 986
------- ------- ------- -------- ------- ------- --------
Total revenues........... 12,715 20,109 53,649 77,311 35,134 61,069 75,103
------- ------- ------- -------- ------- ------- --------
Expenses:
Production.................... 4,309 6,789 13,495 20,145 9,197 15,737 20,974
General and administrative.... 1,105 1,832 4,267 4,954 2,825 4,535 5,049
Interest...................... 1,146 2,085 1,993 13,809 1,530 387 9,193
Imputed preferred dividends... -- -- 1,281 1,281 1,153 -- --
Loss on early extinguishment
of debt..................... -- 200 440 440 440 -- --
Depletion and depreciation.... 4,209 8,022 17,904 24,601 12,557 23,224 27,166
Franchise taxes............... 65 100 213 213 160 308 308
------- ------- ------- -------- ------- ------- --------
Total expenses........... 10,834 19,028 39,593 65,443 27,862 44,191 62,690
------- ------- ------- -------- ------- ------- --------
Income before income taxes...... 1,881 1,081 14,056 11,868 7,272 16,878 12,413
Provision for federal income
taxes......................... (718) (367) (5,312) (4,502) (2,932) (6,245) (4,593)
------- ------- ------- -------- ------- ------- --------
Net income...................... $ 1,163 $ 714 $ 8,744 $ 7,366 $ 4,340 $10,633 $ 7,820
======= ======= ======= ======== ======= ======= ========
Net income per common share
Primary....................... $ 0.19 $ 0.10 $ 0.67 $ 0.41 $ 0.37 $ 0.53 $ 0.31
Fully diluted................. 0.19 0.10 0.62 0.40 0.36 0.50 0.31
Weighted average common shares
outstanding................... 6,240 6,870 13,104 17,975 11,616 20,175 25,046
OTHER FINANCIAL DATA:
Operating cash flow(b).......... $ 6,185 $ 9,394 $34,140 $ 38,649 $21,767 $40,166 $ 39,643
Capital expenditures............ 16,903 28,524 86,857 288,857 73,320 70,773 272,773
EBITDA(c)....................... 7,213 11,311 34,905 51,230 22,527 39,503 47,786
SELECTED RATIOS:
Ratio of earnings to fixed
charges(d).................... 2.6x 1.5x 4.4x 1.7x 3.1x 34.9x 2.3x
Ratio of EBITDA to interest
expense....................... 6.3 5.4 17.5 3.7 14.7 102.1 5.2
Ratio of long-term debt to
EBITDA........................ 2.3 0.3 0.1 2.5 1.6(e) 0.4(e) 2.3(e)
</TABLE>
10
<PAGE> 11
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30,
1997
AS OF DECEMBER 31, -------------------
---------------------------- PRO
1994 1995 1996 ACTUAL FORMA(a)
------- ------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)......................... $(1,620) $ 6,862 $ 12,482 $ 2,899 $ 2,899
Total assets...................................... 48,964 77,641 166,505 210,424 415,634
Long-term debt, net of current maturities......... 16,536 3,474 125 20,005 148,105
Convertible preferred stock....................... -- 15,000 -- -- --
Shareholders' equity.............................. 25,962 53,501 142,504 155,558 232,668
</TABLE>
- ---------------
(a) Gives effect to the Transactions as if the Transactions had been consummated
as of the beginning of the period presented. See "Unaudited Pro Forma
Consolidated Financial Information."
(b) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
(c) EBITDA represents earnings before interest income, interest expense, income
taxes, depletion and depreciation, imputed preferred dividends and losses on
early extinguishment of debt. The Company has included information
concerning EBITDA because it believes that EBITDA is used by certain
investors as one measure of an issuer's historical ability to service its
debt. EBITDA is not a measurement determined in accordance with generally
accepted accounting principles and should not be considered in isolation or
as a substitute for measures of performance prepared in accordance with
generally accepted accounting principles.
(d) For purposes of determining the ratio of earnings to fixed charges, earnings
are defined as earnings from continuing operations before income taxes, plus
fixed charges. Fixed charges consist of interest expense, amortization of
debt expense, and imputed preferred stock dividends.
(e) EBITDA used to calculate the ratio of long-term debt to EBITDA for these
periods has been annualized.
11
<PAGE> 12
SUMMARY OIL AND NATURAL GAS RESERVE DATA
The following table summarizes the estimates of the Company's net proved
oil and natural gas reserves as of the dates indicated and the present value
attributable to the reserves at such dates. The proved reserve and present value
data as of December 31, 1995, 1996 and 1997 have been prepared by Netherland &
Sewell, independent petroleum engineers. A summary of the Netherland & Sewell
report as of December 31, 1997 is included as Annex A to this Prospectus. See
"Risk Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves,"
"Business and Properties -- Oil and Natural Gas Operations," and Note 11 to the
Consolidated Financial Statements.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------
1995 1996 1997
------- -------- --------
<S> <C> <C> <C>
PROVED RESERVES:
Oil (MBbls)............................................... 6,292 15,052 52,018
Natural Gas (MMcf)........................................ 48,116 74,102 77,191
Oil Equivalent (MBOE)..................................... 14,311 27,403 64,883
Proved developed as a percent of total proved reserves.... 78% 84% 66%
PRESENT VALUES:
PV10 Value (before income taxes, in thousands)............ $96,965 $316,098(d) $361,329(e)
Standardized measure of discounted estimated future net
cash flow after net
income taxes (in thousands)............................. 81,164 241,872 336,755
REPRESENTATIVE OIL AND GAS PRICES:(a)
West Texas Intermediate (per Bbl)......................... $ 18.00 $ 23.39 $ 16.18
NYMEX Henry Hub (per MMBtu)............................... 2.24 3.90 2.58
OTHER RESERVE DATA:
Reserve replacement percent(b)............................ 300% 500% 844%
Reserve to production ratio (years)(c).................... 9.3 9.2 10.9(f)
</TABLE>
- ---------------
(a) The oil prices as of each respective year-end were based on West Texas
Intermediate ("WTI") posted prices per barrel and NYMEX Henry Hub ("NYMEX")
prices per MMBtu, with these representative prices adjusted by field to
arrive at the appropriate corporate net price.
(b) Equals current period reserve additions through acquisition of reserves,
extensions and discoveries, and revisions of prior estimates divided by the
production for such period.
(c) Calculated by dividing year-end proved reserves by such year's annual
production.
(d) For comparative purposes, the Company also prepared a reserve report as of
December 31, 1996 using a 1996 WTI price of $21.00 per Bbl and a NYMEX price
of $2.40 per MMBtu, with these prices also adjusted by field. The PV10 Value
in this report was $213.7 million with 27.0 MMBOE of proved reserves. For
the nine months ended September 30, 1997, the average WTI price was
approximately $18.90 per Bbl and the average NYMEX price was approximately
$2.39 per MMBtu.
(e) For comparative purposes, the Company also prepared a reserve report as of
December 31, 1997 using the prices used in the December 31, 1996 reserve
report. The PV10 Value in this report was $633.4 million with 67.8 MMBOE of
proved reserves. Of this PV10 Value, $206.7 million was attributable to the
Chevron Acquisition, as opposed to its PV10 Value of $109.4 million using
December 31, 1997 prices.
(f) Calculated by dividing year-end proved reserves by the pro forma annualized
production for the nine months ended September 30, 1997.
SUMMARY OPERATING DATA
The following table sets forth summary data with respect to the production
and sales of oil and natural gas by the Company for the periods indicated.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------- -----------------------------
PRO FORMA PRO FORMA
1994 1995 1996 1996(A) 1996 1997 1997(A)
------ ------- ------- --------- ------- ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
AVERAGE NET DAILY PRODUCTION VOLUMES:
Oil (Bbls)................................ 1,340 1,995 4,099 7,520 3,529 7,615 10,522
Natural gas (Mcf)......................... 9,113 13,271 24,406 25,076 23,867 34,061 34,648
Oil equivalent (BOE) ..................... 2,859 4,207 8,167 11,699 7,507 13,292 16,297
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)............................. $13.84 $ 14.90 $ 18.98 $ 18.75 $ 18.05 $ 17.53 $ 17.45
Natural gas (per Mcf)..................... 1.78 1.90 2.73 2.72 2.64 2.54 2.54
PER BOE DATA:
Revenue................................... $12.17 $ 13.05 $ 17.69 $ 17.88 $ 16.87 $ 16.56 $ 16.65
Production expenses....................... (4.13) (4.42) (4.51) (4.70) (4.47) (4.34) (4.71)
------ ------- ------- ------- ------- ------- -------
Production netback........................ 8.04 8.63 13.18 13.18 12.40 12.22 11.94
General and administrative................ (1.12) (1.25) (1.50) (1.21) (1.45) (1.33) (1.20)
Interest, net............................. (0.99) (1.26) (0.26) (2.94) (0.37) 0.18 (1.83)
------ ------- ------- ------- ------- ------- -------
Operating cash flow(b).................... $ 5.93 $ 6.12 $ 11.42 $ 9.03 $ 10.58 $ 11.07 $ 8.91
====== ======= ======= ======= ======= ======= =======
</TABLE>
- ---------------
(a) Adjusted to give effect to the Transactions as if the Transactions had been
completed as of the beginning of the periods presented.
(b) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
12
<PAGE> 13
RISK FACTORS
Prospective purchasers of the securities offered hereby should carefully
consider the following factors in addition to the other information in this
Prospectus. See "Forward-Looking Statements."
SUBSTANTIAL CAPITAL REQUIREMENTS
In the future, the Company will require additional funds to develop,
maintain and acquire additional interests in existing or newly acquired
properties. During the last three years, the Company's total capital
expenditures, including acquisitions, have averaged significantly more than its
cash flow from operations. The Company made capital expenditures of $28.5
million, $86.9 million and $272.8 million in the years ended December 31, 1995
and 1996, and the nine-month period ended September 30, 1997 (including the pro
forma effect of the Chevron Acquisition), respectively. Historically, the
Company has funded these expenditures principally through internally-generated
cash flows, bank debt and the issuance of equity. The Company intends to use the
net proceeds from the Offerings and the TPG Purchase to substantially reduce its
outstanding bank debt. As of September 30, 1997, after giving pro forma effect
to the Transactions, the Company would have had $141.9 million ($123.9 million
as of December 31, 1997) available under its Credit Facility. See "Use of
Proceeds." The borrowing base on the Credit Facility will be redetermined semi-
annually by the lenders thereunder in their sole discretion and there can be no
assurance that the borrowing base will be maintained at its present level. If
the Company's borrowing base under the Credit Facility is decreased, the
Company's ability to obtain the funds necessary to carry out its business
strategy may be limited. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Restated Credit Facility" and
"Description of Certain Indebtedness."
Although the Company carefully monitors its capital requirements and plans
its expenditures accordingly, and believes that it will be able to meet all of
its obligations in the future, there can be no assurance that additional capital
will always be available to the Company in the future or that it will be
available on terms that are acceptable to the Company. Numerous factors affect
the cost and availability of capital, including market conditions, the Company's
results of operations and the rate of the Company's drilling successes. Should
outside capital resources be limited, the rate of the Company's growth would
substantially decline, and there can also be no assurance that the Company would
be able to continue to increase its oil and natural gas production or reserves.
PRICE FLUCTUATIONS AND MARKETS
The Company's revenue, profitability and future rate of growth are
dependent upon the price of, and demand for, oil, natural gas and natural gas
liquids. Historically, the markets for oil and natural gas have been volatile
and are likely to continue to be volatile in the future. The prices for oil and
natural gas are subject to wide fluctuations in response to relatively minor
changes in the supply of and demand for oil and natural gas, market uncertainty
and a variety of additional factors that are beyond the control of the Company.
These factors include the level of consumer product demand, weather conditions,
domestic and foreign governmental relations, governmental regulations and taxes,
the price and availability of alternative fuels, political conditions in the
Middle East and other petroleum producing areas, the foreign supply of oil and
natural gas, the price of foreign imports and overall economic conditions. These
factors and the volatility of the energy markets make it extremely difficult to
predict future oil and natural gas price movements with any certainty. Declines
in oil and natural gas prices would not only reduce revenue, but could reduce
the amount of oil and natural gas that can be produced economically by the
Company and, as a result, could have a material adverse effect on the Company's
financial condition, results of operations and reserves. In an effort to
minimize the effect of price volatility, the Company has from time to time
entered into hedging arrangements. The Company currently does not have any
financial hedging contracts in place, although it may enter into such contracts
in the future.
The availability of a ready market for the Company's oil and natural gas
production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to, and the capacity
of, oil and natural gas gathering systems, pipelines or trucking and terminal
facilities. Wells may be temporarily shut-in for lack of a market, or due to the
inadequacy or unavailability of pipeline or
13
<PAGE> 14
gathering system capacity. If any of these market factors were to dramatically
change, the impact on the Company's financial condition would be substantial.
ACQUISITION RISKS
The Company's rapid growth in recent years has been attributable in
significant part to acquisitions of producing properties. After the consummation
of the Offerings, the Company expects to continue to evaluate and, where
appropriate, pursue acquisition opportunities. There can be no assurance that
suitable acquisition opportunities will be identified in the future, or that
they will be integrated successfully into the Company's operations or be
successful in achieving desired profitability objectives. In addition, the
Company competes against other companies for acquisitions, and there can be no
assurance that the Company will be successful in the acquisition of any material
property interests.
The successful acquisition of producing properties requires an assessment
of recoverable reserves, exploration potential, future oil and natural gas
prices, operating costs, potential environmental and other liabilities and other
factors beyond the Company's control. In connection with such an assessment, the
Company performs a review of the subject properties that it believes to be
generally consistent with industry practices. Nonetheless, the resulting
assessments are necessarily inexact and their accuracy inherently uncertain, and
such a review may not accurately assess a property's value or reveal all
existing or potential problems, nor will it necessarily permit a buyer to become
sufficiently familiar with the property to fully assess its merits and
deficiencies. Inspections may not always be performed on every platform or well,
and structural and environmental problems are not necessarily observable even
when an inspection is undertaken.
Additionally, significant acquisitions can change the nature of the
operations and business of the Company depending upon the character of the
acquired properties, which may have substantially different operating and
geological characteristics or geographic location than existing properties.
While it is the Company's current intention to continue to concentrate on
acquiring producing properties with development and exploration potential
located in the Gulf Coast region, there can be no assurance that the Company
will not pursue acquisitions or properties located in other geographic regions.
To the extent that such acquired properties are substantially different than the
Company's Gulf Coast properties, the Company's ability to efficiently realize
the economic benefits of such transactions may be limited.
DRILLING AND OPERATING RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be discovered. There can be no assurance
that new wells drilled by the Company will be productive or that the Company
will recover all or any portion of its investment in such wells. Drilling for
oil and natural gas may involve unprofitable efforts, not only from dry wells
but also from wells that are productive but do not produce sufficient net
revenues to return a profit after deducting drilling, operating and other costs.
The cost of drilling, completing and operating wells is often uncertain. The
Company's drilling operations may be curtailed, delayed or canceled as a result
of numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.
The Company's operations are subject to all of the risks normally incident
to the operation and development of oil and natural gas properties and the
drilling of oil and natural gas wells, including encountering unexpected
formations or pressures, blow-outs, the release of contaminants into the
environment, cratering and fires, all of which could result in personal
injuries, loss of life, pollution damage, damage to property of the Company and
others, including the inability to control such risk when wells are being
drilled by third party contractors and the imposition of fines and penalties
pursuant to environmental legislation. See "-- Governmental and Environmental
Regulation" and "Business and Properties -- Legal Proceedings." The Company is
not fully insured against all of these risks, nor are all such risks insurable.
Although the Company maintains liability insurance in an amount which it
considers adequate, the nature of these risks is such that liabilities could
exceed policy limits, or, as in the case of environmental fines and penalties,
be uninsurable, in which event the Company could incur significant costs that
could have a material adverse effect upon its
14
<PAGE> 15
financial condition. The Company believes that it has proper procedures in place
and that its operating staff carries out their work in a manner designed to
mitigate these risks. There can be no assurance, however, that such procedures
will be effective in deterring these costs.
The Company has focused its oil and natural gas operations in certain key
areas and currently receives approximately 80% of its production from 11 fields.
Any interruption of operations in these key areas could materially adversely
affect the profitability of the Company. In the majority of the Company's
Mississippi fields, significant amounts of saltwater are produced which require
disposal. Currently, the Company is able to dispose of such saltwater
economically, but should it be unable to do so in the future, production from
these fields would become uneconomical.
NEED TO REPLACE RESERVES
The Company's future success depends on its ability to find, develop or
acquire additional oil and natural gas reserves that are recoverable on an
attractive economic basis. Unless the Company successfully replaces the reserves
that it produces (through development, exploration or acquisitions), the
Company's proved reserves will decline. Furthermore, approximately 21% of the
Company's proved developed reserves at December 31, 1997 are located in the
lower Gulf Coast geosyncline in southern Louisiana, which is characterized by
relatively rapid decline rates. Approximately 60% of the Company's total proved
reserves at December 31, 1997 were either proved undeveloped or proved developed
non-producing. Recovery of such reserves will require significant capital
expenditures and successful drilling operations. There can be no assurance that
the Company will continue to be successful in its effort to develop or replace
its proved reserves on terms economically beneficial to the Company, if at all.
UNCERTAINTY OF ESTIMATES OF OIL AND NATURAL GAS RESERVES
Estimates of the Company's proved developed oil and natural gas reserves
and future net revenues therefrom appearing elsewhere herein are based on
reserve reports prepared by independent petroleum engineers. There are numerous
uncertainties inherent in estimating the quantity of proved reserves, including
many factors which are beyond the Company's control. The estimates contained in
this Prospectus are based on several assumptions, all of which are speculative
to a certain degree. Actual future production, revenues, taxes, operating
expenses, development expenditures and quantities of recoverable oil and natural
gas reserves could vary substantially from those assumed in the estimates and
any significant variance in these assumptions could materially affect the
estimated quantity of reserves. The estimation of reserves requires substantial
judgment on the part of the petroleum engineers, resulting in imprecise
determinations, particularly with respect to new discoveries. Different reserve
engineers may make different estimates of reserve quantities and revenues
attributable thereto based on the same data. The accuracy of any reserve
estimate depends on the quality of available data, as well as engineering and
geological interpretation and judgment. The Company's reserves are primarily
water-drive reservoirs which can increase the uncertainty of the estimates that
have been prepared. Results of drilling, testing and production or price changes
subsequent to the date of the estimate may result in revisions to such
estimates. The estimates of future net revenues reflect oil and natural gas
prices as of the date of estimation, without escalation. There can be no
assurance, however, that such prices will be realized or that the estimated
production volumes will be produced during the periods indicated. Future
performance that deviates significantly from that found in the reserve reports
could have a material adverse effect on the Company.
EFFECTS OF LEVERAGE AND RESTRICTIVE DEBT COVENANTS
As of September 30, 1997, after giving pro forma effect to the
Transactions, the Company would have had total consolidated indebtedness of
approximately $148.1 million and a debt-to-capitalization ratio of 38.9%. In
addition, the Company may incur additional indebtedness in the future under the
Credit Facility in connection with its acquisition, development, exploitation
and exploration of oil and natural gas producing properties. As of September 30,
1997, after giving pro forma effect to the Transactions, the Company would have
had $141.9 million ($123.9 million as of December 31, 1997) of availability
under the Credit Facility.
15
<PAGE> 16
The degree to which the Company will be leveraged following the
Transactions could have important consequences to holders of the Notes,
including but not limited to, the following: (i) a substantial portion of the
Company's cash flow from operations will be dedicated to debt service and will
not be available for other purposes; (ii) the Company's ability to obtain
additional financing in the future could be limited; (iii) certain of the
Company's borrowings are at variable rates of interest, which could result in
higher interest expense in the event of increases in interest rates; (iv) the
Company may be more vulnerable to downturns in its business or in the general
economy and may be restricted from making acquisitions, introducing new
technologies or exploiting business opportunities; and (v) the Indenture and the
Credit Agreement (as defined herein) contain financial and restrictive covenants
that limit the ability of the Company to, among other things, borrow additional
funds, dispose of assets or pay cash dividends. Failure by the Company to comply
with such covenants could result in an event of default under such debt
instruments which, if not cured or waived, could have a material adverse effect
on the Company. In addition, the degree to which the Company is leveraged could
prevent it from purchasing all Notes tendered to it upon the occurrence of a
Change of Control, which would constitute an event of default under the
Indenture. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Restated Credit Facility," "Description of Certain
Indebtedness" and "Description of the Notes."
If the Company is unable to generate sufficient cash flow or otherwise
obtain funds necessary to make required payments on its indebtedness or, if the
Company otherwise fails to comply with the various covenants in such
indebtedness (including covenants in the Credit Facility), it would be in
default under the terms thereof, which would permit the holders of such
indebtedness to accelerate the maturity of such indebtedness and could cause
defaults under other indebtedness of the Company, including the Notes, or result
in its bankruptcy. Such defaults or any bankruptcy of the Company resulting
therefrom could result in a default on the Notes and could delay or preclude
payment of principal of, or interest on, the Notes. See "-- Subordination of the
Notes and Guaranties." The ability of the Company to meet its obligations will
be dependent upon the future performance of the Company, which will be subject
to prevailing economic conditions and to financial, business and other factors,
including factors beyond the control of the Company.
SUBORDINATION OF THE NOTES AND GUARANTIES
The indebtedness evidenced by the Notes and the DRI Guaranty will be senior
subordinated obligations of DMI and DRI, respectively. The payment of the
principal of, premium (if any), and interest on the Notes and the payment of the
DRI Guaranty are each subordinate in right of payment, as set forth in the
Indenture, to the prior payment in full of all Senior Indebtedness of DMI or
DRI, as the case may be, including the obligations of DMI under, and DRI's
guarantee of DMI's obligations with respect to, the Credit Facility. Any future
Subsidiary Guaranty (as defined herein) will be similarly subordinated to Senior
Indebtedness of such Subsidiary Guarantor (as defined herein).
As of September 30, 1997, after giving pro forma effect to the
Transactions, (i) the Senior Indebtedness of DMI would have been approximately
$23.1 million, all of which would have been secured and (ii) the Senior
Indebtedness of DRI would have been approximately $23.1 million, all of which
would have represented guarantees of Senior Indebtedness of DMI under the Credit
Facility. Although the Indenture contains limitations on the amount of
additional indebtedness that DMI may incur, under certain circumstances the
amount of such indebtedness could be substantial and, in any case, such
indebtedness may be Senior Indebtedness. See "Description of the
Notes -- Certain Covenants -- Limitation on Indebtedness." As of September 30,
1997, after giving pro forma effect to the Transactions, including the
anticipated repayment of borrowings under the Credit Facility, approximately
$141.9 million ($123.9 million as of December 31, 1997) of additional borrowings
would have been available under the Credit Facility for general corporate
purposes, which amounts will constitute Senior Indebtedness of DMI and DRI if
and when incurred.
In the event of the bankruptcy, liquidation or reorganization of DMI, DRI
or any Subsidiary Guarantor, the assets of DMI, DRI or such Subsidiary
Guarantor, as the case may be, will be available to pay the Notes or such
Guaranty (as defined herein) only after all Senior Indebtedness of DMI, DRI or
such Subsidiary Guarantor, as the case may be, has been paid in full. Sufficient
funds may not exist to pay amounts due on the Notes in such event. In addition,
the subordination provisions of the Indenture provide that no payment (other
16
<PAGE> 17
than certain non-cash payments) may be made with respect to the Notes during the
continuance of a payment default under certain Senior Indebtedness. Furthermore,
if certain non-payment defaults exist with respect to certain Senior
Indebtedness of DMI, the holders of such Senior Indebtedness will be able to
prevent payments on the Notes for certain periods of time. See "Description of
the Notes -- Ranking."
CONTROLLING SHAREHOLDER
In December 1995, the Company completed a $40.0 million private placement
of securities to TPG consisting of Convertible Preferred (as defined herein),
Common Shares and warrants to purchase Common Shares. After giving pro forma
effect to the Equity Offering and the TPG Purchase, TPG will own approximately
34% of the Common Shares outstanding. TPG is entitled to nominate a minimum of
three of the seven members of the Company's Board of Directors so long as TPG
maintains certain ownership levels. In addition, certain transactions, including
changes to the number of board members, amendments to the Company's Articles of
Continuance, certain issuances of debt, certain acquisitions and dispositions,
and most issuances of equity, require the two-thirds majority of the Board of
Directors, which cannot be obtained without the approval of at least one TPG
nominee. Additionally, so long as TPG's equity interest is 20% or greater, it
has the right (which has been partially waived for the Equity Offering), but not
the obligation, to maintain its pro rata ownership interest in the equity
securities of the Company in the event the Company issues any additional equity
securities or securities convertible into Common Shares by purchasing additional
securities on the same terms and conditions. At the request of the New York
Stock Exchange, the Company has agreed to make the extension of this right
subject to shareholder ratification every five years with the first vote on the
matter expected to be at the Company's annual meeting in the year 2000. See
"Interests of Management in Certain Transactions."
DEPENDENCE ON KEY PERSONNEL
The Company believes that its continued success will depend to a
significant extent upon the abilities and continued efforts of its Board of
Directors and its senior management, particularly Gareth Roberts, its Chief
Executive Officer and President. The Company does not have any employment
agreements and does not maintain any key man life insurance policies. The loss
of the services of any of its key personnel could have a material adverse effect
on the Company's results of operations. The success of the Company will also
depend, in part, upon the Company's ability to find, hire and retain additional
key management personnel who are also being sought by other businesses. The
inability to find, hire and retain such personnel could have a material adverse
effect upon the Company's results of operations. See "Management."
RISKS RELATING TO A CHANGE OF CONTROL
Upon a Change of Control, holders of the Notes will have the right to
require the Company to purchase all or any part of such holders' Notes at a
price equal to 101% of the principal amount thereof, plus accrued and unpaid
interest, if any, to the date of purchase. The events that constitute a Change
of Control under the Indenture would constitute a default under the Credit
Agreement, which prohibits the purchase of the Notes by the Company in the event
of certain Change of Control events unless and until such time as the Company's
indebtedness under the Credit Facility is repaid in full. There can be no
assurance that the Company and the Guarantor would have sufficient financial
resources available to satisfy all of its or their obligations under the Credit
Facility and the Notes in the event of a Change of Control. The Company's
failure to purchase the Notes would result in a default under the Indenture and
under the Credit Agreement, each of which could have material adverse
consequences for the Company and the holders of the Notes. See "Description of
Certain Indebtedness" and "Description of the Notes -- Change of Control."
COMPETITION
The Company operates in a highly competitive industry. The Company competes
with a large number of integrated and independent energy companies for the
acquisition of desirable oil and natural gas properties, as well as for the
equipment and labor required to develop and operate such properties. Many of
these
17
<PAGE> 18
competitors have financial and other resources substantially greater than those
of the Company. See "Business and Properties -- Competition."
The principal resources necessary for the exploration for, and the
acquisition, exploitation, production and sale of, oil and natural gas are
leaseholds under which oil and natural gas reserves may be discovered, drilling
rigs and related equipment to explore for and develop such reserves, capital
assets required for the exploitation and production of the reserves and
knowledgeable personnel to conduct all phases of oil and natural gas operations.
The Company must compete for such resources with major oil companies and
independent operators and also with other industries for certain personnel and
materials. Although the Company believes its current resources are adequate to
preclude any significant disruption of operations in the immediate future, the
continued availability of such materials and resources to the Company cannot be
assured.
GOVERNMENTAL AND ENVIRONMENTAL REGULATION
The production of oil and natural gas is subject to regulation under a wide
range of United States federal and state statutes, rules, orders and
regulations. Federal and state statutes and regulations require permits for
drilling, reworking and recompletion operations, drilling bonds and reports
concerning operations, and these permits are subject to modification, renewal
and revocation by the issuing governmental authority. Most states in which the
Company owns and operates properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment of
wells. Many states also restrict production to the market demand for oil and
natural gas, and several states have indicated interest in revising applicable
regulations in light of the persistent oversupply and low prices for oil and
natural gas production. These regulations may limit the rate at which oil and
natural gas could otherwise be produced from the Company's properties. Some
states have also enacted statutes prescribing ceiling prices for natural gas
sold within the state. See "Business and Properties -- Regulations."
Various federal, state and local laws and regulations relating to the
protection of the environment may affect the Company's operations and costs. In
particular, the Company's production operations, its salt water disposal
operations and its use of facilities for treating, processing or otherwise
handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. The majority of the Company's Louisiana activity is
conducted in a marsh environment where environmental regulations are somewhat
greater. Although compliance with these regulations increases the cost of
Company operations, such compliance has not had a material effect on the
Company's capital expenditures, earnings or competitive position. There can be
no assurance, however, that future compliance with these regulations will not
have such a material adverse effect. Environmental regulations have historically
been subject to frequent change by regulatory authorities, and the Company is
unable to predict the ongoing cost of complying with these laws and regulations
or the future impact of such regulations on its operations. There can be no
assurance that present or future regulation will not adversely affect the
Company's exploration, development and production of its oil and natural gas
producing properties. A significant discharge of hydrocarbons into the
environment could, to the extent such event is not insured, subject the Company
to substantial expense. See "Business and Properties -- Regulations."
ABSENCE OF A PUBLIC MARKET FOR THE NOTES
The Notes are a new issue of securities for which there is currently no
trading market. The Underwriters have advised the Company that they currently
intend to make a market in the Notes, although the Underwriters are not
obligated to do so and may discontinue such market making at any time. The
Company does not intend to apply for listing of the Notes on any domestic
securities exchange or to seek approval for quotation through an automated
quotation system. Accordingly, there can be no assurance that an active market
will develop upon completion of the Debt Offering or, if developed, that such
market will be sustained or as to the liquidity of any market. Factors such as
quarterly or cyclical variations in the Company's financial results, variations
in interest rates, future announcements concerning the Company or its
competitors, government regulation, general economic and other conditions and
developments affecting the oil and gas industry could cause the market price of
the Notes to fluctuate substantially.
18
<PAGE> 19
CONCENTRATION OF CUSTOMERS
During 1996, the Company sold 10% or more of its net production of oil and
natural gas to the following purchasers: Natural Gas Clearinghouse (20%); Penn
Union Energy Services (19%); Enron Trading & Transportation (13%); and Hunt
Refining (15%). In addition, the Company is currently selling a majority of its
oil to Hunt Refining under a two-year contract which expires in April 1998 and
is currently receiving a premium to the posted price in this contract. The
Company may not be able to renew this contract in the future or may not be able
to obtain terms as favorable as those in the existing contract. While the
Company believes that its relationships with these purchasers are good, any loss
of revenue from these purchasers could have a material adverse effect on the
Company's results of operations.
FORWARD-LOOKING STATEMENTS
The statements contained in this Prospectus that are not historical facts,
including, but not limited to, statements found in the "Prospectus Summary,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business and Properties," are "forward-looking statements," as
that term is defined in Section 21E of the Exchange Act, that involve a number
of risks and uncertainties. Such forward-looking statements may be or may
concern, among other things, capital expenditures, drilling activity,
acquisition plans and proposals, dispositions, development activities, cost
savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon
prices, liquidity, regulatory matters and competition. Such forward-looking
statements generally are accompanied by words such as "plan," "estimate,"
"expect," "predict," "anticipate," "projected," "should," "assume," "believe" or
other words that convey the uncertainty of future events or outcomes. Such
forward-looking statements are based upon management's current plans,
expectations, estimates and assumptions and are subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and the Company's financial condition and
results of operations. As a consequence, actual results may differ materially
from expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital, general economic conditions,
competition and government regulations, as well as the risks and uncertainties
discussed in this Prospectus, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in the
Company's other public reports, filings and public statements.
EQUITY OFFERING
Concurrently with the Debt Offering, the Company is offering 4,557,200
Common Shares to the public in the Equity Offering and TPG is purchasing 313,400
Common Shares in the TPG Purchase. In addition, as part of the Equity Offering
the Company has granted the underwriters an option to purchase up to 683,580
additional Common Shares to cover over-allotments, if any. The closing of the
Debt Offering is conditioned upon the closing of the Equity Offering and the TPG
Purchase; however, the closing of the Equity Offering is not conditioned upon
the closing of the Debt Offering.
19
<PAGE> 20
USE OF PROCEEDS
The net proceeds to the Company from the Debt Offering are estimated to be
approximately $121.8 million. Concurrently with the Debt Offering, the Company
is offering 4,557,200 Common Shares in the Equity Offering and TPG is purchasing
313,400 Common Shares in the TPG Purchase. The closing of the Debt Offering is
conditioned upon the closing of the Equity Offering and the TPG Purchase;
however, the closing of the Equity Offering is not conditioned upon the closing
of the Debt Offering.
The Company intends to use the total net proceeds of the Offerings and the
TPG Purchase (estimated to be $198.9 million in the aggregate) to reduce
outstanding borrowings under the Credit Facility. The undrawn balance under the
Credit Facility will then be available for capital expenditures and general
corporate purposes, including the acquisition of additional producing oil and
natural gas properties. As of December 31, 1997, the Credit Facility had an
outstanding balance of $240.0 million and an average interest rate of 7.5% per
annum. After the application of the net proceeds from the Offerings and the TPG
Purchase to reduce amounts outstanding under the Credit Facility, the Credit
Facility will consist of a five-year revolving credit facility with a borrowing
base of $165.0 million. The Company borrowed $220.0 million under the Credit
Facility during the fourth quarter of 1997, primarily to fund the Chevron
Acquisition. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Restated Credit Facility," "Business and
Properties -- Acquisitions of Oil and Natural Gas Properties" and "Description
of Certain Indebtedness -- Credit Facility."
20
<PAGE> 21
CAPITALIZATION
The following table sets forth as of September 30, 1997 (i) the actual
capitalization of the Company, (ii) the capitalization of the Company as
adjusted for the Chevron Acquisition, (iii) the capitalization of the Company as
further adjusted to give effect to the Equity Offering, the TPG Purchase and the
application of the net proceeds therefrom and (iv) the capitalization of the
Company as further adjusted to give effect to the Debt Offering and the
application of the net proceeds therefrom. See "Use of Proceeds." This table
should be read in conjunction with "Unaudited Pro Forma Consolidated Financial
Information," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the Consolidated Financial Statements.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997
------------------------------------------------------
AS FURTHER
ADJUSTED FOR
AS ADJUSTED THE EQUITY
FOR THE OFFERING AS ADJUSTED
COMPANY CHEVRON AND TPG FOR THE
HISTORICAL ACQUISITION PURCHASE TRANSACTIONS
---------- ----------- ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents....................... $ 2,236 $ 2,236 $ 2,236 $ 2,236
======== ======== ======== ========
Short-term debt:
Credit Facility (a)........................... $ -- $ 47,000 $ -- $ --
-------- -------- -------- --------
Long-term debt:
Credit Facility (a)........................... 20,000 175,000 144,890 23,100
9% Senior Subordinated Notes Due 2008......... -- -- -- 125,000
Other notes payable........................... 5 5 5 5
-------- -------- -------- --------
Total long-term debt.................. 20,005 175,005 144,895 148,105
-------- -------- -------- --------
Shareholders' equity (b):
Common Shares, no par value; unlimited shares
authorized; 20,364,799 outstanding;
25,235,399 outstanding as adjusted for the
Transactions............................... 132,744 132,744 209,854 209,854
Retained earnings............................. 22,814 22,814 22,814 22,814
-------- -------- -------- --------
Total shareholders' equity................. 155,558 155,558 232,668 232,668
-------- -------- -------- --------
Total capitalization.................. $175,563 $377,563 $377,563 $380,773
======== ======== ======== ========
</TABLE>
- ---------------
(a) The Credit Facility was revised and restated in December 1997 in order to
fund the Chevron Acquisition. After repayment of the acquisition tranche and
other borrowings thereunder with the net proceeds from the Offerings and the
TPG Purchase, the Credit Facility will consist of a five year revolving
credit facility with a borrowing base of $165.0 million.
(b) Excludes 1,512,206 outstanding stock options as of September 30, 1997
exercisable at various prices ranging from $5.55 to $17.29 per share with a
weighted average price of $10.69 (of which 395,222 were currently
exercisable), and 700,000 Common Shares reserved for issuance upon exercise
of the two series of Common Share purchase warrants. Also excludes 406,620
stock options that were granted on January 2, 1998, none of which are
currently exercisable.
21
<PAGE> 22
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION
The following unaudited pro forma consolidated statements of income for the
year ended December 31, 1996 and the nine months ended September 30, 1997 and
the unaudited pro forma consolidated balance sheet as of September 30, 1997
(collectively, the "Pro Forma Financial Statements") are based on the historical
consolidated financial statements of the Company and the historical financial
statements of the properties acquired by the Company (the "Chevron Properties")
in the Chevron Acquisition, adjusted to give effect to the Transactions.
Additional property acquisitions were made in 1997 that have not been included
in the pro forma adjustments since they are immaterial individually and in the
aggregate. These acquisitions are included in the Company's historical
statements from the date of their respective acquisition.
The Unaudited Pro Forma Consolidated Statement of Income for the year ended
December 31, 1996 gives effect to the Transactions as if they had occurred as of
January 1, 1996, and the Unaudited Pro Forma Consolidated Statement of Income
for the nine months ended September 30, 1997 gives effect to the Transactions as
if they had occurred as of January 1, 1997. The Unaudited Pro Forma Consolidated
Balance Sheet gives effect to the Transactions as if they had occurred as of
September 30, 1997. The pro forma adjustments are described in the accompanying
notes and are based upon available information and certain assumptions that
management believes are reasonable.
The Pro Forma Financial Statements do not purport to represent what the
Company's results of operations or financial condition would actually have been
had the Transactions in fact occurred on such dates or to project the Company's
results of operations or financial condition for any future date or period. The
Pro Forma Financial Statements should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements.
22
<PAGE> 23
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
-----------------------------------------------------------------
HISTORICAL ADJUSTMENTS
------------------------ ------------------------
OFFERINGS
COMPANY CHEVRON CHEVRON AND TPG
HISTORICAL PROPERTIES ACQUISITION PURCHASE PRO FORMA
---------- ---------- ----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and related
product........................ $52,880 $23,662 $ -- $ -- $76,542
Interest and other................ 769 -- -- -- 769
------- ------- -------- ------- -------
Total revenues............ 53,649 23,662 -- -- 77,311
------- ------- -------- ------- -------
Expenses:
Production........................ 13,495 6,650 -- -- 20,145
General and administrative........ 4,267 -- 687(b) -- 4,954
Interest.......................... 1,993 -- 15,716(c) (3,900)(e) 13,809
Imputed preferred dividend........ 1,281 -- -- -- 1,281
Loss on early extinguishment of
debt........................... 440 -- -- -- 440
Depletion and depreciation........ 17,904 -- 6,697(d) -- 24,601
Franchise taxes................... 213 -- -- -- 213
------- ------- -------- ------- -------
Total expenses............ 39,593 6,650 23,100 (3,900) 65,443
------- ------- -------- ------- -------
Income before income taxes.......... 14,056 17,012 (23,100) 3,900 11,868
Provision for income taxes.......... (5,312) (6,294)(a) 8,547(a) (1,443)(a) (4,502)
------- ------- -------- ------- -------
Net income.......................... $ 8,744 $10,718 $(14,553) $ 2,457 $ 7,366
======= ======= ======== ======= =======
Net income per common share
Primary........................... $ 0.67 $ 0.41
Fully diluted..................... 0.62 0.40
Average common shares outstanding... 13,104 17,975
</TABLE>
See Notes to Unaudited Pro Forma Consolidated Financial Information
23
<PAGE> 24
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1997
----------------------------------------------------------------
HISTORICAL ADJUSTMENTS
----------------------- ------------------------
OFFERINGS
COMPANY CHEVRON CHEVRON AND TPG
HISTORICAL PROPERTIES ACQUISITION PURCHASE PRO FORMA
---------- ---------- ----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil, natural gas and related
product........................... $60,083 $14,034 $ -- $ -- $74,117
Interest and other................... 986 -- -- -- 986
------- ------- ------- ------- -------
Total revenues............... 61,069 14,034 -- -- 75,103
------- ------- ------- ------- -------
Expenses:
Production........................... 15,737 5,237 -- -- 20,974
General and administrative........... 4,535 -- 514(b) -- 5,049
Interest............................. 387 -- 10,289(c) (1,483)(e) 9,193
Depletion and depreciation........... 23,224 -- 3,942(d) -- 27,166
Franchise taxes...................... 308 -- -- -- 308
------- ------- ------- ------- -------
Total expenses............... 44,191 5,237 14,745 (1,483) 62,690
------- ------- ------- ------- -------
Income before income taxes............. 16,878 8,797 (14,745) 1,483 12,413
Provision for income taxes............. (6,245) (3,255)(a) 5,456(a) (549)(a) (4,593)
------- ------- ------- ------- -------
Net income............................. $10,633 $ 5,542 $(9,289) $ 934 $ 7,820
======= ======= ======= ======= =======
Net income per common share
Primary.............................. $ 0.53 $ 0.31
Fully diluted........................ 0.50 0.31
Average common shares outstanding...... 20,175 25,046
</TABLE>
See Notes to Unaudited Pro Forma Consolidated Financial Information
24
<PAGE> 25
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997
----------------------------------------------------------------
ADJUSTMENTS
-------------------------------------
EQUITY
OFFERING
COMPANY CHEVRON AND TPG DEBT
HISTORICAL ACQUISITION PURCHASE OFFERING PRO FORMA
---------- ----------- -------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
ASSETS:
Current assets
Cash and cash equivalents........ $ 2,236 $ -- $ -- $ -- $ 2,236
Accrued production receivable.... 7,097 -- -- -- 7,097
Trade and other receivables...... 14,507 -- -- -- 14,507
-------- -------- -------- -------- --------
Total current assets..... 23,840 -- -- -- 23,840
-------- -------- -------- -------- --------
Property and equipment (using full
cost accounting)
Oil and gas properties........... 230,521 127,000(f) -- -- 357,521
Unevaluated oil and gas
properties.................... 6,389 75,000(f) -- -- 81,389
Less accumulated depreciation and
depletion..................... (53,527) -- -- -- (53,527)
-------- -------- -------- -------- --------
Net property and equipment.... 183,383 202,000 -- -- 385,383
-------- -------- -------- -------- --------
Other assets....................... 3,201 -- -- 3,210(k) 6,411
-------- -------- -------- -------- --------
Total assets............. $210,424 $202,000 $ -- $ 3,210 $415,634
======== ======== ======== ======== ========
LIABILITIES AND SHAREHOLDERS'
EQUITY:
Current liabilities
Accounts payable and accrued
liabilities................... $ 16,858 $ -- $ -- $ -- $ 16,858
Oil and gas production payable... 4,060 -- -- -- 4,060
Current portion of long-term
debt.......................... 23 47,000(g) (47,000)(i) -- 23
-------- -------- -------- -------- --------
Total current
liabilities............ 20,941 47,000 (47,000) -- 20,941
-------- -------- -------- -------- --------
Long-term liabilities
Long-term debt................... 20,005 155,000(h) (30,110)(i) (121,790)(l) 23,105
Senior subordinated debt......... -- -- -- 125,000(m) 125,000
Provision for site reclamation
costs......................... 938 -- -- -- 938
Deferred income taxes and
other......................... 12,982 -- -- -- 12,982
-------- -------- -------- -------- --------
Total long-term
liabilities............ 33,925 155,000 (36,081) 3,210 162,025
-------- -------- -------- -------- --------
Shareholders' equity
Common shares, no par value;
unlimited shares authorized;
20,364,799 outstanding;
25,235,399 outstanding pro
forma......................... 132,744 -- 77,110(j) -- 209,854
Retained earnings................ 22,814 -- -- -- 22,814
-------- -------- -------- -------- --------
Total shareholders'
equity................. 155,558 -- 77,110 -- 232,668
-------- -------- -------- -------- --------
Total liabilities and
shareholders' equity... $210,424 $202,000 $ -- $ 3,210 $415,634
======== ======== ======== ======== ========
</TABLE>
See Notes to Unaudited Pro Forma Consolidated Financial Information
25
<PAGE> 26
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION
(a) Income taxes were computed using the federal statutory rate of 35% plus a 2%
provision for state income taxes.
(b) Reflects an increase of $687,000 and $514,000 for the year ended December
31, 1996 and the nine months ended September 30, 1997, respectively, in
general and administrative expense for additional personnel and associated
costs relating to the properties acquired in the Chevron Acquisition, net of
anticipated allocations to operations and capitalization of exploration
costs.
(c) Reflects an increase in interest expense for the period presented to reflect
the $202.0 million of borrowing under the Credit Facility (at an assumed
annual interest rate of 7.8% and 6.8% for the year ended December 31, 1996
and the nine months ended September 30, 1997, respectively) that would have
been required to fund the Chevron Acquisition had it occurred as of the
beginning of each respective period.
(d) Depreciation, depletion and amortization ("DD&A") and site reclamation
expenses have been computed using the unit of production method and reflects
the Company's increased investment in oil and natural gas properties, which
investment excludes $75.0 million of the Chevron Acquisition purchase price
as the Company intends to classify this amount as unevaluated properties at
December 31, 1997. The December 31, 1997 estimated proved reserves prepared
by Netherland & Sewell were used in the DD&A computation for the Chevron
Acquisition.
(e) Reflects a decrease in interest expense for the period presented resulting
from (i) the receipt of $77.1 million in estimated net proceeds from the
Equity Offering and the TPG Purchase and the application of such net
proceeds to reduce borrowings under the Credit Facility and (ii) the receipt
of $121.8 million in estimated net proceeds from the Debt Offering and the
application of such net proceeds to reduce borrowings under the Credit
Facility. Interest expense also includes the amortization of deferred debt
issuance costs.
(f) Reflects the purchase price paid in the Chevron Acquisition, of which the
Company intends to classify $75.0 million as unevaluated properties.
(g) Reflects the incurrence of indebtedness under the Acquisition Tranche (as
defined herein) of the Credit Facility to finance a portion of the Chevron
Acquisition.
(h) Reflects the incurrence of indebtedness under the revolving portion of the
Credit Facility to finance a portion of the Chevron Acquisition.
(i) Reflects the repayment of indebtedness outstanding under the Credit Facility
with the net proceeds of the Equity Offering and the TPG Purchase.
(j) Reflects the issuance and sale of Common Shares in the Equity Offering and
the TPG Purchase, net of underwriting discounts and commissions and
estimated expenses.
(k) Reflects deferred financing costs incurred in connection with the Debt
Offering.
(l) Reflects the repayment of indebtedness outstanding under the Credit Facility
with the net proceeds of the Debt Offering.
(m) Reflects the issuance of the Notes in the Debt Offering.
26
<PAGE> 27
SELECTED CONSOLIDATED FINANCIAL DATA
The selected historical consolidated financial data for the Company set
forth below as of and for the years ended December 31, 1992, 1993, 1994, 1995
and 1996, have been derived from the audited consolidated financial statements
of the Company. The selected historical consolidated financial data for the
nine-month periods ended September 30, 1996 and 1997, and as of September 30,
1997, have been derived from unaudited consolidated financial statements of the
Company which, in management's opinion, include all adjustments (consisting of
only normal recurring adjustments) necessary to present fairly the results for
such periods. The operating results for such periods are not necessarily
indicative of the operating results to be expected for a full fiscal year. The
information set forth below should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------------------- ------------------
1992 1993 1994 1995 1996 1996 1997
------ ------- ------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil, natural gas and related product.................... $1,912 $ 5,868 $12,692 $20,032 $52,880 $34,709 $60,083
Interest income......................................... 40 76 23 77 769 425 986
------ ------- ------- ------- ------- ------- -------
Total revenues...................................... 1,952 5,944 12,715 20,109 53,649 35,134 61,069
------ ------- ------- ------- ------- ------- -------
Expenses:
Production.............................................. 634 2,067 4,309 6,789 13,495 9,197 15,737
General and administrative.............................. 955 782 1,105 1,832 4,267 2,825 4,535
Interest................................................ 8 83 1,146 2,085 1,993 1,530 387
Imputed preferred dividends............................. -- -- -- -- 1,281 1,153 --
Loss on early extinguishment of debt.................... -- -- -- 200 440 440 --
Depletion and depreciation.............................. 690 1,898 4,209 8,022 17,904 12,557 23,224
Franchise taxes......................................... -- -- 65 100 213 160 308
------ ------- ------- ------- ------- ------- -------
Total expenses...................................... 2,287 4,830 10,834 19,028 39,593 27,862 44,191
------ ------- ------- ------- ------- ------- -------
Income (loss) before the following:....................... (335) 1,114 1,881 1,081 14,056 7,272 16,878
Gain on sale of Canadian properties..................... -- 966 -- -- -- -- --
------ ------- ------- ------- ------- ------- -------
Income (loss) before income taxes......................... (335) 2,080 1,881 1,081 14,056 7,272 16,878
Provision for federal income taxes........................ -- (345) (718) (367) (5,312) (2,932) (6,245)
------ ------- ------- ------- ------- ------- -------
Net income (loss)......................................... $ (335) $ 1,735 $ 1,163 $ 714 $ 8,744 $ 4,340 $10,633
====== ======= ======= ======= ======= ======= =======
Net income (loss) per common share:
Primary................................................. $(0.11) $ 0.35 $ 0.19 $ 0.10 $ 0.67 $ 0.37 $ 0.53
Fully diluted........................................... (0.11) 0.35 0.19 0.10 0.62 0.36 0.50
Weighted average common shares outstanding................ 2,949 4,990 6,240 6,870 13,104 11,616 20,175
OTHER FINANCIAL DATA:
Operating cash flow(a).................................... $ 354 $ 3,030 $ 6,185 $ 9,394 $34,140 $21,767 $40,166
Capital expenditures...................................... 6,189 29,855 16,903 28,524 86,857 73,320 70,773
EBITDA(b)................................................. 323 3,019 7,213 11,311 34,905 22,527 39,503
SELECTED RATIOS:
Ratio of earnings to fixed charges(c)..................... (d) 12.3x 2.6x 1.5x 4.4x 3.1x 34.9x
Ratio of EBITDA to interest expense....................... 40.4 36.4 6.3 5.4 17.5 14.7 102.1
Ratio of long-term debt to EBITDA......................... -- 2.0 2.3 0.3 0.1 1.6(e) 0.4(e)
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
----------------------------------------------- SEPTEMBER 30,
1992 1993 1994 1995 1996 1997
------ ------- ------- ------- -------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)................................. $1,369 $(1,410) $(1,620) $ 6,862 $ 12,482 $ 2,899
Total assets.............................................. 8,225 35,978 48,964 77,641 166,505 210,424
Long-term debt, net of current maturities................. -- 6,177 16,536 3,474 125 20,005
Convertible preferred stock............................... -- -- -- 15,000 -- --
Shareholders' equity...................................... 7,548 24,431 25,962 53,501 142,504 155,558
</TABLE>
- ---------------
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
(b) EBITDA represents earnings before interest income, interest expense, income
taxes, depletion and depreciation, gain on sale of oil and gas properties,
imputed preferred dividends and losses on early extinguishment of debt. The
Company has included information concerning EBITDA because it believes that
EBITDA is used by certain investors as one measure of an issuer's historical
ability to service its debt. EBITDA is not a measurement determined in
accordance with generally accepted accounting principles and should not be
considered in isolation or as a substitute for measures of performance
prepared in accordance with generally accepted accounting principles.
(c) For purposes of determining the ratio of earnings to fixed charges, earnings
are defined as earnings from continuing operations before income taxes, plus
fixed charges. Fixed charges consist of interest expense, amortization of
debt expense, and imputed preferred stock dividends.
(d) Earnings were inadequate to cover fixed charges as there was a $317,000
deficiency.
(e) EBITDA for these periods has been annualized.
27
<PAGE> 28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. Over the last four years, the Company has
achieved rapid growth in proved reserves, production and cash flow by
concentrating on the acquisition of properties which it believes have
significant upside potential and through the efficient development, enhancement
and operation of its properties.
ACQUISITION OF CHEVRON PROPERTIES
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202.0
million. The Chevron Acquisition represents the largest acquisition by the
Company to date. The Heidelberg Field is adjacent to the Company's other primary
oil properties in Mississippi and includes 122 producing wells, 96 of which the
Company will operate. The Company purchased an average working interest of 94%
and an average net revenue interest of 81% in these 96 wells, which wells
currently account for approximately 99% of the field's average net daily
production. The average net daily production from these properties during the
third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75.0 million of the purchase price to unevaluated
properties.
The Company has identified several potential development projects during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 15 wells and recompleting 30
wells in new zones. In addition, the Company has identified over 40 potential
drilling locations in addition to other potential secondary and tertiary
recovery projects. Horizontal wells drilled by the Company in 1997 at nearby
Davis, Quitman and Eucutta Fields improved daily production rates significantly
as compared to vertical wells drilled in the same fields. Consequently, the
Company anticipates that 30 of the 40 proposed future wells in the Heidelberg
Field will be horizontal wells. The Company's total 1998 development budget for
the Heidelberg Field is approximately $30.0 million.
ACQUISITION OF HESS PROPERTIES
The Company completed several property acquisitions during 1996, the
largest of which was the acquisition of producing oil and natural gas properties
in Mississippi, Louisiana and Alabama, plus certain overriding royalty interests
in Ohio, for approximately $37.2 million from Amerada Hess, effective May 1,
1996. The average daily production from the properties included in the Hess
Acquisition during May and June 1996, the first two months of ownership, was
approximately 2,945 BOE/d. The average daily production on these properties had
increased to 5,373 BOE/d by the third quarter of 1997. As of December 31, 1997,
in the Company's independent reserve report (the "December Report"), the
properties acquired in the Hess Acquisition had estimated net proved reserves of
approximately 14.2 MMBOE with a PV10 Value of $95.0 million. This compares to
approximately 5.9 MMBOE of net proved reserves and a $43.1 million PV10 Value on
these same properties as reported in the Company's independent reserve report
dated July 1, 1996 (the "July Report"). The December Report was calculated using
year-end prices which were based on a WTI price of $16.18 per Bbl and a NYMEX
price of $2.58 per MMBtu, with these representative prices adjusted by field to
arrive at the appropriate corporate net price, as compared to oil and gas prices
of $20.00 and $2.65, respectively, in the July Report. In addition to the
increase in proved reserves, the Company produced approximately 1.9 MMBOE from
July 1, 1996 through September 30, 1997 with total net operating income of $23.8
million.
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<PAGE> 29
RESTATED CREDIT FACILITY
The Company has a credit facility (the "Credit Facility") with NationsBank
of Texas, N.A., as agent for a group of banks. The Credit Facility was increased
in size from $150.0 million to $300.0 million in December 1997 and the borrowing
base was increased to $260.0 million in order to fund the Chevron Acquisition.
After application of the net proceeds from the Offerings and the TPG Purchase to
reduce amounts outstanding under the Credit Facility, the Credit Facility will
consist of a five-year revolving credit facility with a borrowing base of $165.0
million with $123.9 million available on a pro forma basis as of December 31,
1997. The borrowing base is subject to review every six months. The Credit
Facility is secured by substantially all of the Company's oil and natural gas
properties, except for those acquired in the Chevron Acquisition. Interest is
payable on the revolving credit facility at either the prime rate or, depending
on the percentage of the borrowing base that is outstanding, at rates ranging
from LIBOR plus 7/8% to LIBOR plus 1 3/8%; provided that interest is payable at
LIBOR plus 1 5/8% as long as the Acquisition Tranche is outstanding with the
rate escalating 0.25% each quarter, beginning on March 1, 1998 through March 31,
1999, unless the Acquisition Tranche is repaid. The Credit Facility has several
restrictions, including, among others: (i) a prohibition on the payment of
dividends; (ii) a requirement for a minimum equity balance; (iii) a requirement
to maintain positive working capital (as defined in the Credit Agreement); (iv)
a minimum interest coverage test; and (v) a prohibition on most debt, lien and
corporate guarantees.
THE NOTES
The Notes to be issued by DMI are to be fully and unconditionally
guaranteed by DMI's parent company, DRI, pursuant to the terms and conditions of
the Indenture. In addition, under certain circumstances, certain subsidiaries
may in the future guarantee the Notes. The Indenture will contain certain
covenants for the benefit of the holders of the Notes, including, among others,
covenants limiting the payment of dividends, including dividends payable from
DMI to DRI.
CAPITAL RESOURCES AND LIQUIDITY
As discussed below, in each of the last three years, the Company's capital
expenditures required additional debt and equity capital to supplement cash flow
from operations.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
----------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------- ------- ------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Acquisitions of oil and natural gas
properties............................ $ 6,606 $16,763 $48,407 $16,073
Oil and natural gas expenditures........ 10,297 11,761 38,450 54,700
------- ------- ------- -------
Total......................... $16,903 $28,524 $86,857 $70,773
======= ======= ======= =======
</TABLE>
From January 1, 1994 through September 30, 1997, including the pro forma
adjustments for the Chevron Acquisition, the Company has made total capital
expenditures of $405.1 million. These capital expenditures were funded by the
issuance of equity ($105.3 million), bank debt ($209.9 million) and cash
generated by operations ($89.9 million). During 1996, the Company's funds were
provided by operating cash flow and equity, although the Company did use bank
debt during the year. The Company began 1996 with $100,000 of outstanding bank
debt, borrowed $47.9 million during the year, paid off the debt with the
proceeds from a public offering of Common Shares in October 1996 and ended the
year with $100,000 of bank debt outstanding. For the nine months ended September
30, 1997, the Company's average debt outstanding was $3.6 million.
As of December 31, 1997, the Company had minimal working capital and
approximately $240.0 million of debt outstanding. A portion of this debt also
relates to an acquisition tranche on which the interest rate increases 0.25%
each quarter beginning on March 1, 1998. Although the Company is still reviewing
its budget, particularly in light of the recent Chevron Acquisition, the Company
is currently budgeting capital expenditures for 1998 of approximately $95.0
million, of which approximately $30.0 million is allocated for the
29
<PAGE> 30
properties included in the Chevron Acquisition. Although the Company's projected
cash flow is highly variable and difficult to predict as it is dependent on
product prices, drilling success and other factors, these projected expenditures
are expected to exceed the Company's cash flow during 1998. As of December 31,
1997, after giving pro forma effect to the Transactions, the Company would have
had an unused borrowing base of $123.9 million under the Credit Facility to fund
any potential cash flow deficits. If external capital resources are limited or
reduced in the future, the Company can also adjust its capital expenditure
program accordingly. However, such adjustments could limit, or even eliminate,
the Company's future growth. See "Risk Factors -- Substantial Capital
Requirements."
In addition to its internal capital expenditure program, the Company has
historically required capital for the acquisition of producing properties, which
have been a major factor in the Company's rapid growth during recent years.
There can be no assurance that suitable acquisitions will be identified in the
future or that any such acquisitions will be successful in achieving desired
profitability objectives. Without suitable acquisitions or the capital to fund
such acquisitions, the Company's future growth could be limited or even
eliminated. As such, the Company is seeking additional financing from the
Offerings and the TPG Purchase in order to reduce amounts outstanding under the
Credit Facility and to better position the Company for future opportunities.
SOURCES AND USES OF FUNDS. During the first nine months of 1997, the
Company spent approximately $54.7 million on exploration and development
expenditures and approximately $16.1 million on acquisitions. The exploration
and development expenditures included approximately $38.2 million spent on
drilling, $6.7 million on geological, geophysical and acreage expenditures and
$9.8 million on workover costs. These expenditures were funded by available
cash, bank debt and cash flow from operations. The Company anticipates that a
total of approximately $10 million will be spent during 1997 on exploration
expenditures $65 million on development expenditures, and $225 million on
acquisitions.
During 1996, the Company spent approximately $33.4 million on oil and
natural gas development expenditures, $37.2 million on the Hess Acquisition,
$7.5 million on properties acquired in April 1996 (the "Ottawa Acquisition"),
$3.7 million on other minor oil and natural gas acquisitions, and approximately
$5.1 million on geological, geophysical and acreage expenditures. The
development expenditures included $15.5 million spent on drilling and $17.9
million spent on workover costs. These expenditures were funded during the year
by bank debt, available cash and cash flow from operations, although the bank
debt was retired with the proceeds from a public offering of Common Shares in
October 1996.
During 1995, the Company made $28.5 million in capital expenditures, with
the single largest component being a $10.0 million acquisition of seven
producing wells in the Gibson and Humphreys Fields located near the Company's
other properties in southern Louisiana (the "Gibson Acquisition"). The balance
of 1995 acquisition expenditures were for additional interests in the Company's
Lirette Field in Louisiana ($2.9 million), interests in the Bully Camp Field,
also in Louisiana ($2.1 million), and a few smaller acquisitions in both
Mississippi and Louisiana. During 1995, the Company also spent $1.9 million
drilling four wells in Mississippi, $1.1 million for acreage, geological and
geophysical and delay rentals, and $8.1 million for workovers of existing
properties. The 1995 expenditures were funded on an interim basis with cash flow
from operations ($9.4 million) and bank debt ($19.4 million), which was repaid
in December 1995 with a portion of the $39.5 million of net proceeds from a
private placement of equity with TPG.
Capital expenditures for 1994 were $16.9 million and included $10.3 million
of development costs, primarily expended on natural gas properties in Louisiana,
with the balance of $6.6 million expended on acquisitions of properties
primarily in Louisiana, of which $5.5 million was spent on acquiring additional
working interests in existing Company-operated properties. Expenditures in 1994
were principally funded by $6.2 million of cash provided by operations and net
incremental debt of $8.8 million, of which $1.5 million came from the issuance
of unsecured convertible debentures and the balance from bank debt.
30
<PAGE> 31
RESULTS OF OPERATIONS
OPERATING INCOME
During the last three years, operating income has increased significantly
as outlined in the following chart. Oil and gas revenue increased as a result of
the increased oil and gas production and increases in oil and gas product
prices.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------- ------------------
1994 1995 1996 1996 1997
------- ------- -------- ------- --------
<S> <C> <C> <C> <C> <C>
Operating income (in thousands)
Oil sales............................ $ 6,767 $10,852 $ 28,475 $17,455 $ 36,436
Natural gas sales.................... 5,925 9,180 24,405 17,254 23,647
Less production expenses............. (4,309) (6,789) (13,495) (9,197) (15,737)
------- ------- -------- ------- --------
Operating income.................. $ 8,383 $13,243 $ 39,385 $25,512 $ 44,346
======= ======= ======== ======= ========
Unit prices
Oil price per Bbl.................... $ 13.84 $ 14.90 $ 18.98 $ 18.05 $ 17.53
Gas price per Mcf.................... 1.78 1.90 2.73 2.64 2.54
Netback per BOE
Sales price.......................... $ 12.17 $ 13.05 $ 17.69 $ 16.87 $ 16.56
Production expenses.................. (4.13) (4.42) (4.51) (4.47) (4.34)
------- ------- -------- ------- --------
$ 8.04 $ 8.63 $ 13.18 $ 12.40 $ 12.22
======= ======= ======== ======= ========
Average net daily production volume
Bbls................................. 1,340 1,995 4,099 3,529 7,615
Mcf.................................. 9,113 13,271 24,406 23,867 34,061
BOE.................................. 2,858 4,207 8,167 7,507 13,292
</TABLE>
COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. Production
increases have been fueled by both internal growth from the Company's
development and exploration programs and from the acquisition of producing
properties. Production on a BOE/d basis increased 47% between 1994 and 1995 with
approximately 240 BOE/d attributable to the Gibson Acquisition and the balance
of approximately 1,109 BOE/d primarily attributable to internal growth. Between
1995 and 1996, production increased 94% with approximately 2,550 BOE/d
attributable to the properties acquired in the Hess and Ottawa Acquisitions and
750 BOE/d attributable to properties acquired in the Gibson Acquisition. The
balance of approximately 660 BOE/d was attributable to internal growth on other
properties.
Oil and gas revenue has increased not only because of the large increase in
production, but also due to improved product prices for these periods. Between
1994 and 1995, product price increases were relatively modest with an 8%
increase in oil prices and a 7% increase in natural gas prices. The Company also
realized an $800,000 gas hedging gain during 1995 which added $.17 per Mcf to
its average natural gas price. The Company did not have any oil or natural gas
hedges in place during 1996, nor does it have any currently in place due to the
relatively strong commodity prices and the reduced debt levels of the Company.
During 1996, product prices increased substantially with a 27% increase in the
average oil price and a 44% increase in the average natural gas price. Coupled
with the production increases, the Company's oil and natural gas revenue
increased 164%, or $32.8 million, from 1995 to 1996. Approximately $16.5 million
of the increase was related to properties acquired in the Hess and Ottawa
Acquisitions, approximately $5.4 million to properties acquired in the Gibson
Acquisition, approximately $7.7 million due to the increase in product prices
and the balance of approximately $3.2 million due to increased production from
internal growth on other properties.
Production expenses increased each year along with the increases in
production. On a BOE basis, production expenses increased 7% from 1994 to 1995
and increased 2% from 1995 to 1996. The increases were largely attributable to
the changes in the mix of properties as the Mississippi oil properties tend to
have a higher operating cost per BOE than the Louisiana gas properties. During
the first two months of ownership
31
<PAGE> 32
(May and June 1996), the production expenses averaged $6.27 per BOE on the Hess
Acquisition properties which were more heavily weighted toward Mississippi oil
than Louisiana gas. After assuming operations, these averages were brought more
in line with the Company averages through cost savings and increased production
levels. For the remainder of the year (July through December 1996) production
expenses on these properties averaged $5.05 per BOE.
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. Production
increases have been fueled by both internal growth from the Company's
development and exploration programs and from the acquisition of producing
properties during 1996, particularly the Hess Acquisition. During May and June
of 1996, the first two months of ownership, the properties acquired in the Hess
Acquisition averaged approximately 2,945 BOE/d. During the first, second and
third quarters of 1997, the production from these same properties averaged
approximately 4,385 BOE/d, 4,613 BOE/d and 5,373 BOE/d, respectively, a 49%, 57%
and 82% increase, respectively, from initial production levels. Total corporate
production on a BOE/d basis increased 21% from the fourth quarter of 1996
average of 10,132 BOE/d to the first quarter of 1997 average of 12,256 BOE/d,
increased an additional 9% to 13,405 BOE/d for the second quarter of 1997 and an
additional increase of 6% to 14,195 BOE/d for the third quarter of 1997. Since
the Company has had only limited acquisitions since the Hess Acquisition, the
production increases since June 30, 1996 were almost solely as a result of
internal development. On a quarter to quarter comparison, production on a BOE
basis increased 54% between the respective third quarters. When comparing the
nine month periods, production on a BOE basis has increased 77%, reflecting the
effect of the Hess Acquisition effective in May 1996.
Oil and gas revenue has increased primarily because of the large increase
in production. Oil product prices decreased by 3% and natural gas product prices
declined 4% or an overall decline of 2% when measured on a BOE basis when
comparing the nine months ended September 30, 1997 to the comparable period in
1996. During the first nine months of 1996, approximately 47% of the Company's
production on a BOE basis was oil while during the first nine months of 1997,
approximately 57% of the Company's production on a BOE basis was oil.
Production expenses on an absolute basis increased between the relative
periods of 1996 and 1997 along with the increases in production. On a BOE basis,
production expenses decreased 3% when comparing the first nine months of 1996 to
the first nine months of 1997. This improvement was a result of efficiencies
achieved from higher production volumes (on both an absolute basis and per well
basis) despite the Company having a higher percentage of oil production in 1997
as compared to 1996, which typically has a higher operating cost per BOE.
GENERAL AND ADMINISTRATIVE EXPENSES
As outlined below, general and administrative ("G&A") expenses have
increased along with the Company's growth.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------- -----------------
1994 1995 1996 1996 1997
------ ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Net G&A expenses (in thousands)
Gross expenses.......................... $2,475 $ 3,900 $ 8,407 $ 5,583 $ 9,999
State franchise taxes................... 65 100 213 159 308
Operator overhead charges............... (890) (1,438) (2,916) (1,906) (3,789)
Capitalized exploration expenses........ (480) (630) (1,224) (851) (1,675)
------ ------- ------- ------- -------
Net expenses............................ $1,170 $ 1,932 $ 4,480 $ 2,985 $ 4,843
====== ======= ======= ======= =======
Average G&A cost per BOE.................. $ 1.12 $ 1.25 $ 1.50 $ 1.45 $ 1.33
Employees as of end of period............. 27 51 122 109 141
</TABLE>
COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. On a BOE basis,
these costs increased 12% from 1994 to 1995 and increased 20% from 1995 to 1996.
Part of the increase in 1995 was attributable to $190,000 of costs ($0.12 per
BOE) related to non-recurring personnel changes. As a result of improved
32
<PAGE> 33
financial results during the first quarter of 1996 and other factors, the
Company conducted a review of salaries and awarded increases and bonuses in
February 1996 to its employees. Bonuses, including related payroll taxes,
amounted to approximately $225,000 ($0.08 per BOE). During 1996, the Company
also accrued $545,000 ($0.18 per BOE) for bonuses which were awarded in February
1997. In addition, the Company began to increase its staff levels during the
second quarter of 1996 to handle the Hess Acquisition, but was not entitled to
any operator's overhead recovery on these properties until July 15, 1996,
resulting in a further increase in general and administrative cost per BOE, as
Amerada Hess remained the operator of record until that date.
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. On a BOE
basis, G&A expenses declined 8% when comparing the first nine months of 1996 to
the comparable period in 1997. The decrease is partially attributable to the
increased production on both an absolute and per well basis. Furthermore, the
respective well operating agreements allow the Company, when it is the operator,
to charge a well with a specified overhead rate during the drilling phase. As a
result of the increased drilling activity in 1997, the percentage of gross G&A
recovered through these types of allocations (listed in the above table as
"Operator overhead charges") increased when compared to the corresponding
periods of 1996. During the first nine months of 1996, approximately 34% was
recovered by operator overhead charges, while during the comparable period of
1997 this increased to 38%. This trend is even more pronounced in the third
quarter of 1997 with 42% of the gross G&A recovered as compared to 35% for the
third quarter of 1996.
INTEREST AND FINANCING EXPENSES
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- ------------------
1994 1995 1996 1996 1997
------- ------- ------- -------- -------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
Interest expense....................... $ 1,146 $ 2,085 $ 1,993 $ 1,530 $ 387
Non-cash interest expense.............. (86) (90) (459) (345) (64)
------- ------- ------- ------- ------
Cash interest expense.................. 1,060 1,995 1,534 1,185 323
Interest and other income.............. (23) (77) (769) (425) (986)
------- ------- ------- ------- ------
Net interest expense................. $ 1,037 $ 1,918 $ 765 $ 760 $ (663)
======= ======= ======= ======= ======
Average interest cost per BOE.......... $ 0.99 $ 1.26 $ 0.26 $ 0.37 $(0.18)
Average debt outstanding............... 12,200 21,400 19,500 20,673 3,610
Ratio of earnings to fixed charges..... 2.6x 1.5x 4.4x 3.1x 34.9x
Imputed preferred dividend............. $ -- $ -- $ 1,281 $ 1,153 $ --
Loss on early extinguishment of debt... -- 200 440 440 --
</TABLE>
During the first half of 1996 and 1997, the Company had minimal debt
outstanding as virtually all of the bank debt had been retired during the
previous fourth quarter. In 1995, the bank debt was repaid with proceeds from
the December 1995 private placement of equity with TPG and in 1996, the debt was
repaid with proceeds from a public offering of Common Shares completed in
October 1996. However, in 1996, the Company did incur debt late in the second
quarter in order to fund property acquisitions and, during the third quarter of
1997, the Company borrowed approximately $20 million to fund $12.5 million of
property acquisitions and $7.5 million of development expenditures.
The private placement of equity in December 1995 with TPG included 1.5
million shares of Convertible Preferred. During 1996, the Company recognized
$1.3 million of charges representing the imputed preferred dividend until
October 30, 1996 when the Convertible Preferred were converted into 2.8 million
Common Shares. Under Canadian generally accepted accounting principles, this
dividend was reported as an operating expense, while under U.S. generally
accepted accounting principles this would not be an expense but it would be
deducted from net income to arrive at net income attributable to the common
shareholders. In addition to paying off its bank debt and converting the
Convertible Preferred into common equity during 1996, the Company also converted
its remaining subordinated debt into common equity, leaving the Company
essentially debt-free as of December 31, 1996.
33
<PAGE> 34
During 1996, the Company had a $440,000 charge relating to a loss on early
extinguishment of debt. These costs related to the remaining unamortized debt
issue costs of the Company's prior credit facility which was replaced in May
1996, as previously discussed. The Company also had a charge of $200,000 during
the first half of 1995 for the same type of expense relating to a previous bank
debt refinancing. Under U.S. generally accepted accounting principles, a loss on
early extinguishment of debt would be an extraordinary item rather than a normal
operating expense as required by Canadian generally accepted accounting
principles.
DEPLETION, DEPRECIATION AND SITE RESTORATION
COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. DD&A has
increased along with the additional capitalized cost and increased production.
DD&A per BOE has increased 30% from 1994 to 1995 and 15% from 1995 to 1996
primarily due to 59% of the 1995 capital expenditures and 56% of the 1996
expenditures relating to property acquisitions, which had a higher per unit cost
for the Company than those reserves added by development expenditures.
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. The Company's
DD&A rate per BOE for the first half of 1997 increased to $6.50 per BOE to
provide for the estimated effect of reduced oil prices on reserve quantities,
the estimated effect of rising drilling costs on certain proved undeveloped
locations, and higher than anticipated costs on wells drilled in Louisiana that
were proved undeveloped locations at December 31, 1996. In comparison, the
Company's DD&A rate was $5.99 per BOE for the year ended December 31, 1996. The
oil prices used in the December 31, 1996 reserve report were based on a WTI
posting price of $23.39 per Bbl in accordance with the rules of the Commission
while the comparable WTI price at June 30, 1997 was $17.15 per Bbl. This
reduction in oil prices reduced the June 30, 1997 estimated reserves by
approximately 1.3 MMBbls.
As a result of two oil and natural gas discoveries announced in September,
1997, the Company's third quarter DD&A rate decreased to $6.22 per BOE ($6.40
per BOE for the nine months ended September 30, 1997). During the third quarter
of 1997, the Company also transferred approximately $4.6 million from the
unevaluated properties to the full cost pool reflecting activity on these
properties, leaving a balance of approximately $6.4 million in unevaluated
properties as of September 30, 1997. The DD&A effect of this transfer was
approximately $440,000 for the quarter.
The Company also provides for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision is included in the DD&A expense and has
increased each year along with an increase in the number of properties owned by
the Company.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -----------------
1994 1995 1996 1996 1997
------ ------ ------- ------- -------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
Depletion and depreciation............... $4,177 $7,918 $17,533 $12,430 $22,899
Site restoration provision............... 32 104 371 127 325
------ ------ ------- ------- -------
Total amortization....................... $4,209 $8,022 $17,904 $12,557 $23,224
====== ====== ======= ======= =======
Average DD&A cost per BOE................ $ 4.03 $ 5.22 $ 5.99 $ 6.10 $ 6.40
</TABLE>
34
<PAGE> 35
INCOME TAXES
Due to net operating losses by its U.S. subsidiary each year for tax
purposes, the Company does not have any current tax provision. The deferred tax
provision as a percentage of net income has varied depending on the mix of
Canadian and U.S. expenses. The rate declined from 1994 to 1995 as there were
less Canadian expenses, but increased again slightly in 1996 due to the
non-deductible imputed preferred dividend and interest on the subordinated debt.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -----------------
1994 1995 1996 1996 1997
------ ------ ------- ------- -------
<S> <C> <C> <C> <C> <C>
Deferred income taxes (thousands)........ $ 718 $ 367 $ 5,312 $ 2,932 $ 6,245
Average income tax costs per BOE......... 0.69 0.24 1.78 1.43 1.72
Effective tax rate....................... 38% 34% 38% 40% 37%
</TABLE>
NET INCOME
Primarily as a result of increased production and improved product prices,
net income and cash flow from operations increased substantially between 1995
and 1996 as outlined below. Between 1994 and 1995, net income decreased 39% as a
result of certain nonrecurring charges and a disproportionate increase in DD&A
as compared to the increase in revenue. Net income and cash flow from operations
increased substantially on both a gross and per share basis between the first
nine months of 1996 and the first nine months of 1997 as outlined below.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -----------------
1994 1995 1996 1996 1997
------ ------ ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Net income............................... $1,163 $ 714 $ 8,744 $ 4,340 $10,633
Net income per common share:
Primary................................ 0.19 0.10 0.67 0.37 0.53
Fully diluted.......................... 0.19 0.10 0.62 0.36 0.50
Cash flow from operations(a)............. 6,185 9,394 34,140 21,767 40,166
</TABLE>
- ---------------
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
35
<PAGE> 36
The following table summarizes the cash flow, DD&A and net income on a BOE
basis for the comparative periods. Each of the individual components are
discussed above.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------ ---------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Per BOE data
Revenue................................... $12.17 $13.05 $17.69 $16.87 $16.56
Production expenses....................... (4.13) (4.42) (4.51) (4.47) (4.34)
------ ------ ------ ------ ------
Production netback........................ 8.04 8.63 13.18 12.40 12.22
General and administrative................ (1.12) (1.25) (1.50) (1.45) (1.33)
Interest.................................. (0.99) (1.26) (0.26) (0.37) 0.18
------ ------ ------ ------ ------
Cash flow from operations(a)........... 5.93 6.12 11.42 10.58 11.07
DD&A...................................... (4.03) (5.22) (5.99) (6.10) (6.40)
Deferred income taxes..................... (0.69) (0.24) (1.78) (1.43) (1.72)
Other non-cash items...................... (0.10) (0.19) (0.72) (0.94) (0.02)
------ ------ ------ ------ ------
Net income............................. $ 1.11 $ 0.47 $ 2.93 $ 2.11 $ 2.93
====== ====== ====== ====== ======
</TABLE>
- ---------------
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
YEAR 2000 MODIFICATIONS
The Company is currently reviewing its computer systems in order to
evaluate necessary modifications for the year 2000. The Company does not
currently anticipate that it will incur material expenditures to complete any
such modifications.
RECENTLY ISSUED ACCOUNTING STANDARDS
See discussion of Recently Issued Accounting Standards in Note 7 of the
Consolidated Financial Statements.
36
<PAGE> 37
BUSINESS AND PROPERTIES
THE COMPANY
Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. The Company believes the Gulf Coast
represents one of the most attractive regions in North America given the
region's prolific production history, complex geology (with multiple producing
horizons) and the opportunities that have been created by advanced technologies
such as 3-D seismic and various drilling, completion and recovery techniques. As
of December 31, 1997, the Company had proved reserves of 52.0 MMBbls and 77.2
Bcf or 64.9 MMBOE, including 27.6 MMBOE attributable to the Chevron Acquisition.
At such date, the PV10 Value of these reserves was $361.3 million, of which
$276.5 million was attributable to proved developed reserves. Denbury operates
wells comprising approximately 83% of its PV10 Value. The eight largest fields
in which the Company has an interest constitute approximately 82% of its
estimated proved reserves and, within these eight fields, Denbury owns an
average working interest of 91%.
Over the last four years, the Company has achieved rapid growth in proved
reserves, production and cash flow by concentrating on the acquisition of
properties which it believes have significant upside potential and through the
efficient development, enhancement and operation of its properties. For the
four-year period ended December 31, 1997, the Company increased its proved
reserves at a compound annual growth rate of 83%, from 5.8 MMBOE to 64.9 MMBOE.
Over the four-year period ended December 31, 1996, the Company also increased
its average net daily production at a compound annual growth rate of 90%, from
1,193 BOE/d to 8,167 BOE/d, with a further increase to 14,195 BOE/d for the
third quarter of 1997. For the same four-year period, EBITDA increased at a
compound annual growth rate of 126%, from $3.0 million to $34.9 million. EBITDA
for the twelve months ended September 30, 1997 was $51.9 million.
Since 1993, when the Company began to focus its operations exclusively in
the United States, through December 31, 1995, the Company spent a total of $43.4
million on acquisitions. In May 1996, the Company acquired properties in its
core areas of Mississippi and Louisiana from Amerada Hess for approximately
$37.2 million. As of June 30, 1996, these acquired properties were producing
approximately 2,945 BOE/d and had proved reserves of approximately 5.9 MMBOE.
Since that date, the Company's extensive development and exploitation on these
properties has resulted in an 82% increase in their production to 5,373 BOE/d
for the third quarter of 1997 and a 141% increase in their proved reserves to
14.2 MMBOE as of December 31, 1997.
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, which is adjacent to the Company's other primary oil properties in
Mississippi, from Chevron for approximately $202.0 million. These properties are
located approximately nine miles from the Eucutta Field, the property with the
highest PV10 Value of those acquired by the Company in the Hess Acquisition. The
estimated proved reserves as of January 1, 1998 for the Chevron Acquisition
properties are approximately 27.6 MMBOE, with average net daily production of
approximately 2,940 BOE/d for the third quarter of 1997. As a result of the
significant amount of future development and exploitation to be performed on
these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75.0 million of the purchase price to unevaluated
properties. The Company believes that the properties acquired in the Chevron
Acquisition provide exploitation opportunities similar to those of the
Mississippi properties acquired in the Hess Acquisition and the Company intends
to apply the same technologies to the Heidelberg Field. The Company's estimated
1998 development budget for the Heidelberg Field is approximately $30.0 million.
See "-- Acquisition of Chevron Properties."
BUSINESS STRATEGY
The Company seeks to: (i) achieve attractive returns on capital through
prudent acquisitions, development and exploratory drilling and efficient
operations; (ii) maintain a conservative balance sheet to preserve maximum
financial and operational flexibility; and (iii) create strong employee
incentives through equity ownership. The Company believes that its growth to
date in proved reserves, production and cash flow is a direct result of its
adherence to several fundamental principles which are at the core of the
Company's long-
37
<PAGE> 38
term growth strategy. The Company's long-term growth strategy includes the
following fundamental principles:
REGIONAL FOCUS. The Company intends to continue the regional focus of its
operations. By focusing its efforts in the Gulf Coast region, primarily
Louisiana and Mississippi, the Company has been able to accumulate substantial
geological and reservoir data and operating experience which it believes
provides it with significant competitive advantages. For example, the Company
believes it is better able to identify, evaluate and negotiate potential
acquisitions, and develop and operate its properties in an efficient and low-
cost manner. The Company believes the Gulf Coast represents one of the most
attractive regions in North America given the region's prolific production
history, complex geology (with multiple producing horizons) and the
opportunities that have been created by advanced technologies such as 3-D
seismic and various drilling, completion and recovery techniques. Moreover,
because of the region's proximity to major pipeline networks serving important
northeastern U.S. markets, the Company typically realizes natural gas prices in
excess of those realized in many other producing regions.
DISCIPLINED ACQUISITION STRATEGY. The Company intends to continue to
acquire properties where it believes significant additional value can be
created. Such properties are typically characterized by: (i) long production
histories; (ii) complex geological formations with multiple producing horizons
and substantial exploitation potential; (iii) a history of limited operational
focus and capital investment, often due to their relatively small size and
limited strategic importance to the previous owner; and (iv) the potential for
the Company to gain control of operations. The Company believes that due to
continuing rationalization of properties, primarily by major integrated and
independent energy companies, future acquisition opportunities should continue
to be available. In addition, the Company seeks to maintain a well-balanced
portfolio of oil and natural gas development, exploitation and exploration
projects in order to minimize the overall risk profile of its investment
opportunities while still providing significant upside potential. The recent
Hess and Chevron Acquisitions are examples of the types of opportunities the
Company seeks.
OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company intends to
continue to acquire working interest positions that give it operational control
or that the Company believes may lead to operational control. As the operator of
properties comprising approximately 83% of its total PV10 Value, the Company
believes it is better able to manage and monitor production and more effectively
control expenses, the allocation of capital and the timing of field development.
Once a property is acquired, the Company employs its technical and operational
expertise to fully evaluate a field's future potential. If favorable, it will
consolidate its working interest positions, primarily through negotiated
transactions, which tend to be attractively priced compared to acquisitions
available in competitive situations. The consolidation of ownership allows the
Company to: (i) enhance the effectiveness of its technical staff by
concentrating on relatively few wells; (ii) increase production while adding
virtually no additional personnel; and (iii) increase ownership in a property so
that the potential benefits of value enhancement activities justify the
allocation of Company resources.
EXPLOITATION OF PROPERTIES. The Company intends to maximize the value of
its properties through a combination of increasing production, increasing
recoverable reserves or reducing operating costs. During 1997, the Company's
primary methodology for achieving these objectives was the use of horizontal
drilling, which it also intends to emphasize in 1998. Horizontal drilling has
historically produced oil at faster rates and with lower operating costs on a
BOE basis than traditional vertical drilling. The Company also utilizes a
variety of other techniques to maximize property values, including: (i)
undertaking surface improvements such as rationalizing, upgrading or redesigning
production facilities; (ii) making downhole improvements such as resizing
downhole pumps or reperforating existing production zones; (iii) reworking
existing wells into new production zones with additional potential; and (iv)
utilizing exploratory drilling, which is frequently based on various advanced
technologies such as 3-D seismic.
EXPERIENCED AND INCENTIVIZED PERSONNEL. The Company intends to maintain a
highly competitive team of experienced and technically proficient employees and
motivate them through a positive work environment and stock ownership in the
Company. The Company's 29 geological and engineering professionals have an
average of over 15 years of experience in the Gulf Coast region. The Company
believes that employee ownership, which is encouraged through the Company's
stock option and stock purchase plans, is essential for attracting,
38
<PAGE> 39
retaining and motivating quality personnel. As of January 1, 1998, approximately
86% of the Company's employees were participating in the Company's stock
purchase plan. The Company believes that all employees are important to the
success of the Company and as such grants bonuses and stock options to both
management and employees on a basis roughly proportional to salaries.
OIL AND NATURAL GAS OPERATIONS
Denbury operates in two core areas, Louisiana and Mississippi. The Company
operates 67 wells in Louisiana from an office in Houma and 161 wells in
Mississippi from an office in Laurel. The eight largest oil and natural gas
fields owned by the Company constitute approximately 85% and 82%, respectively,
of its total proved reserves on a BOE and PV10 Value basis. Within these eight
fields, Denbury owns an average 91% working interest and operates 85% of the
wells, which comprise 71% of the Company's PV10 Value. The Company's eight
largest fields are located in three adjacent counties in Mississippi and one
parish in Louisiana. This concentration of value in a relatively small number of
fields allows the Company to benefit substantially from any operating cost
reductions or production enhancements and allows the Company to effectively
manage the properties from its two field offices.
These two core areas are similar in that the major trapping mechanisms for
oil and natural gas accumulations are structural features usually related to
deep-seated salt or shale movement. Both areas typically feature fields with
mostly multiple sandstone reservoirs supported by strong waterdrives. However,
the two areas differ significantly in drilling costs, risks and the size of
potential reserves. In Mississippi, the producing zones are generally shallower
than in Louisiana and therefore drilling and workover costs are lower. However,
the geological complexity of southern Louisiana, which is more expensive to
exploit, creates the potential for larger discoveries, particularly of natural
gas. The Company's production in Louisiana is predominately natural gas, while
Mississippi is predominately oil.
The following table sets forth information with respect to Denbury's
properties, reserves and drilling and production activities. The information
included in this table about the Company's proved oil and natural gas reserve
estimates as of December 31, 1997 were prepared by Netherland & Sewell. See
"Risks Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves."
<TABLE>
<CAPTION>
AVERAGE NET PRODUCTION AS OF
PROVED RESERVES THIRD QUARTER OF SEPTEMBER 30,
AS OF DECEMBER 31, 1997 1997(A) 1997
--------------------------------------- ----------------------- ---------------------
PV10 AVERAGE
NATURAL PV10 VALUE NATURAL GROSS NET
OIL GAS VALUE % OF OIL GAS PRODUCTIVE REVENUE
(MBbls) (MMcf) (000'S)(b) TOTAL (Bbls/d) (Mcf/d) WELLS(c) INTEREST
-------- ------- ---------- ----- ---------- --------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LOUISIANA
Lirette..................... 289 27,746 44,668 12.4% 161 11,983 18 63.0%
Gibson...................... 302 6,631 12,658 3.5% 196 4,602 3 57.8%
South Chauvin............... 135 7,333 9,734 2.7% 48 3,029 4 73.4%
Bayou Rambio................ 69 11,353 18,205 5.0% 45 3,254 3 59.1%
Other Louisiana............. 1,423 15,048 33,192 9.2% 1,186 10,232 82 48.7%
------ ------ ------- ----- ----- ------ ---
Total Louisiana........... 2,218 68,111 118,457 32.8% 1,636 33,100 110 51.5%
------ ------ ------- ----- ----- ------ ---
MISSISSIPPI
Heidelberg(d)............... 30,171 2,517 118,973 32.9% -- -- -- --
Eucutta..................... 8,967 -- 58,657 16.2% 1,895 -- 45 75.3%
Davis....................... 2,660 -- 13,348 3.7% 1,033 -- 25 90.5%
Quitman..................... 3,032 -- 19,064 5.3% 1,914 -- 18 60.7%
Other Mississippi........... 4,834 5,597 29,667 8.2% 1,594 2,716 87 53.1%
------ ------ ------- ----- ----- ------ ---
Total Mississippi........... 49,664 8,114 239,709 66.3% 6,436 2,716 175 66.5%
------ ------ ------- ----- ----- ------ ---
Other......................... 136 966 3,163 0.9% 76 466 -- --
------ ------ ------- ----- ----- ------ ---
Company Total................. 52,018 77,191 361,329 100.0% 8,148 36,282 285 60.7%
====== ====== ======= ===== ===== ====== ===
</TABLE>
39
<PAGE> 40
- ---------------
(a) This table does not include production on the properties acquired in the
Chevron Acquisition. See "-- Production Volumes, Sales Prices and Production
Costs" for pro forma production data.
(b) The reserves were prepared using constant prices and costs in accordance
with the guidelines of the Commission, based on the prices received on a
field by field basis as of December 31, 1997. The oil price at that date was
WTI $16.18 per Bbl adjusted by field and a NYMEX natural gas price average
of $2.58 per MMBtu, also adjusted by field.
(c) Includes only productive wells in which the Company has a working interest
as of September 30, 1997.
(d) Includes properties acquired in the Chevron Acquisition, as well as
properties acquired in three other minor acquisitions in the same field. The
average net production on the properties acquired in the Chevron Acquisition
from July 1, 1997 through September 30, 1997 was 2,840 Bbls/d and 600 Mcf/d
from 122 gross productive wells with an average net revenue interest of 81%.
MISSISSIPPI OPERATING AREA
In Mississippi, most of the Company's production is oil, produced largely
from depths of less than 10,000 feet. Fields in this region are characterized by
relatively small geographic areas which generate prolific production from
multiple pay sands. The Company's Mississippi production is usually associated
with large amounts of saltwater, which must be disposed of in saltwater disposal
wells, and almost all wells require pumping. These factors increase the
operating costs on a per barrel basis as compared to Louisiana. The Company
places considerable emphasis on reducing these costs in order to maximize the
cash flow from this area. The Company has increased its emphasis in horizontal
drilling based on its apparent success during the past year. These horizontal
wells have contributed to the reduction of operating costs on a BOE basis during
the last twelve months, as these wells typically produce oil more efficiently,
resulting in higher production rates and better recovery efficiency.
The Company drilled its first horizontal well in 1995 at the South Thompson
Creek Field in Mississippi and drilled a subsequent horizontal well in this
field during 1996. Both of these wells were completed as producers. During the
last quarter of 1996 and through the end of 1997, the Company completed twelve
horizontal wells at an average cost of $1,050,000. These wells produced at an
average production rate of 420 Bbls/d in their initial month of production.
Although horizontal wells typically decline rapidly from their initial
production rates, these twelve wells had an average production rate of 280
Bbls/d for the month of December 1997 and have been producing for an average of
seven months. These horizontal wells typically have a higher internal rate of
return than a comparable vertical well, reduce operating costs per BOE and
reduce the number of wells required to drain the reservoir. The Company plans to
drill over 50 horizontal wells in 1998 in Mississippi.
HEIDELBERG FIELD. Heidelberg field was discovered in 1944 and has produced
an estimated 191 MMBbls and 36 Bcf since its discovery. This Field is a large
salt-cored anticline which is divided by faulting into a western and eastern
half. Production is from a series of normally pressured Cretaceous and Jurassic
sandstone horizons situated between 4,500 feet and 11,500 feet. There are 11
producing formations in the Heidelberg Field containing 44 individual reservoir
intervals, with the majority of the current production coming from the Eutaw and
Christmas sands at depths of approximately 5,000 feet.
The West Heidelberg Eutaw sands have been unitized and water injection
began late in 1996 in order to increase the bottom hole pressure and improve
recoveries from the formation. A production response to the injection is
expected during 1998. The Eutaw East One Fault Block Oil Pool Unit (Eutaw
formation in East Heidelberg) was unitized in October 1997 and injection is
projected to commence in March 1998. These waterflood projects, particularly the
East Unit, comprise a significant portion of the potential reserves at
Heidelberg. The Company has a 78% working interest in the East Unit, 59% of
which was acquired in the Chevron Acquisition and the remaining 19% of which was
acquired over a three-month period from three other entities. The Company
operates a similar Eutaw unit at its East Eucutta Field, located approximately
nine miles to the southeast, with production from sands with similar porosity,
permeability, thickness and drive mechanisms.
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<PAGE> 41
The Company has identified several potential development projects during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 15 wells and recompleting 30
wells in new zones. In addition, the Company has identified over 40 potential
drilling locations in addition to other potential secondary and tertiary
recovery projects. Horizontal wells drilled by the Company in 1997 at nearby
Davis, Quitman and Eucutta Fields improved daily production rates significantly
as compared to vertical wells drilled in the same fields. Consequently, the
Company anticipates that 30 of the 40 proposed future wells will be horizontal
wells. The Company's total 1998 development budget for the Heidelberg Field is
approximately $30 million.
Based on its experience in other fields in the same area, the Company
believes that significant additional reserve potential may exist beyond the
identified proven reserves. The development budget in 1998 and ensuing years is
expected, in part, to be used to evaluate this potential which is summarized
below:
Higher Oil Recovery in the Eutaw Sand Waterfloods. Since discovery of the
Heidelberg Field, total cumulative production in the Eutaw formation through
December 1997 has been 80 MMBbls, which, based upon geological and engineering
analysis, the Company estimates has recovered 22% of the original oil in place.
Based upon a similar analysis, the Company estimates that historical cumulative
production from the Eutaw formation under waterflood at nearby East Eucutta
Field has recovered an estimated 34% of the oil in place. The Company believes
that similar recovery factors may be achievable at Heidelberg Field based on the
geological conditions that appear to be analogous. The Company will also attempt
to improve the recovery factors through the use of horizontal drilling and may
also employ tertiary recovery methods such as carbon dioxide injection. The
Company currently is evaluating the feasibility of such methods.
Higher Oil Recovery in the Christmas Sands. Because of the success of the
Company's horizontal drilling program in other fields in the area, the Company
intends to develop the Christmas sands primarily through horizontal drilling.
Since its discovery, the Christmas sands have produced approximately 67 MMBbls
through December 1997. The Company believes these sands are ideal for horizontal
development due to the strong natural water drive of these reservoirs. Recent
horizontal drilling by the Company has produced oil at faster rates and reduced
operating costs on a BOE basis as compared to vertical drilling. Although
Denbury believes that horizontal drilling should ultimately increase the amount
of oil recovered from the Christmas sands, to date the Company does not have
enough production history to determine if, and to the extent, oil recoveries
will increase.
Further Drilling in Deeper Zones. The zones below the Christmas formation
including the Tuscaloosa, Paluxy, Rodessa, Hosston, Cotton Valley and Smackover
formations, have produced on a cumulative basis a combined 44 MMBbls and 14 Bcf
through December 1997. The Company believes that additional reserve potential
may exist for extensions of existing reservoirs and potential new reservoirs in
these zones within the Heidelberg Field area. A 36-square mile 3-D seismic
program over the field was shot by Chevron in 1993 and will be acquired under
license by Denbury. The Company intends to reprocess the 3-D seismic data to
evaluate this potential.
EUCUTTA FIELD. The Eucutta Field is located about 18 miles east of Laurel,
Mississippi. Since its discovery in 1943, this field has produced 63 MMBbls and
4.7 Bcf. Denbury acquired the majority of its interests in this field as part of
the Hess Acquisition and currently operates 45 producing oil wells and 3
saltwater injection wells. Most of the wells produce oil with large amounts of
saltwater, which requires pumping and disposal.
The Eucutta Field is divided into a shallow Eutaw sand unit in which the
Company has a 78% working interest and the deeper Tuscaloosa, Wash-Fred, Paluxy,
Rodessa, Sligo and Hosston sand zones in which the Company has a 100% working
interest. The Eucutta Field traps oil in multiple sandstone reservoirs from the
Eutaw to the Hosston Formations in this highly faulted anticline from depths of
5,000 to 11,000 feet. Denbury recently established new production in the Paluxy
interval in a series of six stacked sands. Two additional delineation wells have
been drilled and completed for this interval and the Company currently plans to
drill six horizontal wells to fully develop this new area. The deeper intervals
of the Cotton Valley and Smackover formations have yet to be tested in crestal
positions on this structure although these two horizons have proved to be highly
productive throughout the Mississippi Salt Basin.
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<PAGE> 42
Since its acquisition in May 1996, the Company has implemented a capital
expenditure program at Eucutta Field which included upgrading production
facilities, recompletions and drilling wells. At the time of acquisition,
production from this field was approximately 1,100 Bbls/d. All seven wells
drilled in 1997 were successful, two of which were horizontal wells. As a result
of these wells and other development work, during December 1997 the net
production increased to an average of 2,976 Bbls/d. The Company plans to shoot a
3-D seismic survey over the field and have it processed by late 1998. During
1998, the Company also plans to drill 16 wells, of which nine will be horizontal
wells.
DAVIS FIELD. The Davis Field is located 42 miles northeast of Laurel in the
northern part of the Mississippi salt basin. Denbury operates 36 producing wells
within the area. Davis is a compact anticline that has produced over 21 MMBbls
since its discovery by Conoco in 1969. Over 30 sands have produced oil between
the intervals of 5,000 feet and 8,000 feet. At the time of acquisition in 1993,
the gross production from this field was approximately 700 Bbls/d. During the
month of December 1997, the gross production was approximately 960 Bbls/d with
net production of 870 Bbls/d.
The Davis Field is a relatively mature field and produces large amounts of
saltwater. During December 1997, the field produced an average of approximately
53,000 barrels of saltwater per day, all of which were re-injected into the
ground. The Company places considerable emphasis on controlling operating costs
in this field by minimizing the cost of saltwater disposal and pumping
equipment.
Since acquiring the majority of the Davis Field in 1993, Denbury has
undertaken an active redevelopment program including numerous workovers and five
development wells. As a result of this work and continued reductions in
operating costs, the Company has been able to steadily increase the proven
reserves every year. During 1996, the Company drilled two successful horizontal
wells to improve withdrawal efficiency and drilled an additional three
horizontal wells in 1997, with one additional well in progress as of December
31, 1997. The Company plans to drill five wells in this field in 1998 of which
four will be horizontal wells.
QUITMAN FIELD. The Quitman Field is located in Clarke County, Mississippi,
31 miles northeast of Laurel and near the Davis Field. The Company acquired the
field as part of the Hess Acquisition and now operates 18 producing wells. The
Company owns an average working interest of 93%. The Quitman Field was
discovered in 1966 and has since produced approximately 21 MMBbls from 18
separate reservoirs between 7,500 feet and 12,000 feet. The principal producing
zones at Quitman Field are the Smackover formation and several sands in the
Cotton Valley formation.
Since its acquisition in May, 1996, the Company has implemented a capital
expenditure program at Quitman Field which has included upgrading production
facilities and drilling wells. At the time of acquisition, the net production
from this field was approximately 200 Bbls/d. During December 1997, the net
production averaged 1,676 Bbls/d. All five wells drilled in 1997 were
successful, of which two were horizontal wells. During 1998, the Company plans
to drill four wells, of which three will be horizontal wells.
OTHER MISSISSIPPI FIELDS. In addition to the above fields, Denbury owns an
interest in wells in 35 other fields in Mississippi, which in the aggregate
averaged approximately 1,728 Bbls/d and 2.5 MMcf/d of net production during
December 1997.
LOUISIANA OPERATING AREA
The Company's southern Louisiana producing fields are typically large
structural features containing multiple sandstone reservoirs. Current production
depths range from 7,000 feet to 16,000 feet with potential throughout the area
for even deeper production. The region produces predominantly natural gas, with
most reservoirs producing with a water-drive mechanism.
The majority of the Company's southern Louisiana fields lie in the Houma
embayment area of Terrebonne and LaFourche Parishes. The area is characterized
by complex geological structures which have produced prolific reserves, typical
of the lower Gulf Coast geosyncline. Given the swampy conditions of southern
Louisiana, 3-D seismic has only recently become feasible for this area as
improvements in field recording techniques have made the process more
economical. 3-D seismic has become a valuable tool in exploration and
development throughout the onshore Gulf Coast and has been pivotal in
discovering
42
<PAGE> 43
significant reserves. The Company currently owns or has license to work on over
300 square miles of 3-D seismic data and plans to continue to expand its data
ownership. The Company believes that this 3-D seismic data, some of which is the
first 3-D shot in these swampy areas, has the potential to identify significant
exploration prospects, particularly in the deeper geopressured sections below
12,000 feet.
During 1995, the Company acquired approximately 46 square miles of 3-D
seismic data over five of its existing fields in Southern Louisiana, namely
Bayou Rambio, De Large, North Deep Lake, Gibson and Humphreys. During 1996, the
Company entered into a joint venture agreement with two industry partners and
shot approximately 158 square miles of 3-D seismic data in the Terrebonne Parish
area, which includes three of the Company's existing fields, Lirette, Lapeyrouse
and North Lapeyrouse. The Company's existing productive zones are excluded from
the joint venture. Denbury owns a one-third interest in any new prospects
discovered through this joint venture that currently owns rights to over 35,000
acres within the survey area. The 3-D seismic survey is complete and two wells
have been drilled to date based on the results of the survey. One was a dry hole
and the other a successful well in the Lirette Field area. There are currently
10 identified prospect areas which have been generated as a result of the
survey, of which three should be drilled during the first half of 1998. The 3-D
seismic survey is still being reviewed for additional drilling opportunities.
LIRETTE FIELD. The Lirette structure is a large salt-cored anticline
located about 10 miles south of Houma, Louisiana, which has produced over one
Tcf of natural gas from multiple reservoirs. The field is located in six to ten
feet of inland water and produces from depths of 8,000 feet to 16,000 feet. The
field was discovered in 1937, but in 1993, when the Company first acquired a 23%
working interest in the field, gross production had declined to less than 3
MMcf/d. By January 1995, following a series of workovers of existing wells,
gross production had grown to approximately 13.2 MMcf/d and 360 Bbls/d (6.5
MMcf/d and 150 Bbls/d net). Additional interests were acquired in 1995 and 1997
to increase the Company's ownership to its current average 82% working interest.
During December 1997 the net production from this field averaged approximately
10.6 MMcf/d and 179 Bbls/d from 18 wells.
During the latter half of 1996, the Lirette Field was covered by a 3-D
seismic survey which is currently being evaluated. One well was drilled in the
Lirette area in 1997, the Scana No. 1 Laterre, as a result of this 3-D seismic
survey. This well established two pay sands in the prolific Tex W interval a
southern untested fault block. Two additional untested fault blocks have been
identified on the Lirette structure and are scheduled for drilling during 1998.
GIBSON FIELD. In late 1994, Denbury acquired minor working interests in
five wells in the Gibson and adjacent Humphreys Fields located in Terrebonne
Parish, 20 miles northwest of the Lirette Field, in the northern part of the
Houma embayment. The Gibson Field, since its discovery in 1937, has produced
over 813 Bcf and 14 MMBbls. During 1995, the Company acquired and processed 38
square miles of 3-D seismic data covering these fields and in November 1995
acquired a additional working interest in these fields. By December 1995,
Denbury's acreage position had grown to 3,165 net acres with interests in three
active wells and five inactive wells. During December 1997, the net production
in this field averaged approximately 5.4 MMcf/d and 105 Bbls/d. Denbury drilled
two wells in this area in 1997, one of which was successful. This well, the
Pelican A-12, found two productive intervals and was completed in the lower most
formation. This well produced at an average rate of 442 Mcf/d, net to the
Company, during the month of December 1997. No wells are currently planned in
this field for 1998.
SOUTH CHAUVIN FIELD. In February 1996, the Company purchased interests in
two producing wells and four non-producing wells in South Chauvin Field located
in the Houma embayment area, about four miles south of Houma and six miles
northwest of Lirette Field. Of the four currently producing wells at Chauvin,
the Company owns an average 94% working interest. During December 1997, the net
production from this field averaged 4.2 MMcf/d and 85 Bbls/d. In late 1996, the
Company acquired 13.7 square miles of 3-D seismic data covering the field and is
currently evaluating the data. The Company drilled one well in this area in 1997
which produced at an average rate of 2.9 MMcf/d and 72 Bbls/d, net to the
Company, during the month of December 1997. One well, a sidetrack of an existing
well, is currently planned in this field for 1998.
BAYOU RAMBIO FIELD. Production at the Bayou Rambio Field was established in
1955 and has exceeded 150 Bcf and 920 MBbls to date. The Company operates three
producing wells in the field, which is located in
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<PAGE> 44
Terrebonne Parish about 15 miles west of Lirette Field. During December 1997,
the net production from this field averaged 7.0 MMcf/d and 53 Bbls/d. Two of
these producing wells were drilled in 1997 based on a review of 3-D seismic
data. The Company has one additional well planned for the first half of 1998
which will attempt to accelerate the production of the established reserves
increasing the field's PV10 Value, while drilling a deeper sand interval which
may establish additional pay sands.
OTHER LOUISIANA FIELDS. In addition to the above fields, the Company owns
an interest in wells at 39 other fields in Louisiana, which in the aggregate
averaged approximately 14.2 MMcf/d and 959 Bbls/d of net production during
December 1997.
ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES
The Company regularly seeks to acquire properties that complement its
operations, provide exploitation, exploration and development opportunities and
have cost reduction potential. The Company has purchased the majority of its
current producing wells and has increased production by a variety of techniques,
including development drilling, increasing fluid withdrawal and reworking
existing wells. These acquisitions have also balanced the Company's reserve mix
between oil and natural gas, increased the scale of its operations in the
onshore Gulf Coast area and provided the Company with a significant base of
operations within its area of geographic focus. Since 1993, aggregate
expenditures to acquire producing properties are approximately $310 million
through September 30, 1997 adjusted for the Chevron Acquisition. The properties
included in the Company's five largest acquisitions make up approximately 84% of
its total proved reserves on a BOE basis as of December 31, 1997. These five
acquisitions are discussed below in the order of their acquisition by the
Company.
MISSISSIPPI ACQUISITION (1993). Effective May 1, 1993, the Company acquired
interests in the Davis, Frances Creek and Lake Utopia Fields in the Mississippi
salt basin for approximately $9.0 million. At the date of acquisition, the
estimated net proved reserves included 2,170 MBbls and 217 MMcf, aggregating to
2.2 MMBOE. From the date of acquisition through September 30, 1997, the Company
produced 1,377 MBOE from the acquired properties and has successfully increased
its ownership in the Davis Field through approximately $4.3 million of
incremental acquisitions. As of December 31, 1997, the estimated net proved
reserves of the properties totaled 3.1 MMBOE, with a PV10 Value of $15.8
million.
LOUISIANA ACQUISITION (1993). Effective October 1, 1993, Denbury acquired
interests in the Lirette, Bayou Rambio, Delarge, Lapeyrouse, Lake Boeuf, North
Deep Lake and Bay Baptiste Fields in southern Louisiana for approximately $9.8
million. Six of the seven fields are situated in the prolific Houma Embayment,
which is located south of Houma and approximately 40 miles south of New Orleans,
Louisiana. This basin contains fields which have produced more than 2 Tcf of gas
since 1930. These fields have established productive sand intervals as shallow
as 1,000 feet to depths in excess of 17,000 feet, with individual well
production rates exceeding 10 MMcf/d.
At the date of acquisition, the net proved reserves included 155 MBbls and
9,137 MMcf, aggregating to 1.7 MMBOE. From the date of acquisition through
September 30, 1997, the Company produced 2,898 MBOE from the acquired
properties. Subsequent to the acquisition, Denbury has successfully completed
approximately $12.7 million in acquisitions of incremental interests in the
Lirette and Bayou Rambio Fields. As of December 31, 1997, the estimated net
proved reserves of the properties were 7.4 MMBOE, with a PV10 Value of $68.7
million.
GIBSON ACQUISITION (1995). In October 1995, Denbury acquired additional
interests in the Gibson and Humphreys Fields in Southern Louisiana for
approximately $10.2 million. At the date of acquisition, the net proved reserves
included approximately 412 MBbls and 9,435 MMcf, aggregating to 2.0 MMBOE. From
the date of acquisition through September 30, 1997, the Company produced 1,285
MBOE from the acquired properties. As of December 31, 1997, the estimated net
proved reserves of the properties were 1.5 MMBOE, with a PV10 Value of $13.9
million.
HESS ACQUISITION (1996). The Company completed several property
acquisitions during 1996, the largest of which was the acquisition of producing
oil and natural gas properties in Mississippi, Louisiana and
44
<PAGE> 45
Alabama, plus certain overriding royalty interests in Ohio, for approximately
$37.2 million from Amerada Hess, effective May 1, 1996. The average daily
production from the properties included in the Hess Acquisition during May and
June 1996, the first two months of ownership, was approximately 2,945 BOE/d. The
average daily production on these properties had increased to 5,373 BOE/d by the
third quarter of 1997. As of December 31, 1997, in the Company's December
Report, the properties acquired in the Hess Acquisition had estimated net proved
reserves of approximately 14.2 MMBOE with a PV10 Value of $95.0 million. This
compares to approximately 5.9 MMBOE of net proved reserves and a $43.1 million
PV10 Value on these same properties as reported in the July Report. The December
Report was calculated using year-end prices which were based on a WTI price of
$16.18 per Bbl and a NYMEX price of $2.58 per Mcf, with these representative
prices adjusted by field to arrive at the appropriate corporate net price, as
compared to oil and gas prices of $20.00 and $2.65, respectively, in the July
Report. In addition to the increase in proved reserves, the Company produced
approximately 1.9 MMBOE from July 1, 1996 through September 30, 1997 with total
net operating income of $23.8 million.
The two largest fields acquired in the Hess Acquisition are the Eucutta and
Quitman Fields which make up approximately 82% of the total Hess Acquisition
PV10 Value. Both fields are in the same vicinity as the Company's previously
existing Mississippi core properties.
CHEVRON ACQUISITION (1997). On December 30, 1997, the Company acquired oil
properties in the Heidelberg Field, Jasper County, Mississippi, from Chevron for
approximately $202.0 million. The Chevron Acquisition represents the largest
acquisition by the Company to date. The Heidelberg Field is adjacent to the
Company's other primary oil properties in Mississippi and includes 122 producing
wells, 96 of which the Company will operate. The Company purchased an average
working interest of 94% and an average net revenue interest of 81% in these 96
wells, which wells account for approximately 99% of the field's current average
net daily production. The average net daily production from these properties
during the third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed approximately $75.0 million of the purchase price to unevaluated
properties.
The Company has identified several potential development projects during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 15 wells and recompleting 30
wells in new zones. In addition, the Company has identified over 40 potential
drilling locations in addition to other potential secondary and tertiary
recovery projects. Horizontal wells drilled by the Company in 1997 at nearby
Davis, Quitman and Eucutta Fields improved daily production rates significantly
as compared to vertical wells drilled in the same fields. Consequently, the
Company anticipates that 30 of the 40 proposed future wells in the Heidelberg
Field will be horizontal wells. The Company's total 1998 development budget for
the Heidelberg Field is approximately $30.0 million.
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<PAGE> 46
PRODUCTION VOLUMES, SALES PRICES AND PRODUCTION COSTS
The following table summarizes the Company's net oil and natural gas
production volumes, average sales prices and production costs for each of the
years in the three-year period ended December 31, 1996 and for the nine month
periods ended September 30, 1996 and 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------ ---------------------------------
PRO FORMA PRO FORMA
1994 1995 1996 1996(a) 1996 1997 1997(a)
------ ------ ------ --------- -------- -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
NET PRODUCTION VOLUME:
Oil (MBbls)............ 489 728 1,500 2,752 967 2,079 2,873
Natural gas (MMcf)..... 3,326 4,844 8,933 9,178 6,540 9,299 9,459
Oil equivalent (MBOE).. 1,043 1,535 2,989 4,282 2,057 3,629 4,449
AVERAGE SALE PRICES:
Oil ($/Bbl)............ $13.84 $14.90 $18.98 $18.75 $18.05 $17.53 $17.45
Natural gas ($/Mcf).... 1.78 1.90 2.73 2.72 2.64 2.54 2.54
Oil equivalent
($/BOE)............. 12.17 13.05 17.69 17.88 16.87 16.56 16.65
AVERAGE PRODUCTION COSTS:
Per BOE................ $ 4.13 $ 4.42 $ 4.51 $ 4.70 $ 4.47 $ 4.34 $ 4.71
</TABLE>
- ---------------
(a) Pro forma for the Chevron Acquisition. See "-- Acquisitions of Oil and
Natural Gas Properties" and "Unaudited Pro Forma Consolidated Financial
Information."
OIL AND NATURAL GAS ACREAGE
The following table sets forth the Company's acreage position as of
December 31, 1996:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
--------------- ---------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Louisiana........................................... 29,328 20,374 10,137 7,812
Mississippi......................................... 17,511 11,138 19,180 8,002
Other............................................... 1,710 1,260 1,709 722
------ ------ ------ ------
Total..................................... 48,549 32,772 31,026 16,536
====== ====== ====== ======
</TABLE>
The following table sets forth the Company's acreage position as of
September 30, 1997:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
--------------- ---------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Louisiana........................................... 28,519 19,870 20,542 10,668
Mississippi......................................... 17,102 12,655 27,185 10,970
------ ------ ------ ------
Total..................................... 45,621 32,525 47,727 21,638
====== ====== ====== ======
</TABLE>
PRODUCTIVE WELLS
The following table sets forth the Company's gross and net productive wells
as of December 31, 1996:
<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS WELLS TOTAL
------------- ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Louisiana................................... 44 24.8 66 38.1 110 62.9
Mississippi................................. 142 106.0 28 14.8 170 120.8
Other....................................... 4 2.0 12 5.3 16 7.3
--- ----- --- ---- --- -----
Total............................. 190 132.8 106 58.2 296 191.0
=== ===== === ==== === =====
</TABLE>
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<PAGE> 47
The following table sets forth the Company's gross and net productive wells
as of September 30, 1997:
<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS WELLS TOTAL
------------- ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Louisiana................................... 40 25.7 70 43.2 110 68.9
Mississippi................................. 154 132.5 21 7.2 175 139.7
--- ----- --- ---- --- -----
Total............................. 194 158.2 91 50.4 285 208.6
=== ===== === ==== === =====
</TABLE>
DRILLING ACTIVITY
The following table sets forth the results of drilling activities during
each of the three years in the period ended December 31, 1996 and the nine
months ended September 30, 1997. No wells were in the process of drilling at
September 30, 1997.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
----------------------------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------------- ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EXPLORATORY WELLS:
Productive..................... -- -- -- -- -- -- 2 0.8
Nonproductive.................. 3 0.8 2 1.0 1 1.0 5 2.4
DEVELOPMENT WELLS:
Productive..................... 4 2.9 2 1.5 9 7.9 26 22.7
Nonproductive.................. 1 1.0 -- -- -- -- 2 1.1
---- ---- ---- ---- ---- ---- ---- ----
Total.................. 8 4.7 4 2.5 10 8.9 35 27.0
==== ==== ==== ==== ==== ==== ==== ====
</TABLE>
PRODUCT MARKETING
Denbury's production is primarily from developed fields close to major
pipelines or refineries and established infrastructure. As a result, Denbury has
not experienced any difficulty in finding a market for its product as it becomes
available or in transporting its product to these markets.
OIL MARKETING. Denbury markets its oil to a variety of purchasers, most of
which are large, established companies. The oil is generally sold under a
short-term contract with the sales price based on an applicable posted price,
plus a negotiated premium. This price is determined on a well-by-well basis and
the purchaser generally takes delivery at the wellhead. Mississippi oil, which
accounted for approximately 73% of the Company's oil production in 1996, is
primarily light sour crude and sells at a discount to the published WTI posting.
The balance of the oil production, Louisiana oil, is primarily light sweet
crude, which typically sells at a slight premium to the WTI posting.
The Company is currently selling a majority of its oil under a two-year
contract to Hunt Refining which expires on April 1998 and is currently receiving
a premium to the posted price in this contract. The Company may not be able to
renew this contract in the future or may not be able to obtain terms as
favorable as those in the existing contract.
NATURAL GAS MARKETING. Virtually all of Denbury's natural gas production is
close to existing pipelines and consequently, the Company generally has a
variety of options to market its natural gas. The Company sells the majority of
its natural gas on one year contracts with prices fluctuating month-to-month
based on published pipeline indices with slight premiums or discounts to the
index.
PRODUCTION PRICE HEDGING. For 1995, the Company entered into financial
contracts to hedge 75% of the Company's net natural gas production and 43% of
the Company's net oil production. The net effect of these hedges was to increase
oil and natural gas revenues by approximately $750,000 during 1995. The Company
does not currently have any hedging contracts in place, although it may enter
into such contracts in the future.
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<PAGE> 48
SIGNIFICANT OIL AND NATURAL GAS PURCHASERS
Oil and natural gas sales are made on a day-to-day basis under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon the Company's operations. For
the period ended December 31, 1996, the Company sold 10% or more of its net
production of oil and natural gas to the following purchasers: Natural Gas
Clearinghouse (20%), Penn Union Energy Services (19%), Enron Trading &
Transportation (13%) and Hunt Refining (15%).
TITLE TO PROPERTIES
Customarily in the oil and natural gas industry, only a perfunctory title
examination is conducted at the time properties believed to be suitable for
drilling operations are first acquired. Prior to commencement of drilling
operations, a thorough drill site title examination is normally conducted and
curative work is performed with respect to significant defects. During
acquisitions, title reviews are performed on all properties; however, formal
title opinions are obtained on only the higher value properties. The Company
believes that it has good title to its oil and natural gas properties, some of
which are subject to minor encumbrances, easements and restrictions.
COMPETITION
The oil and natural gas industry is highly competitive in all its phases.
The Company encounters strong competition from many other energy companies in
acquiring economically desirable producing properties and drilling prospects and
in obtaining equipment and labor to operate and maintain its properties. In
addition, many energy companies possess greater resources than the Company. See
"Risk Factors -- Competition."
GEOGRAPHIC SEGMENTS
All of the Company's operations are in the United States.
OFFICE AND FIELD FACILITIES
The Company leases its executive and administrative offices in Dallas,
Texas, consisting of approximately 25,000 square feet, under a lease that
continues through May 1999. On August 6, 1997, the Company entered into a ten
year office lease for approximately 50,000 square feet to replace its current
corporate headquarters. This new lease is expected to commence late in 1998.
EMPLOYEES
At January 15, 1998, the Company had 183 employees associated with its
operations, including 69 field personnel in Mississippi and 35 field personnel
in Louisiana. None of the Company's employees is represented by a union. The
Company considers its employee relations to be satisfactory.
LEGAL PROCEEDINGS
From time to time, the Company is a party to legal proceedings in the
ordinary course of its business, including actions for personal injury and
property damage occurring as a result of the operation of wells, and claims for
environmental damage. In June of 1997, a well blow-out occurred at the Lake
Chicot Field, for which the Company is operator, in St. Martin Parish, Louisiana
in which four individuals that were employees of other third party entities were
killed, none of whom were employees or contractors of the Company. In connection
with this blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al
.v. Mallard Bay Drilling L.L.C., Parker Drilling Company and Denbury Management,
Inc., Case No. 58226-G in the 16th Judicial District Court in St. Martin Parish,
Louisiana alleging various defective and dangerous conditions violation of
certain rules and regulations and acts of negligence. The Company believes that
all litigation to which it is a party is covered by insurance and none of such
legal proceedings can be reasonably expected to have a material adverse effect
on the Company's financial condition or results of operations. See "Risk
Factors -- Drilling and Operating Risks."
48
<PAGE> 49
REGULATIONS
The availability of a ready market for oil and gas production depends upon
numerous factors beyond the Company's control. These factors include regulation
of natural gas and oil production, federal and state regulations governing
environmental quality and pollution control, state limits on allowable rates of
production by well or proration unit, the amount of natural gas and oil
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
State and federal regulations generally are intended to prevent waste of natural
gas and oil, protect rights to produce natural gas and oil between owners in a
common reservoir, control the amount of natural gas and oil produced by
assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies. The following discussion summarizes the regulation of the
United States oil and gas industry and is not intended to constitute a complete
discussion of the various statutes, rules, regulations and governmental orders
to which the Company's operations may be subject.
REGULATION OF NATURAL GAS AND OIL EXPLORATION AND PRODUCTION. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for drilling wells,
maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in and the unitization or pooling of oil and gas properties. In
addition, state conservation laws establish maximum rates of production from oil
and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and gas the Company can produce from its
wells and may limit the number of wells or the locations at which the Company
can drill. Each state generally imposes a production or severance tax with
respect to production and sale of crude oil, natural gas and natural gas liquids
within their respective jurisdictions. The regulatory burden on the oil and gas
industry increases the Company's costs of doing business and, consequently,
affects its profitability. Inasmuch as such laws and regulations are frequently
expanded, amended and reinterpreted, the Company is unable to predict the future
cost or impact of complying with such regulations.
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Federal
legislation and regulatory controls in the U.S. have historically affected the
price of the natural gas produced by the Company and the manner in which such
production is marketed. The Federal Energy Regulatory Commission (the "FERC")
regulates the interstate transportation and sale for resale of natural gas by
interstate and intrastate pipelines. The FERC previously regulated the maximum
selling prices of certain categories of gas sold in "first sales" in interstate
and intrastate commerce under the Natural Gas Policy Act. Effective January 1,
1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas, which
includes all sales by the Company of its own production. As a result, all sales
of the Company's domestically produced natural gas may be sold at market prices,
unless otherwise committed by contract. The FERC's jurisdiction over natural gas
transportation and gas sales other than first sales was unaffected by the
Decontrol Act.
The Company's natural gas sales are affected by the regulation of
intrastate and interstate gas transportation. In an attempt to restructure the
interstate pipeline industry with the goal of providing enhanced access to, and
competition among, alternative natural gas supplies, the FERC, commencing in
April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have
altered significantly the interstate transportation and sale of natural gas.
Among other things, Order No. 636 required interstate pipelines to unbundle the
various services that they had provided in the past, such as sales, transmission
and storage, and to offer these services individually to their customers. By
requiring interstate pipelines to "unbundle" their services and to provide their
customers with direct access to pipeline capacity held by them, Order No. 636
has enabled pipeline customers to choose the levels of transportation and
storage service they require, as well as to purchase natural gas directly from
third-party merchants other than the pipelines and obtain
49
<PAGE> 50
transportation of such gas on a non-discriminatory basis. The effect of Order
No. 636 has been to enable the Company to market its natural gas production to a
wider variety of potential purchasers. The Company believes that these changes
generally have improved the Company's access to transportation and have enhanced
the marketability of its natural gas production. To date, Order No. 636 has not
had any material adverse effect on the Company's ability to market and transport
its natural gas production. However, the Company cannot predict what new
regulations may be adopted by the FERC and other regulatory authorities, or what
effect subsequent regulations may have on the Company's activities. In addition,
Order No. 636 and a number of related orders were appealed. Recently, the United
States Court of Appeals for the District of Columbia Circuit issued an opinion
largely upholding the basic features and provision of Order No. 636. However,
even though Order No. 636 itself has been judicially approved, several related
FERC orders remain subject to pending appellate review and further changes could
occur as a result of court order or at the FERC's own initiative.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate natural gas
pipeline-owned gathering facilities to pipeline affiliates, (ii) the completion
of a rulemaking involving the regulation of interstate natural gas pipelines
with marketing affiliates under Order No. 497, (iii) FERC's on-going efforts to
promulgate standards for pipeline electronic bulletin boards and electronic data
exchange, (iv) a generic inquiry into the pricing of interstate pipeline
capacity, (v) efforts to refine FERC's regulations controlling the operation of
the secondary market for released interstate natural gas pipeline capacity, and
(vi) a policy statement regarding market-based rates and other non-cost-based
rates for interstate pipeline transmission and storage capacity. Several of
these initiatives are intended to enhance competition in natural gas markets.
While any resulting FERC action would affect the Company only indirectly, the
ongoing, or, in some instances, preliminary evolving nature of these regulatory
initiatives makes it impossible at this time to predict their ultimate impact
upon the Company's activities.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. Commencing in October 1993, the FERC has modified its regulation
of oil pipeline rates and services in order to comply with the Energy Policy Act
of 1992. That Act mandated that FERC streamline oil pipeline ratemaking by
abandoning its old, cumbersome procedures and issue new procedures to be
effective January 1, 1995. In response, the FERC issued a series of rules (Order
Nos. 561 and 561-A) establishing an indexing system under which oil pipelines
will be able to change their transportation rates, subject to prescribed ceiling
levels. The FERC's new oil pipeline ratemaking methodology was recently affirmed
by the Court. The Company is not able at this time to predict the effects of
Order Nos. 561 and 561-A, if any, on the transportation costs associated with
oil production from the Company's oil producing operations.
GATHERING REGULATIONS. Under the Natural Gas Act (the "NGA"), facilities
used for and operations involving the production and gathering of natural gas
are exempt from FERC jurisdiction, while facilities used for and operations
involving interstate transmission are not. Under current law even facilities
which otherwise would have been classified as gathering may be subject to the
FERC's rate and service jurisdiction when owned by an interstate pipeline
company and when such regulation is necessary in order to effectuate FERC's
Order No. 636 open-access initiatives. FERC has reaffirmed that it does not have
jurisdiction over natural gas gathering facilities and services and that such
facilities and services are properly regulated by state authorities. As a
result, natural gas gathering may receive greater regulatory scrutiny by state
agencies. In addition, the FERC has approved several transfers by interstate
pipelines of gathering facilities to unregulated gathering companies, including
affiliates. This could allow such companies to compete more effectively with
independent gatherers.
State regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements.
While some states provide for the rate regulation of pipelines engaged in the
intrastate transportation of natural gas, such regulation has not generally been
applied against gatherers of natural gas. Natural gas gathering may receive
greater regulatory scrutiny following the pipeline industry restructuring under
Order No. 636. Thus the Company's gathering operations could be
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<PAGE> 51
adversely affected should they be subject in the future to the application of
state or federal regulation of rates and services. See "Risk
Factors -- Governmental and Environmental Regulation."
ENVIRONMENTAL REGULATIONS. The Company's operations are subject to numerous
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years. The
trend of more expansive and stricter environmental legislation and regulations
could continue. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes environmental protection requirements
that result in increased costs to the oil and gas industry in general, the
business and prospects of the Company could be adversely affected.
The EPA and various state agencies have limited the approved methods of
disposal for certain hazardous and nonhazardous wastes. Certain wastes generated
by the Company's oil and natural gas operations that are currently exempt from
treatment as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Most of
these properties have been operated by prior owners, operators and third parties
whose treatment and disposal or release of hydrocarbons or other wastes was not
under the Company's control. These properties and the wastes disposed thereon
may be subject to Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), Federal Resource Conservation and Recovery Act and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Certain provisions of CAA may result in
the gradual imposition of certain pollution control requirements with respect to
air emissions from the operations of the Company. The EPA and states have been
developing regulations to implement these requirements. The Company may be
required to incur certain capital expenditures in the next several years for air
pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues.
However, the Company does not believe its operations will be materially
adversely affected by any such requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from a spill, including but not
limited to, the costs of responding to a release of oil to surface waters.
Regulations are currently being developed under the OPA and state laws
concerning oil pollution prevention and other matters that may impose additional
regulatory burdens on the Company.
The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as nonhazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or modification of this exemption by administrative, legislative or judicial
process, or through changes in applicable state statutes, would increase the
volume of hazardous waste to be managed and disposed of by the Company.
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Any such
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<PAGE> 52
change in the applicable statues may require the Company to make additional
capital expenditures or incur increased operating expenses.
Some states have enacted statutes governing the handling, treatment,
storage and disposal of naturally occurring radioactive material ("NORM"). NORM
is present in varying concentrations in subsurface and hydrocarbon reservoirs
around the world and may be concentrated in scale, film and sludge in equipment
that comes in contact with crude oil and natural gas production and processing
streams. Mississippi legislation prohibits the transfer of property for
residential or other unrestricted use if the property contains NORM above
prescribed levels.
The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to the protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
the Company. See "Risk Factors -- Governmental and Environmental Regulation."
TAXATION
Since all of the Company's oil and natural gas operations are located in
the United States, the Company's primary tax concerns relate to U.S. tax laws,
rather than Canadian tax laws. Certain provisions of the United States Internal
Revenue Code of 1986, as amended, are applicable to the petroleum industry.
Current law permits the Company to deduct currently, rather than capitalize,
intangible drilling and development costs ("IDC") incurred or borne by it. The
Company, as an independent producer, is also entitled to a deduction for
percentage depletion with respect to the first 1,000 barrels per day of domestic
crude oil (and/or equivalent units of domestic natural gas) produced by the
Company (if such percentage of depletion exceeds cost depletion). Generally,
this deduction is 15% of gross income from an oil and natural gas property,
without reference to the taxpayer's basis in the property. Percentage depletion
can not exceed the taxable income from any property (computed without allowance
for depletion), and is limited in the aggregate to 65% of the Company's taxable
income. Any depletion disallowed under the 65% limitation, however, may be
carried over indefinitely. For additional tax disclosures, see Note 4 of the
Consolidated Financial Statements.
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<PAGE> 53
MANAGEMENT
The names of the directors and officers of the Company, their ages, the
offices held by them with the Company and the periods during which such offices
have been held are set forth below. Each officer and director holds office for
one year or until his death, resignation or removal or until his successor is
duly elected and qualified. The officers set forth below hold the same position
in both DRI and DMI unless otherwise noted.
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
Ronald G. Greene(a)(b)(c)(d)................ 48 Chairman of the Board of DRI
Wilmot L. Matthews(a)....................... 61 Director of DRI
William S. Price, III(b)(c)(d).............. 40 Director of DRI
David M. Stanton............................ 34 Director of DRI
Wieland F. Wettstein(a)..................... 47 Director of DRI
David Bonderman............................. 54 Director of DRI
Gareth Roberts.............................. 45 President, Chief Executive Officer and
Director of DRI and DMI
Matthew Deso................................ 44 Vice President, Exploration and Director
of DMI
Phil Rykhoek................................ 41 Chief Financial Officer and Secretary and
Director of DMI
Mark A. Worthey............................. 40 Vice President, Operations and Director of
DMI
Bobby J. Bishop............................. 37 Controller and Chief Accounting Officer
Ron Gramling................................ 52 President of DMI marketing subsidiary
Lynda Perrard............................... 54 Vice President, Land of DMI
</TABLE>
- ---------------
(a) Member of the Audit Committee.
(b) Member of the Compensation Committee.
(c) Member of the Stock Option Plan Committee.
(d) Member of the Stock Purchase Plan Committee.
Ronald G. Greene is the Chairman of the Board, and has been a director of
the Company since 1995. Mr. Greene is the founder and Chairman of the Board of
Renaissance Energy Ltd. and was Chief Executive Officer of Renaissance from its
inception in 1974 until May 1990. He is also the sole shareholder, officer and
director of Tortuga Investment Corp., a private investment company. Mr. Greene
also serves on the Board of Directors of a private Western Canadian airline.
Wilmot L. Matthews was first elected as director of the Company on December
9, 1997. Mr. Matthews, a Chartered Accountant, has been involved in all aspects
of investment banking by serving in various positions with Nesbitt Burns Inc.
and its predecessor companies from 1964 until his retirement in September 1996,
most recently as Vice Chairman and Director. Mr. Matthews is currently President
of Marjad Inc., a personal investment company, and also serves on the Board of
Directors of Renaissance Energy Ltd. and several private companies.
William S. Price, III has been a director of the Company since 1995. Mr.
Price is a co-founder and principal of TPG. Prior to forming TPG in 1992, Mr.
Price was vice-president of strategic planning and business development for G.E.
Capital, and from 1985 to 1991 was employed by the management consulting firm of
Bain & Company, attaining officer status and acting as co-head of the Financial
Services practice. Mr. Price is Chairman of the Board of Favorite Brands
International, Inc. and Co-Chairman of the Board of Beringer Wine Estates. Mr.
Price also serves on the Board of Directors of Continental Airlines, Inc.,
Continental Micronesia, Inc., VSP Holdings, Inc., Belden & Blake Corporation and
Del Monte Foods.
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<PAGE> 54
David M. Stanton has been a director of the Company since 1995. Mr. Stanton
is a managing director of TPG. From 1991 until he joined TPG in 1994, Mr.
Stanton was a venture capitalist with Trinity Ventures where he specialized in
information technology, software and telecommunications investments. Mr. Stanton
also serves on the Board of Directors of TPG Communications, Inc., Paradyne
Partners, L.P. and Belden & Blake Corporation.
Wieland F. Wettstein has been a director of the Company since 1990. Mr.
Wettstein is the Executive Vice President of, and indirectly controls 50% of,
Finex Financial Corporation Ltd., a merchant banking company in Calgary,
Alberta, a position he has held for more than five years. Mr. Wettstein serves
on the Board of Directors of a public oil and natural gas company, BXL Energy,
and on the Board of Directors of a private technology firm.
David Bonderman has been a director of the Company since 1996. Mr.
Bonderman is a co-founder and principal of TPG. Prior to forming TPG in 1992,
Mr. Bonderman was the Chief Operating Officer of the Robert M. Bass Group, Inc.
(now doing business as Keystone, Inc.), joining them in 1983. Keystone, Inc. is
the personal investment vehicle of Fort Worth, Texas-based investor Robert M.
Bass. Mr. Bonderman serves on the boards of Continental Airlines; Inc.; Beringer
Wine Estates; Credicom Asia; Bell & Howell Company; Ryanair, Limited; Virgin
Cinemas, Limited; Ducati Motors S.P.A.; and Washington Mutual, Inc.
Gareth Roberts -- President, Chief Executive Officer and a Director, is the
founder of DMI, which was founded in April 1990. Mr. Roberts has more than 20
years of experience in the exploration and development of oil and natural gas
properties with Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc.
His expertise is particularly focused in the Gulf Coast region where he
specializes in the acquisition and development of old fields with low
productivity. Mr. Roberts holds honors and masters degrees in Geology and
Geophysics from St. Edmund Hall, Oxford University. Mr. Roberts also serves on
the Board of Directors of Belden & Blake Corporation.
Matthew Deso -- Vice President, Exploration, has been with the Company
since October 1990, first as a consultant then, when he moved to Dallas in
January 1994, as Vice President of Exploration, his current position. Mr. Deso
has twenty years of petroleum geology experience, and received a Bachelor of
Science in Geosciences from the University of Texas in 1976. Mr. Deso also
worked for Enserch Exploration (three years), Terra Resources (three years) and
TXO Production Corp. (eight years) in positions of varying responsibility.
Phil Rykhoek -- Chief Financial Officer, a Certified Public Accountant,
joined the Company and was appointed to the position of Chief Financial Officer
and Secretary in June 1995. Prior to joining the Company, Mr. Rykhoek was
Executive Vice President and co-founder of Petroleum Financial, Inc., a private
company formed in May 1991 to provide oil and natural gas accounting services on
a contract basis to other entities. From 1982 to 1991 (except for 1986), Mr.
Rykhoek was employed by Amerac Energy Corporation (formerly Wolverine
Exploration Company), most recently as Vice President and Chief Accounting
Officer. He retained his officer status during his tenure at Petroleum
Financial, Inc.
Mark A. Worthey -- Vice President, Operations, is a geologist and is
responsible for all aspects of operations in the field. He joined the Company in
September 1992. Previously, he was with Coho Resources, Inc. as an exploitation
manager, beginning his employment there in 1985. Mr. Worthey graduated from
Mississippi State University with a Bachelor of Science degree in petroleum
geology in 1984.
Bobby J. Bishop -- Controller and Chief Accounting Officer, a Certified
Public Accountant, joined the Company as Controller in August 1993 and was
appointed to the position of Chief Accounting Officer in December, 1997. Prior
to joining the Company, Mr. Bishop was the Chief Financial Officer for Arcadia
Exploration and Production Company, a private company. He also worked for Lake
Ronel Oil Company and TXO Production Corp. Mr. Bishop graduated from the
University of Oklahoma with a Bachelor of Business Administration in Accounting
in 1983.
Ron Gramling -- President of DRI's marketing subsidiary, joined the Company
in May 1996 when the Company purchased the subsidiary's assets. Prior to
becoming affiliated with the Company, he was employed by Hadson Gas Systems as
Vice President of term supply. Mr. Gramling has 27 years of marketing,
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<PAGE> 55
transportation and supply experience in the natural gas and crude oil industry.
He received his Bachelor of Business Administration degree from Central State
University, Edmond, Oklahoma in 1970.
Lynda Perrard -- Vice President, Land of DMI, joined the Company in April
1994. Ms. Perrard has over 30 years of experience in the oil and gas industry as
a petroleum landman. Prior to joining the Company, Ms. Perrard was the President
and Chief Executive Officer of Perrard Snyder, Inc., a corporation performing
contract land services. Ms. Perrard also served as Vice President, Land for
Snyder Exploration Company from 1986 to 1991.
As part of the Securities Purchase Agreement that governed the TPG's
initial investment in the Company, TPG has the right to designate three of seven
nominees to serve on the Board of Directors of the Company. It was also intended
by the parties to the agreement that Mr. Ronald G. Greene would be nominated to
serve as one of the seven directors and that the remaining three directors would
be nominated by the Company. TPG will forfeit its right to designate one of the
directors that it would otherwise be entitled to designate if at any time TPG
owns securities of the Company representing less than 30% of the outstanding
Common Shares, calculated on a fully-diluted basis. TPG shall forfeit its right
to designate any director if at any time TPG's share holdings represent less
than 20% of the outstanding Common Shares, calculated on a fully-diluted basis.
Currently, Messrs. Stanton, Bonderman and Price are the directors of the Company
nominated by TPG.
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<PAGE> 56
PRINCIPAL SHAREHOLDERS
The following table sets forth information, as of December 31, 1997,
concerning beneficial ownership of the Common Shares before and after giving
effect to the Transactions for: (i) any shareholders known to the Company to
beneficially own more than 5% of the issued and outstanding Common Shares; and
(ii) all executive officers and directors individually and as a group. Except as
otherwise indicated and except for those Common Shares that are listed as being
beneficially owned by more than one shareholder, each shareholder identified in
the table has sole voting and investment power with respect to their Common
Shares.
<TABLE>
<CAPTION>
BENEFICIAL
OWNERSHIP
BENEFICIAL OWNERSHIP AS OF AFTER THE
DECEMBER 31, 1997 TRANSACTIONS
-------------------------- ------------
NAME AND ADDRESS OF BENEFICIAL OWNER SHARES PERCENT PERCENT
------------------------------------ ------------ --------- ------------
<S> <C> <C> <C>
Ronald G. Greene................................. 900,900(a) 4.4%(a) 3.6%(a)
Suite 700, 407 -- 2nd Street
Calgary, Alberta T2P 2Y3
David Bonderman.................................. 8,658,038(b) 41.2%(b) 34.7%(b)
201 Main Street, Suite 2420
Ft. Worth, TX 76102
Wilmot L. Matthews............................... 156,250(c) * *
1 First Canadian Place, Suite 5101
Toronto, ON M5X 1E3
William S. Price, III............................ 8,411,038(d) 40.0%(d) 33.7%(d)
600 California Street, Suite 1850
San Francisco, CA 94108
David M. Stanton................................. 2,000(e) * *
Wieland F. Wettstein............................. 83,389(f) * *
Gareth Roberts................................... 498,302(g) 2.4%(g) 2.0%(g)
Phil Rykhoek..................................... 4,422(h) * *
Mark A. Worthey.................................. 79,001(h) * *
Matthew Deso..................................... 25,801(h) * *
Bobby J. Bishop.................................. 2,439 * *
All of the executive officers and directors as a
group (11 persons)............................. 10,413,542(i) 49.3%(i) 41.3%(i)
TPG Advisors, Inc................................ 8,408,038(j) 40.0%(j) 33.7%(j)
201 Main Street, Suite 2420
Ft. Worth, TX 76102
</TABLE>
- ---------------
* Less than 1%.
(a) Includes 30,150 Common Shares held by Mr. Greene's spouse in her retirement
plan, 900 shares held in trust for Mr. Greene's minor children and 520,833
Common Shares held by Tortuga Investment Corp., which is solely owned by
Mr. Greene.
(b) Includes 250,000 Common Shares in a family partnership 100% controlled by
Mr. Bonderman and 625,000 Common Share purchase warrants held by TPG which,
for purposes of this disclosure, are assumed to be exercised. These
warrants were exercised on January 20, 1998. Mr. Bonderman is a director,
executive officer and shareholder of TPG Advisors, Inc., which is the
general partner of TPG GenPar, L.P., which in turn is the general partner
of both TPG Partners, L.P., and TPG Parallel I, L.P., which are the direct
beneficial owners of the remaining securities attributed to Mr. Bonderman.
Mr. Bonderman's beneficial ownership after the Transactions includes the
Common Shares purchased by TPG in the TPG Purchase.
(c) Includes 52,300 Common Shares held by a subsidiary of Marjad Inc., which is
wholly owned by Mr. Matthews, 2,450 Common Shares held in various trusts of
which Mr. Matthews is a trustee and an
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<PAGE> 57
income beneficiary and 1,500 Common Shares as to which Mr. Matthews holds a
power of attorney but no beneficial interest.
(d) Includes 1,000 Common Shares held by Mr. Price and 2,000 Common Shares held
by Mr. Price's spouse and 625,000 Common Share purchase warrants held by
TPG which, for purposes of this disclosure, are assumed to be exercised.
These warrants were exercised on January 20, 1998. Mr. Price is a director,
executive officer and shareholder of TPG Advisors, Inc., which is the
general partner of TPG GenPar, L.P., which in turn is the general partner
of both TPG Partners, L.P., and TPG Parallel I, L.P., which are the direct
beneficial owners of the remaining securities attributed to Mr. Price. Mr.
Price's beneficial ownership after the Transactions includes the Common
Shares purchased by TPG in the TPG Purchase.
(e) Although Mr. Stanton is not considered to be a "beneficial owner" as that
term is defined by the Commission, Mr. Stanton is a managing director of
TPG.
(f) Includes 76,439 Common Shares held by S.P. Hunt Holdings Ltd., which is
solely owned by a trust of which Mr. Wettstein is a trustee.
(g) Includes 138,330 Common Shares held by a corporation, which is solely owned
by Mr. Roberts, 38,000 Common Shares held in a private charitable
foundation which he and his wife control, and 2,228 Common Shares held by
his wife.
(h) Includes 1,875, 73,250 and 17,500 Common Shares which Mr. Rykhoek, Mr.
Worthey and Mr. Deso, respectively, have the right to acquire pursuant to
stock options which are currently vested or which vest within 60 days of
December 31, 1997.
(i) Includes 92,625 Common Shares which the officers and directors as a group
have the right to acquire pursuant to stock options which are currently
vested or which vest within 60 days of December 31, 1997 and 625,000
Common Share purchase warrants held by TPG which, for purposes of this
disclosure, are assumed to be exercised. These warrants were exercised on
January 20, 1998. Beneficial ownership does include the Common Shares held
by affiliates of TPG, although Mr. Price and Mr. Bonderman, who are
directors of the Company, are not the owners of record of these
securities. Mr. Price and Mr. Bonderman are directors, executive officers
and shareholders of TPG Advisors, Inc., which is the general partner of
TPG GenPar, L.P., which in turn is the general partner of both TPG
Partners, L.P. and TPG Parallel I, L.P., which are the direct beneficial
owners of these securities. The beneficial ownership after the
Transactions of the directors and executive officers as a group includes
the Common Shares purchased by TPG in the TPG Purchase.
(j) Includes 625,000 Common Share purchase warrants held by TPG which, for
purposes of this disclosure, are assumed to be exercised. These warrants
were exercised on January 20, 1998.
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<PAGE> 58
INTERESTS OF MANAGEMENT IN CERTAIN TRANSACTIONS
Other than as described in the paragraphs that follow, there are no
material interests, direct or indirect, of any director, officer or any
shareholder of the Company who beneficially owns, directly or indirectly, or
exercises control or direction over more than 5% of the outstanding Common
Shares, or any known family member, associate or affiliate of such persons,
participating in any transaction within the last three years or in any proposed
transaction that has materially affected or would materially affect the Company,
or any of its subsidiaries. The Company believes that the terms of the
transactions described below were as favorable to the Company as terms that
reasonably could have been obtained from non-affiliated third parties.
TPG INVESTMENTS
In December 1995, the Company closed a $40.0 million private placement of
securities with partnerships that are affiliated with TPG (the "TPG Placement").
The TPG Placement was comprised of: (i) 4.2 million Common Shares issued at
$5.85 per share; (ii) 625,000 warrants at a price of $1.00 per warrant,
entitling the holders thereof to purchase 625,000 Common Shares at $7.40 per
share; and (iii) 1.5 million shares of $10 stated value Convertible First
Preferred Shares, Series A (the "Convertible Preferred"). The shareholders of
the Company at a Special Meeting on October 9, 1996 approved a resolution to
amend the terms of the Convertible Preferred to allow the Company to require a
conversion of the Convertible Preferred at any time. All of the Convertible
Preferred shares were converted into 2,816,372 Common Shares on October 30,
1996. As per the terms of the warrants, the Company is allowed to force
conversion of the warrants after December 21, 1997 if the price of the Common
Shares exceeds $10.00 per share for a period of 40 consecutive trading days. As
of December 31, 1997, TPG is the beneficial owner of 7,783,038 Common Shares,
which represents 38% of the outstanding Common Shares (40% after the exercise of
the warrants on January 20, 1998).
In connection with the TPG Placement, TPG received the right to nominate
three of the directors of the Company out of a maximum of seven. Of the current
directors, Messrs. Bonderman, Price and Stanton were nominated by TPG. See
"Management." In addition, until December 21, 1997, TPG had certain "piggyback"
registration rights which allowed TPG to include all or part of the Common
Shares acquired by TPG in any registration statement of the Company during that
period. Commencing December 21, 1997 and until December 21, 2000, TPG may
request and receive one demand registration whereby TPG may make a written
request to the Company for registration under the Securities Act of the Common
Shares acquired by TPG. Finally, the agreement provides that TPG shall have the
right, but not the obligation, to maintain its pro rata ownership interest in
the equity securities of the Company, in the event that the Company issues any
additional equity securities or securities convertible into Common Shares of the
Company, by purchasing additional securities of the Company on the same terms
and conditions. This right, however, expires should TPG's share holdings
represent less than 20% of the outstanding Common Shares calculated on a
fully-diluted basis. At the request of the NYSE, the Company has agreed to make
the extension of this right subject to shareholder ratification every five years
with the first vote on the matter expected to be at the annual meeting in the
year 2000. TPG waived its right to maintain its pro rata ownership with regard
to the public offering by the Company in October 1996, but did purchase 800,000
Common Shares included in the offering directly from the Company. These Common
Shares were sold for 93.5% of the public offering price, or the same net price
that the remainder of the shares included in the offering were being sold to the
underwriters. TPG has waived its right to maintain its pro rata ownership with
regard to the Equity Offering but is planning to purchase 313,400 shares in the
TPG Purchase at 95.25% of the public offering price, or the same net price that
the remainder of the shares included in the Equity Offering are being sold to
the Underwriters. As of December 31, 1997, after giving pro forma effect to the
Transactions, TPG will be the beneficial owner of 8,721,438 Common Shares, which
represents 34% of the outstanding Common Shares.
In 1995, the Company issued 333,333 Common Shares to Tortuga Investment
Corp. as a financial advisory fee for its services in connection with the TPG
Placement. Tortuga Investment Corp. is a corporation wholly owned by Mr. Ronald
Greene, currently Chairman of the Board of Directors of the Company. Mr. Greene
was not a director of the Company, nor had he held any director or officer
position with the Company, prior to the time of the issuance of such Common
Shares.
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<PAGE> 59
MODIFICATION OF DEBENTURES
In addition to modifying the terms of the Convertible Preferred at the
special meeting of the shareholders on October 9, 1996, the shareholders
approved the issuance of 7,948 Common Shares in lieu of interest, plus an
additional 308,642 Common Shares to redeem the principal amount of the
outstanding 9.5% Convertible Debentures (the "Debentures") in accordance with
their existing terms. Mr. Ronald G. Greene, Chairman of the Board of Directors,
owned 80% of the Debentures, which were purchased by him at market value prior
to his election to the Board of Directors. These Debentures were redeemed on
October 15, 1996. Mr. Greene also purchased C $1,500,000 of 6 3/4% Convertible
Debentures at market value prior to his election to the Board of Directors that
were converted into 187,500 Common Shares on July 31, 1996 in accordance with
the terms of the 6 3/4% Convertible Debentures.
PURCHASE OF WORKING INTERESTS
In May 1996, the Company purchased oil and natural gas working interests
from four employees for an aggregate consideration of $387,000, which included
$158,000 paid to Mr. Matthew Deso, Vice President of Exploration of the Company,
$133,000 paid to Mr. Mark Worthey, Vice President of Operations of the Company
and $26,000 paid to the spouse of Mr. Gareth Roberts, President and Chief
Executive Officer of the Company. The purchase prices were determined by the
Company based on the present value of the estimated future net revenue to be
generated from the estimated proved reserves of the properties (based on the
prior year's report thereon from Netherland & Sewell) using a 15% discount rate.
The acquisitions were for additional working interests in properties in which
the Company also holds an interest. To the best of the Company's knowledge, none
of the Company's officers or directors have any remaining interests in
properties owned by the Company.
DESCRIPTION OF CERTAIN INDEBTEDNESS
CREDIT FACILITY
Effective December 29, 1997, the Company restated its Credit Facility with
NationsBank of Texas, N.A., as Administrative Agent, and a syndicate of lenders
pursuant to an agreement (the "Credit Agreement") under which DMI is the
borrower from such lenders. The following is a summary of certain terms of the
Credit Facility and is qualified in its entirety by reference to the Credit
Agreement and the various related documents entered into in connection with the
Credit Facility.
The total commitment under the Credit Facility is $300.0 million, subject
to borrowing base availability. The initial borrowing base under the Credit
Facility is $260.0 million, $95.0 million of which consists of an interim
acquisition financing commitment (the "Acquisition Tranche"). The initial
borrowing base of $260 million will be reduced simultaneously with the issuance
by the Company of any debt or equity securities by an amount equal to the net
proceeds from the issuance of such securities, until such time as the borrowing
base is reduced to the conforming borrowing base of $165.0 million. The interest
rate on the Credit Facility includes a premium so long as the Acquisition
Tranche is outstanding. Such premium is currently 0.25% and will increase 0.25%
each quarter, commencing March 31, 1998, through March 31, 1999 until the
Acquisition Tranche is repaid. The borrowing base in effect under the Credit
Agreement is subject to redetermination semi-annually, at the sole discretion of
the lenders. The borrowing base may be affected from time to time by the
performance of the Company's oil and natural gas properties and changes in oil
and natural gas prices, among other factors. The Company incurs a commitment fee
of up to 0.45% per year on the unused portion of the borrowing base.
Borrowings under the Credit Facility are payable in full on December 29,
2002 and bear interest at the option of the Company at the bank's prime rate or,
depending on the percentage of the borrowing base that is outstanding, at rates
ranging from LIBOR plus 7/8% to LIBOR plus 1 3/8% (plus the applicable premium
in effect when the Acquisition Tranche is outstanding). As of December 31, 1997,
after giving effect to the Transactions, the Company would have had a borrowing
base of $165.0 million, of which $123.9 million was available.
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<PAGE> 60
The obligations of DMI as borrower under the Credit Facility will be fully
and unconditionally guaranteed by DRI, DMI's direct corporate parent. In
addition, the Credit Facility will be secured by first priority security
interests in certain oil and natural gas properties which secured the Company's
prior credit facility entered into on May 31, 1996 (excluding the properties
acquired in the Chevron Acquisition) and a pledge of all of the stock of DMI;
provided, however, that if the borrowings outstanding under the Credit Facility
exceed the borrowing base after redetermination on July 1, 1998, the Credit
Facility will be secured by substantially all of the Company's oil and natural
gas properties (including those acquired in the Chevron Acquisition).
The Credit Facility contains certain covenants which, among other things,
restrict the Company's ability to pay dividends and other restricted payments,
incur additional indebtedness, create liens, enter into leases and investments
(including hedging investments), engage in mergers and consolidations or engage
in certain transactions with affiliates. In addition, the Company will be
required to comply with certain financial ratios and tests, including a minimum
tangible net worth test, a current ratio coverage test and an EBITDA to interest
ratio test.
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DESCRIPTION OF THE NOTES
As used in this section, the term "Company" shall mean DMI, the issuer of
the Notes.
GENERAL
The Notes are to be issued under an Indenture, to be dated as of February
26, 1998 (the "Indenture"), between the Company and Chase Bank of Texas,
National Association, as Trustee (the "Trustee"). A copy of the form of
Indenture will be filed as an exhibit to the Registration Statement of which
this Prospectus is a part. The following summary of certain provisions of the
Indenture does not purport to be complete and is subject to, and is qualified in
its entirety by reference to, the Indenture and the Notes, including the
definitions of certain terms therein and those terms made a part of the
Indenture by the Trust Indenture Act of 1939, as amended.
TERMS OF THE NOTES
The Notes will be unsecured senior subordinated obligations of the Company,
initially limited to $125 million aggregate principal amount, and will mature on
March 1, 2008. The Notes will bear interest at the rate per annum shown on the
cover page hereof from February 26, 1998, or from the most recent date to which
interest has been paid or provided for, payable semiannually to Holders of
record at the close of business on the February 15 or August 15 immediately
preceding the interest payment date on March 1 and September 1 of each year,
commencing September 1, 1998. Interest on overdue principal and (to the extent
permitted by law) on overdue installments of interest will accrue at 1% per
annum in excess of such rate. Interest on the Notes will be computed on the
basis of a 360-day year of twelve 30-day months.
Principal of and interest on the Notes will be payable, and the Notes may
be exchanged or transferred, at the office or agency of the Company in the
Borough of Manhattan, The City of New York (which initially shall be the
corporate trust office of the Trustee, at The Chase Manhattan Bank, Corporate
Trust Services Window, Room 234 North, 55 Water Street, New York, New York,
10041, except that, at the option of the Company, payment of interest may be
made by check mailed to the address of the Holders as such address appears in
the Note Register.
The Notes will be issued only in fully registered form, without coupons, in
denominations of $1,000 and any integral multiple of $1,000. No service charge
shall be made for any registration of transfer or exchange of Notes, but the
Company may require payment of a sum sufficient to cover any transfer tax or
other similar governmental charge payable in connection therewith.
Subject to the covenants described below under "-- Certain Covenants" and
applicable law, the Company may issue additional Notes under the Indenture in an
unlimited principal amount. The Notes offered hereby and any additional Notes
subsequently issued would be treated as a single class for all purposes under
the Indenture.
OPTIONAL REDEMPTION
Except as set forth in the following paragraph, the Notes will not be
redeemable at the option of the Company prior to March 1, 2003. Thereafter, the
Notes will be redeemable, at the Company's option, in whole or in part, at any
time or from time to time, upon not less than 30 nor more than 60 days' prior
notice mailed by first-class mail to each Holder's registered address, at the
following redemption prices (expressed in percentages of principal amount), plus
accrued interest to the redemption date (subject to the right of Holders of
record on the relevant record date to receive interest due on the relevant
interest payment date), if redeemed during the 12-month period commencing on
March 1, of the years set forth below:
<TABLE>
<CAPTION>
REDEMPTION
PERIOD PRICE
- ------ ----------
<S> <C> <C>
2003.............................................................. 104.500%
2004.............................................................. 103.000
2005.............................................................. 101.500
2006 and thereafter............................................... 100.000
</TABLE>
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<PAGE> 62
In addition, at any time and from time to time prior to March 1, 2001, the
Company may redeem in the aggregate up to 35% of the original principal amount
of the Notes with the proceeds of one or more Stock Offerings to the extent the
net cash proceeds thereof, in the case of a Stock Offering by DRI, are
contributed to the equity capital of the Company and so long as there is a
Public Market at the time of such redemption, at a redemption price (expressed
as a percentage of principal amount) of 109% plus accrued interest to the
redemption date (subject to the right of Holders of record on the relevant
record date to receive interest due on the relevant interest payment date);
provided, however, that (i) either (A) at least $81.0 million aggregate
principal amount of the Notes must remain outstanding after each such redemption
or (B) such redemption retires the Notes in their entirety and (ii) such
redemption occurs within 60 days following the closing of such Stock Offering.
In the case of any partial redemption, selection of the Notes for
redemption will be made by the Trustee on a pro rata basis, by lot or by such
other method as the Trustee in its sole discretion shall deem to be fair and
appropriate, although no Note of $1,000 in original principal amount or less
shall be redeemed in part. If any Note is to be redeemed in part only, the
notice of redemption relating to such Note shall state the portion of the
principal amount thereof to be redeemed. A new Note in principal amount equal to
the unredeemed portion thereof will be issued in the name of the Holder thereof
upon cancellation of the original Note.
SINKING FUND
There will be no sinking fund payments for the Notes.
GUARANTIES
DRI, as primary obligor and not merely as surety, will irrevocably, fully
and unconditionally guarantee (the "DRI Guaranty") on a senior subordinated
basis the performance and the punctual payment when due, whether at Stated
Maturity, by acceleration or otherwise, of all the obligations of the Company
under the Indenture and the Notes. In addition, under the circumstances
described below under "-- Certain Covenants -- Future Subsidiary Guarantors,"
certain Restricted Subsidiaries, as primary obligor and not merely as surety,
will irrevocably, fully and unconditionally guarantee (each, a "Subsidiary
Guaranty") on a senior subordinated basis the performance and the punctual
payment when due, whether at Stated Maturity, by acceleration or otherwise, of
all the obligations of the Company under the Indenture and the Notes (all such
obligations guaranteed by DRI and any Subsidiary Guarantors being herein called
the "Guaranteed Obligations"). DRI is a holding company that will derive all of
its operating income and cash flow from its subsidiaries, including primarily
the Company, the common stock of which will be pledged to secure DRI's guarantee
of indebtedness of the Company outstanding under the Credit Facility. DRI has no
material assets other than the common stock of the Company. DRI and each
Subsidiary Guarantor (collectively, the "Guarantors") will agree to pay, in
addition to the amount stated above, any and all expenses (including reasonable
counsel fees and expenses) incurred by the Trustee and the Holders in enforcing
any rights under the Guaranty with respect to the Guarantor. Each Subsidiary
Guaranty will be limited in amount to an amount not to exceed the maximum amount
that can be guaranteed by the applicable Subsidiary Guarantor without rendering
the Subsidiary Guaranty, as it relates to such Subsidiary Guarantor, voidable
under applicable law relating to fraudulent conveyance or fraudulent transfer or
similar laws affecting the rights of creditors generally. If a Subsidiary
Guaranty were to be rendered voidable, it could be subordinated by a court to
all other indebtedness (including guarantees and other contingent liabilities)
of the applicable Subsidiary Guarantor, and depending on the amount of such
indebtedness, a Subsidiary Guarantor's liability on its Subsidiary Guaranty
could be reduced to zero. As of the Issue Date, none of the Company's
subsidiaries will be Subsidiary Guarantors.
The DRI Guaranty is, and each Subsidiary Guaranty will be, a continuing
guarantee and shall (a) subject to certain limited exceptions, remain in full
force and effect until payment in full of all the Guaranteed Obligations, (b) be
binding upon the Guarantor and (c) enure to the benefit of and be enforceable by
the Trustee, the Holders and their successors, transferees and assigns.
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Pursuant to the Indenture, a Guarantor may consolidate with, merge with or
into, or transfer all or substantially all its assets to any other Person to the
extent described below under "-- Certain Covenants -- Merger and Consolidation";
provided, however, that if such Person is not the Company, the Guarantor's
obligations under the Indenture and its Guaranty must be expressly assumed by
such other Person. However, upon the sale or other disposition (including by way
of consolidation or merger) of a Subsidiary Guarantor or the sale or disposition
of all or substantially all the assets of a Subsidiary Guarantor (in each case
other than to the Company or an Affiliate of the Company), such Subsidiary
Guarantor will be released and relieved from all its obligations under its
Subsidiary Guaranty. See "-- Certain Covenants -- Merger and Consolidation."
RANKING
The indebtedness evidenced by the Notes, the DRI Guaranty and any
Subsidiary Guaranty will be senior unsecured, general obligations of the
Company, DRI and the relevant Subsidiary Guarantor, as the case may be,
subordinated in right of payment, as set forth in the Indenture, to the prior
payment of all Senior Indebtedness of the Company or the relevant Guarantor, as
the case may be, whether outstanding on the Issue Date or thereafter incurred,
including the obligations of the Company under, and such Guarantor's guarantee,
if any, of the Company's obligations with respect to, the Credit Facility.
As of September 30, 1997, after giving pro forma effect to the
Transactions, (i) the Senior Indebtedness of the Company would have been
approximately $23.1 million, all of which would have been secured indebtedness
and (ii) the Senior Indebtedness of DRI would have been approximately $23.1
million, all of which would have represented DRI's guarantee of Senior
Indebtedness of the Company under the Credit Facility. Although the Indenture
contains limitations on the amount of additional Indebtedness that the Company
and any Subsidiary Guarantor may incur, under certain circumstances the amount
of such Indebtedness could be substantial and, in any case, such Indebtedness
may be Senior Indebtedness. See "-- Certain Covenants -- Limitation on
Indebtedness."
Only Indebtedness of the Company or a Guarantor that is Senior Indebtedness
will rank senior to the Notes and the relevant Guaranty in accordance with the
provisions of the Indenture. The Notes and each Guaranty will in all respects
rank pari passu with all other Senior Subordinated Indebtedness of the Company
and the relevant Guarantor, respectively. The Company and DRI each has agreed,
and each Subsidiary Guarantor will agree, in the Indenture that it will not
Incur, directly or indirectly, any Indebtedness that is subordinate or junior in
ranking in right of payment to its Senior Indebtedness unless such Indebtedness
is Senior Subordinated Indebtedness or is expressly subordinated in right of
payment to Senior Subordinated Indebtedness. Unsecured Indebtedness is not
deemed to be subordinated or junior to Secured Indebtedness merely because it is
unsecured.
A portion of the operations of the Company are currently conducted through
its subsidiaries. Claims of creditors of any such subsidiaries, including trade
creditors, secured creditors and creditors holding guarantees issued by such
subsidiaries, and claims of preferred stockholders (if any) of such subsidiaries
generally will have priority with respect to the assets and earnings of such
subsidiaries over the claims of creditors of the Company, including holders of
the Notes, even though such obligations would not constitute Senior Indebtedness
of the Company. The Notes, therefore, will be effectively subordinated to
creditors (including trade creditors) and preferred stockholders (if any) of
subsidiaries of the Company (other than subsidiaries of the Company that are
Subsidiary Guarantors). Although the Indenture limits the incurrence of
Indebtedness and the issuance of preferred stock of certain of the Company's
subsidiaries, such limitation is subject to a number of significant
qualifications. Moreover, the Indenture does not impose any limitation on the
incurrence by such subsidiaries of liabilities that are not considered
Indebtedness under the Indenture. See "-- Certain Covenants -- Limitation on
Indebtedness."
The Company may not pay principal of, premium (if any) or interest on, the
Notes or make any deposit pursuant to the provisions described under
"Defeasance" below or may not repurchase, redeem or otherwise retire any Notes
(collectively, "pay the Notes") if (i) any Designated Senior Indebtedness of the
Company is not paid when due or (ii) any other default on Designated Senior
Indebtedness of the Company occurs and the maturity of such Designated Senior
Indebtedness is accelerated in accordance with its terms unless, in
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either case, the default has been cured or waived and any such acceleration has
been rescinded or such Designated Senior Indebtedness has been paid in full.
However, the Company may pay the Notes without regard to the foregoing if the
Company and the Trustee receive written notice approving such payment from the
Representative of the applicable Designated Senior Indebtedness with respect to
which either of the events set forth in clause (i) or (ii) of the immediately
preceding sentence has occurred and is continuing. During the continuance of any
default (other than a default described in clause (i) or (ii) of the second
preceding sentence) with respect to any Designated Senior Indebtedness of the
Company pursuant to which the maturity thereof may be accelerated immediately
without further notice (except such notice as may be required to effect such
acceleration) or the expiration of any applicable grace periods, the Company may
not pay the Notes for a period (a "Payment Blockage Period") commencing upon the
receipt by the Trustee (with a copy to the Company) of written notice (a
"Blockage Notice") of such default from the Representative of the holders of
such Designated Senior Indebtedness specifying an election to effect a Payment
Blockage Period and ending 179 days thereafter (or earlier if such Payment
Blockage Period is terminated (i) by written notice to the Trustee and the
Company from the Person or Persons who gave such Blockage Notice, (ii) because
the default giving rise to such Blockage Notice is no longer continuing or (iii)
because such Designated Senior Indebtedness has been repaid in full in cash).
Notwithstanding the provisions described in the immediately preceding sentence,
unless the holders of such Designated Senior Indebtedness or the Representative
of such holders have accelerated the maturity of such Designated Senior
Indebtedness, the Company must resume payments on the Notes after the end of
such Payment Blockage Period. The Notes shall not be subject to more than one
Payment Blockage Period in any consecutive 360-day period, irrespective of the
number of defaults with respect to Designated Senior Indebtedness of the Company
during such period.
Upon any payment or distribution of the assets of the Company upon a total
or partial liquidation or dissolution or reorganization of or similar proceeding
relating to the Company or its property, the holders of Senior Indebtedness of
the Company will be entitled to receive payment in full in cash of such Senior
Indebtedness before the Noteholders are entitled to receive any payment in
respect of the Notes, and until such Senior Indebtedness is paid in full in
cash, any payment or distribution to which Noteholders would be entitled from
the Company but for the subordination provisions of the Indenture will be made
to holders of such Senior Indebtedness of the Company as their interests may
appear. If a distribution is made to Noteholders that, due to the subordination
provisions, should not have been made to them, such Noteholders are required to
hold it in trust for the holders of Senior Indebtedness of the Company and pay
it over to them as their interests may appear.
If payment of the Notes is accelerated because of an Event of Default, the
Company or the Trustee shall promptly notify the holders of Designated Senior
Indebtedness of the Company or the Representative of such holders of the
acceleration.
The obligations of DRI under the DRI Guaranty are, and the obligations of
any Subsidiary Guarantor under its Subsidiary Guaranty will be, unsecured senior
subordinated obligations. As such, the rights of Noteholders to receive payment
by a Guarantor pursuant to its Guaranty will be subordinated in right of payment
to the rights of holders of Senior Indebtedness of such Guarantor. The terms of
the subordination provisions described above with respect to the Company's
obligations under the Notes apply equally to DRI and any Subsidiary Guarantors
and the obligations of DRI and any such Subsidiary Guarantor under its
respective Guaranty.
By reason of the subordination provisions contained in the Indenture, in
the event of insolvency, creditors of the Company or a Guarantor who are holders
of Senior Indebtedness of the Company or such Guarantor, as the case may be, may
recover more, ratably, than the Noteholders, and creditors of the Company or a
Guarantor who are not holders of Senior Indebtedness of the Company or such
Guarantor may recover less, ratably, than holders of Senior Indebtedness of the
Company or such Guarantor, as the case may be, and may recover more, ratably,
than the Noteholders.
Notwithstanding the foregoing, payment from the money or the proceeds of
U.S. Government Obligations held in any defeasance trust described under
"-- Defeasance" below will not be contractually
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subordinated in right of payment to any Senior Indebtedness of the Company or
subject to the restrictions described herein.
CERTAIN DEFINITIONS
"Additional Assets" means (i) any property or assets (other than
Indebtedness and Capital Stock) in the Oil and Gas Business; (ii) the Capital
Stock of a Person that becomes a Restricted Subsidiary as a result of the
acquisition of such Capital Stock by the Company or another Restricted
Subsidiary; or (iii) Capital Stock constituting a minority interest in any
Person that at such time is a Restricted Subsidiary; provided, however, that any
such Restricted Subsidiary described in clauses (ii) or (iii) above is primarily
engaged in the Oil and Gas Business.
"Adjusted Consolidated Assets" means at any time the total amount of assets
of the Company and its Restricted Subsidiaries (less applicable depreciation,
amortization and other valuation reserves), after deducting therefrom all
current liabilities of the Company and its Restricted Subsidiaries (excluding
intercompany items), all as set forth on the consolidated balance sheet of the
Company and its Restricted Subsidiaries as of the end of the most recent fiscal
quarter ended at least 45 days prior to the date of determination.
"Adjusted Consolidated Net Tangible Assets" or "ACNTA" means (without
duplication), as of the date of determination, (a) the sum of (i) discounted
future net revenue from proved crude oil and natural gas reserves of the Company
and its Restricted Subsidiaries calculated in accordance with SEC guidelines
before any state or federal income taxes, as estimated in a reserve report
prepared as of the end of the Company's most recently completed fiscal year,
which reserve report is prepared or reviewed by independent petroleum engineers,
as increased by, as of the date of determination, the discounted future net
revenue of (A) estimated proved crude oil and natural gas reserves of the
Company and its Restricted Subsidiaries attributable to acquisitions consummated
since the date of such year-end reserve report, and (B) estimated crude oil and
natural gas reserves of the Company and its Restricted Subsidiaries attributable
to extensions, discoveries and other additions and upward determinations of
estimates of proved crude oil and natural gas reserves (including previously
estimated development costs incurred during the period and the accretion of
discount since the prior year end) due to exploration, development or
exploitation, production or other activities which reserves were not reflected
in such year-end reserve report which would, in the case of determinations made
pursuant to clauses (A) and (B), in accordance with standard industry practice,
result in such determinations, in each case calculated in accordance with SEC
guidelines (utilizing the prices utilized in such year-end reserve report), and
decreased by, as of the date of determination, the discounted future net revenue
attributable to (C) estimated proved crude oil and natural gas reserves of the
Company and its Restricted Subsidiaries reflected in such year-end reserve
report produced or disposed of since the date of such year-end reserve report
and (D) reductions in the estimated oil and gas reserves of the Company and its
Restricted Subsidiaries reflected in such year-end reserve report since the date
of such year-end reserve report attributable to downward determinations of
estimates of proved crude oil and natural gas reserves due to exploration,
development or exploitation, production or other activities conducted or
otherwise occurring since the date of such yearend reserve report which would,
in the case of determinations made pursuant to clauses (C) and (D), in
accordance with standard industry practice, result in such determinations, in
each case calculated in accordance with SEC guidelines (utilizing the prices
utilized in such year-end reserve report); provided, however, that, in the case
of each of the determinations made pursuant to clauses (A) through (D), such
increases and decreases shall be as estimated by the Company's engineers, except
that if as a result of such acquisitions, dispositions, discoveries, extensions
or revisions, there is a Material Change which is an increase, then such
increases and decreases in the discounted future net revenue shall be confirmed
in writing by an independent petroleum engineer, (ii) the capitalized costs that
are attributable to crude oil and natural gas properties of the Company and its
Restricted Subsidiaries to which no proved crude oil and natural gas reserves
are attributed, based on the Company's books and records as of a date no earlier
than the date of the Company's latest annual or quarterly financial statements,
(iii) the Net Working Capital on a date no earlier than the date of the
Company's latest annual or quarterly financial statements and (iv) the greater
of (I) the net book value on a date no earlier than the date of the Company's
latest annual or quarterly financial
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statements and (II) the appraised value, as estimated by independent appraisers,
of other tangible assets of the Company and its Restricted Subsidiaries as of a
date no earlier than the date of the Company's latest audited financial
statements (provided that the Company shall not be required to obtain such an
appraisal of such assets if no such appraisal has been performed), minus (b) to
the extent not otherwise taken into account in the immediately preceding clause
(a), the sum of (i) minority interests, (ii) any natural gas balancing
liabilities of the Company and its Restricted Subsidiaries reflected in the
Company's latest audited financial statements, (iii) the discounted future net
revenue, calculated in accordance with SEC guidelines (utilizing the same prices
utilized in the Company's year-end reserve report), attributable to reserves
subject to participation interests, overriding royalty interests or other
interests of third parties, pursuant to participation, partnership, vendor
financing or other agreements then in effect, or which otherwise are required to
be delivered to third parties, (iv) the discounted future net revenue,
calculated in accordance with SEC guidelines (utilizing the same prices utilized
in the Company's year-end reserve report), attributable to reserves that are
required to be delivered to third parties to fully satisfy the obligations of
the Company and its Restricted Subsidiaries with respect to Volumetric
Production Payments on the schedules specified with respect thereto and (v) the
discounted future net revenue, calculated in accordance with SEC guidelines,
attributable to reserves subject to Dollar-Denominated Production Payments that,
based on the estimates of production included in determining the discounted
future net revenue specified in the immediately preceding clause (a) (i)
(utilizing the same prices utilized in the Company's year-end reserve report),
would be necessary to satisfy fully the obligations of the Company and its
Restricted Subsidiaries with respect to Dollar-Denominated Production Payments
on the schedules specified with respect thereto.
"Affiliate" of any specified Person means any other Person, directly or
indirectly, controlling or controlled by or under direct or indirect common
control with such specified Person. For the purposes of this definition,
"control" when used with respect to any Person means the power to direct the
management and policies of such Person, directly or indirectly, whether through
the ownership of voting securities, by contract or otherwise; and the terms
"controlling" and controlled" have meanings correlative to the foregoing. For
purposes of the provisions described under "-- Certain Covenants -- Limitation
on Restricted Payments," "-- Certain Covenants -- Limitation on Affiliate
Transactions" and "-- Certain Covenants -- Limitations on Sales of Assets and
Subsidiary Stock" only, "Affiliate" shall also mean any beneficial owner of
Capital Stock representing 10% or more of the total voting power of the Voting
Stock (on a fully diluted basis) of the Company or of rights or warrants to
purchase such Capital Stock (whether or not currently exercisable) and any
Person who would be an Affiliate of any such beneficial owner pursuant to the
first sentence hereof.
"Asset Disposition" means any sale, lease, transfer or other disposition
(or series of related sales, leases, transfers or dispositions) by the Company
or any Restricted Subsidiary, including any disposition by means of a merger,
consolidation or similar transaction (each referred to for the purposes of this
definition as a "disposition"), of (i) any shares of Capital Stock of a
Restricted Subsidiary (other than directors' qualifying shares or shares
required by applicable law to be held by a Person other than the Company or a
Restricted Subsidiary), (ii) all or substantially all the assets of any division
or line of business of the Company or any Restricted Subsidiary or (iii) any
other assets of the Company or any Restricted Subsidiary outside of the ordinary
course of business of the Company or such Restricted Subsidiary. Notwithstanding
the foregoing, none of the following shall be deemed to be an Asset Disposition:
(1) a disposition by a Restricted Subsidiary to the Company or by the Company or
a Restricted Subsidiary to a Wholly Owned Subsidiary, (2) for purposes of the
covenant described under "-- Certain Covenants -- Limitation on Sales of Assets
and Subsidiary Stock" only, a disposition that constitutes a Restricted Payment
permitted by the covenant described under "-- Certain Covenants -- Limitation on
Restricted Payments," a disposition of all or substantially all the assets of
the Company in compliance with "-- Certain Covenants -- Merger and
Consolidation" or a disposition that constitutes a Change of Control pursuant to
clause (iii) of the definition thereof, (3) the sale or transfer (whether or not
in the ordinary course of business) of crude oil and natural gas properties or
direct or indirect interests in real property; provided, however, that at the
time of such sale or transfer such properties do not have associated with them
any proved reserves, (4) the abandonment, farm-out, lease or sublease of
developed or undeveloped crude oil and natural gas properties in the ordinary
course of business, (5) the trade or exchange by the Company or any Restricted
Subsidiary of any crude oil and natural gas property owned or held by the
Company or such Restricted Subsidiary for any crude oil and
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natural gas property owned or held by another Person or (6) the sale or transfer
of hydrocarbons or other mineral products or surplus or obsolete equipment, in
each case in the ordinary course of business.
"Attributable Debt" in respect of a Sale/Leaseback Transaction means, as at
the time of determination, the present value (discounted at the interest rate
implicit in the Sale/Leaseback Transaction, compounded annually) of the total
obligations of the lessee for rental payments during the remaining term of the
lease included in such Sale/Leaseback Transaction (including any period for
which such lease has been extended).
"Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (i) the sum
of the products of numbers of years from the date of determination to the dates
of each successive scheduled principal payment of such Indebtedness or
redemption or similar payment with respect to such Preferred Stock multiplied by
the amount of such payment by (ii) the sum of all such payments.
"Banks" has the meaning specified in the Credit Agreement.
"Board of Directors" means the Board of Directors of the Company or any
committee thereof duly authorized to act on behalf of such Board.
"Business Day" means each day which is not a Legal Holiday (as defined in
the Indenture).
"Capital Lease Obligations" means an obligation that is required to be
classified and accounted for as a capital lease for financial reporting purposes
in accordance with GAAP, and the amount of Indebtedness represented by such
obligation shall be the capitalized amount of such obligation determined in
accordance with GAAP; and the Stated Maturity thereof shall be the date of the
last payment of rent or any other amount due under such lease prior to the first
date upon which such lease may be terminated by the lessee without payment of a
penalty.
"Capital Stock" of any Person means any and all shares, interests, rights
to purchase, warrants, options, participations or other equivalents of or
interests in (however designated) equity of such Person, including any Preferred
Stock, but excluding any debt securities convertible into such equity.
"Change of Control" means the occurrence of any of the following events:
(i) any "person" (as such term is used in Sections 13(d) and 14(d) of
the Exchange Act), other than a Permitted Holder, is or becomes the
beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange
Act, except that for purposes of this clause (i) such person shall be
deemed to have "beneficial ownership" of all shares that such person has
the right to acquire, whether such right is exercisable immediately or only
after the passage of time), directly or indirectly, of more than 40% of the
total voting power of the Voting Stock of the Company (for the purposes of
this clause (i), such person shall be deemed to beneficially own any Voting
Stock of a specified corporation held by a parent corporation, if such
person is the beneficial owner (as defined in this clause (i)), directly or
indirectly, of more than 40% of the voting power of the Voting Stock of
such parent corporation);
(ii) during any period of two consecutive years from and after the
Issue Date, individuals who at the beginning of such period constituted the
Board of Directors of DRI (together with any new directors whose election
by such Board of Directors or whose nomination for election by the
shareholders of DRI was approved by a vote of a majority of the directors
of DRI then still in office who were either directors at the beginning of
such period or whose election or nomination for election was previously so
approved) cease for any reason to constitute a majority of the Board of
Directors then in office;
(iii) the shareholders of DRI or the Company shall have approved any
plan of liquidation or dissolution of DRI or the Company; or
(iv) the merger or consolidation of the Company with or into another
Person or the merger of another Person with or into the Company, or the
sale, lease, conveyance or transfer of all or substantially all the assets
of the Company and its Restricted Subsidiaries, taken as a whole, to
another Person (other than a Person that is controlled (as defined in the
definition of "Affiliate") by the Permitted Holders), and, in the case of
any such merger or consolidation, the securities of the Company that are
outstanding
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immediately prior to such transaction and which represent 100% of the
aggregate voting power of the Voting Stock of the Company are changed into
or exchanged for cash, securities or property, unless pursuant to such
transaction such securities are changed into or exchanged for, in addition
to any other consideration, securities of the surviving corporation that
represent immediately after such transaction, at least a majority of the
aggregate voting power of the Voting Stock of the surviving corporation.
"Code" means the Internal Revenue Code of 1986, as amended.
"Consolidated Coverage Ratio" as of any date of determination means the
ratio of (i) the aggregate amount of EBITDA for the period of the most recent
four consecutive fiscal quarters ending at least 45 days prior to the date of
such determination to (ii) Consolidated Interest Expense for such four fiscal
quarters; provided, however, that (1) if the Company or any Restricted
Subsidiary has Incurred any Indebtedness since the beginning of such period that
remains outstanding or if the transaction giving rise to the need to calculate
the Consolidated Coverage Ratio is an Incurrence of Indebtedness, or both,
EBITDA and Consolidated Interest Expense for such period shall be calculated
after giving effect on a pro forma basis to such Indebtedness as if such
Indebtedness had been Incurred on the first day of such period and the discharge
of any other Indebtedness repaid, repurchased, defeased or otherwise discharged
with the proceeds of such new Indebtedness as if such discharge had occurred on
the first day of such period, (2) if the Company or any Restricted Subsidiary
has repaid, repurchased, defeased or otherwise discharged any Indebtedness since
the beginning of such period or if any indebtedness is to be repaid,
repurchased, defeased or otherwise discharged on the date of the transaction
giving rise to the need to calculate the Consolidated Coverage Ratio, EBITDA and
Consolidated Interest Expense for such period shall be calculated on a pro forma
basis as if such discharge had occurred on the first day of such period and as
if the Company or such Restricted Subsidiary has not earned the interest income
actually earned during such period in respect of cash or Temporary Cash
Investments used to repay, repurchase, defease or otherwise discharge such
Indebtedness, (3) if since the beginning of such period the Company or any
Restricted Subsidiary shall have made any Asset Disposition (other than an Asset
Disposition involving assets having a fair market value of less than the greater
of two and one-half percent (2.5%) of Adjusted Consolidated Net Tangible Assets
as of the end of the Company's then most recently completed fiscal year and $3.0
million), then EBITDA for such period shall be reduced by an amount equal to
EBITDA (if positive) directly attributable to the assets which are the subject
of such Asset Disposition for such period, or increased by an amount equal to
EBITDA (if negative), directly attributable thereto for such period and
Consolidated Interest Expense for such period shall be reduced by an amount
equal to the Consolidated Interest Expense directly attributable to any
Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased,
defeased or otherwise discharged with respect to the Company and its continuing
Restricted Subsidiaries in connection with such Asset Disposition for such
period (or, if the Capital Stock of any Restricted Subsidiary is sold, the
Consolidated Interest Expense for such period directly attributable to the
Indebtedness of such Restricted Subsidiary to the extent the Company and its
continuing Restricted Subsidiaries are no longer liable for such Indebtedness
after such sale), (4) if since the beginning of such period the Company or any
Restricted Subsidiary (by merger or otherwise) shall have made an Investment in
any Restricted Subsidiary (or any person which becomes a Restricted Subsidiary)
or an acquisition (including by way of lease) of assets, including any
acquisition of assets occurring in connection with a transaction requiring a
calculation to be made hereunder, EBITDA and Consolidated Interest Expense for
such period shall be calculated after giving pro forma effect thereto (including
the Incurrence of any Indebtedness) as if such Investment or acquisition
occurred on the first day of such period and (5) if since the beginning of such
period any Person (that subsequently became a Restricted Subsidiary or was
merged with or into the Company or any Restricted Subsidiary since the beginning
of such period) shall have made any Asset Disposition, any Investment or
acquisition of assets that would have required an adjustment pursuant to clause
(3) or (4) above if made by the Company or a Restricted Subsidiary during such
period, EBITDA and Consolidated Interest Expense for such period shall be
calculated after giving pro forma effect thereto as if such Asset Disposition,
Investment or acquisition occurred on the first day of such period. For purposes
of this definition, whenever pro forma effect is to be given to an acquisition
of assets, the amount of income or earnings relating thereto and the amount of
Consolidated Interest Expense associated with any Indebtedness Incurred in
connection therewith, the pro forma calculations shall be determined in good
faith by a responsible
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financial or accounting Officer of the Company. If any Indebtedness bears a
floating rate of interest and is being given pro forma effect, the interest of
such Indebtedness shall be calculated as if the rate in effect on the date of
determination had been the applicable rate for the entire period (taking into
account any Interest Rate Agreement applicable to such Indebtedness if such
Interest Rate Agreement has a remaining term in excess of 12 months).
"Consolidated Current Liabilities" as of the date of determination means
the aggregate amount of liabilities of the Company and its consolidated
Restricted Subsidiaries which would properly be classified as current
liabilities (including taxes accrued as estimated), on a consolidated balance
sheet of the Company and its Restricted subsidiaries at such date, after
eliminating (i) all intercompany items between the Company and any Restricted
Subsidiary and (ii) all current maturities of long-term Indebtedness, all as
determined in accordance with GAAP consistently applied.
"Consolidated Indebtedness" at any date of determination means the amount
of Indebtedness of the Company and its Restricted Subsidiaries outstanding on
such date determined on a consolidated basis in accordance with GAAP.
"Consolidated Interest Expense" means, for any period, the total interest
expense of the Company and its Restricted Subsidiaries for such period,
determined on a consolidated basis in accordance with GAAP, plus, to the extent
not included in such total interest expense, and to the extent incurred by the
Company or its Restricted Subsidiaries, without duplication, (i) interest
expense attributable to Capital Lease Obligations and imputed interest with
respect to Attributable Debt, (ii) capitalized interest, (iii) non-cash interest
expense, (iv) commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing, (v) net costs
(including amortization of fees and up-front payments) associated with interest
rate caps and other interest rate and currency options that, at the time entered
into, resulted in the Company and its Restricted Subsidiaries being net payees
as to future payouts under such caps or options, and interest rate and currency
swaps and forwards for which the Company or any of its Restricted Subsidiaries
has paid a premium, (vi) dividends (excluding dividends paid in shares of
Capital Stock which is not Disqualified Stock) in respect of all Disqualified
Stock held by Persons other than the Company or a Wholly Owned Subsidiary, (vii)
interest accruing on any Indebtedness of any other Person to the extent such
Indebtedness is Guaranteed by the Company or any Restricted Subsidiary or
secured by a Lien on assets of the Company or any Restricted Subsidiary to the
extent such Indebtedness constitutes Indebtedness of the Company or any
Restricted Subsidiary (whether or not such Guarantee or Lien is called upon);
provided, however, "Consolidated Interest Expense" shall not include any (x)
amortization of costs relating to original debt issuances other than the
amortization of debt discount related to the issuance of zero coupon securities
or other securities with an original issue price of not more than 90% of the
principal thereof, (y) Consolidated Interest Expense with respect to any
Indebtedness Incurred pursuant to clause (b)(8) of the covenant described under
"-- Certain Covenants -- Limitation on Indebtedness" and (z) noncash interest
expense Incurred in connection with interest rate caps and other interest rate
and currency options that, at the time entered into, resulted in the Company and
its Restricted Subsidiaries being either neutral or net payors as to future
payouts under such caps or options.
"Consolidated Net Income" means, for any period, the net income of the
Company and its Subsidiaries determined on a consolidated basis in accordance
with GAAP; provided, however, that there shall not be included in such
Consolidated Net Income: (i) any net income of any Person (other than the
Company) if such Person is not a Restricted Subsidiary, except that (A) subject
to the exclusion contained in clause (iv) below, the Company's equity in the net
income of any such Person for such period shall be included in such Consolidated
Net Income up to the aggregate amount of cash actually distributed by such
Person during such period to the Company or a Restricted Subsidiary as a
dividend or other distribution (subject, in the case of a dividend or other
distribution paid to a Restricted Subsidiary, to the limitations contained in
clause (iii) below) and (B) the Company's equity in a net loss of any such
Person for such period shall be included in determining such Consolidated Net
Income; (ii) any net income (or loss) of any Person acquired by the Company or a
Subsidiary in a pooling of interests transaction for any period prior to the
date of such acquisition; (iii) any net income of any Restricted Subsidiary if
such Restricted Subsidiary is subject to restrictions, directly or indirectly,
on the payment of dividends or the making of distributions by such
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Restricted Subsidiary, directly or indirectly, to the Company, except that (A)
subject to the exclusion contained in clause (iv) below, the Company's equity in
the net income of any such Restricted Subsidiary for such period shall be
included in such Consolidated Net Income up to the aggregate amount of cash
actually distributed by such Restricted Subsidiary during such period to the
Company or another Restricted Subsidiary as a dividend or other distribution
(subject, in the case of a dividend or other distribution paid to another
Restricted Subsidiary, to the limitation contained in this clause) and (B) the
Company's equity in a net loss of any such Restricted Subsidiary for such period
shall be included in determining such Consolidated Net Income; (iv) any gain or
loss realized upon the sale or other disposition of any assets of the Company or
its consolidated Subsidiaries (including pursuant to any sale-and-leaseback
arrangement) which is not sold or otherwise disposed of in the ordinary course
of business and any gain or loss realized upon the sale or other disposition of
any Capital Stock of any Person; (v) extraordinary gains or losses; (vi) any
non-cash compensation expense realized for grants of performance shares, stock
options or stock awards to officers, directors and employees of the Company or
any of its Restricted Subsidiaries; (vii) any write-downs of non-current assets;
provided, however, that any ceiling limitation write-downs under SEC guidelines
shall be treated as capitalized costs, as if such write-downs had not occurred;
and (viii) the cumulative effect of a change in accounting principles.
Notwithstanding the foregoing, for the purposes of the covenant described under
"Certain Covenants -- Limitation on Restricted Payments" only, there shall be
excluded from Consolidated Net Income any dividends, repayments of loans or
advances or other transfers of assets from Unrestricted Subsidiaries to the
Company or a Restricted Subsidiary to the extent such dividends, repayments or
transfers increase the amount of Restricted Payments permitted under such
covenant pursuant to clause (a)(3)(E) thereof.
"Consolidated Net Tangible Assets", as of any date of determination, means
the total amount of assets (less accumulated depreciation and amortization,
allowances for doubtful receivables, other applicable reserves and other
properly deductible items) which would appear on a balance sheet of the Company
and its Restricted Subsidiaries, determined on a consolidated basis in
accordance with GAAP, and after giving effect to purchase accounting and after
deducting therefrom Consolidated Current Liabilities and, to the extent
otherwise included, the amounts of: (i) minority interests in Restricted
Subsidiaries held by Persons other than the Company or a Restricted Subsidiary;
(ii) excess of cost over fair value of assets of businesses acquired, as
determined in good faith by the Board of Directors; (iii) any revaluation or
other write-up in book value of assets subsequent to the Issue Date as a result
of a change in the method of valuation in accordance with GAAP consistently
applied; (iv) unamortized debt discount and expenses and other unamortized
deferred charges, goodwill, patents, trademarks, service marks, trade names,
copyrights, licenses, organization or developmental expenses and other
intangible items; (v) treasury stock; (vi) cash set apart and held in a sinking
or other analogous fund established for the purpose of redemption or other
retirement of Capital Stock to the extent such obligation is not reflected in
Consolidated Current Liabilities; and (vii) Investments in and assets of
Unrestricted Subsidiaries.
"Consolidated Net Worth" means the total of the amounts shown on the
balance sheet of the Company and its Subsidiaries, determined on a consolidated
basis in accordance with GAAP, as of the end of the most recent fiscal quarter
of the Company ending at least 45 days prior to the taking of any action for the
purpose of which the determination is being made, as (i) the par or stated value
of all outstanding Capital Stock of the Company plus (ii) paid-in capital or
capital surplus relating to such Capital Stock plus (iii) any retained earnings
or earned surplus less (A) any accumulated deficit and (B) any amounts
attributable to Disqualified Stock.
"Credit Agreement" means that certain Credit Agreement, dated as of
December 29, 1997, as amended, by and among the Company and NationsBank of
Texas, N.A. (or any successor thereto or replacement thereof), as administrative
agent and as a lender, and certain other institutions, as lenders, including any
related notes, guarantees, collateral documents, instruments and agreements
executed in connection therewith, and in each case as amended, restated,
modified, renewed, refunded, replaced, refinanced or increased in whole or in
part, from time to time.
"Credit Facilities" means, with respect to the Company or any Restricted
Subsidiary, one or more debt facilities (including the Credit Agreement) or
commercial paper facilities with banks or other institutional
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lenders providing for revolving credit loans, term loans, production payments,
receivables financing (including through the sale of receivables to such lenders
or to special purpose entities formed to borrow from such lenders against such
receivables) or letters of credit, in each case, as amended, restated, modified,
renewed, refunded, replaced or refinanced in whole or in part from time to time.
"Currency Agreement" means in respect of a Person any foreign exchange
contract, currency swap agreement or other similar agreement to which such
Person is a party or a beneficiary.
"Default" means any event which is, or after notice or passage of time or
both would be, an Event of Default.
"Designated Senior Indebtedness" in respect of a Person means (i) all the
obligations of such Person under any Credit Facility (including the Credit
Agreement) and (ii) any other Senior Indebtedness of such Person which, at the
date of determination, has an aggregate principal amount outstanding of, or
under which, at the date of determination, the holders thereof are committed to
lend up to, at least $20 million and is specifically designated by such Person
in the instrument evidencing or governing such Senior Indebtedness as
"Designated Senior Indebtedness" for purposes of the Indenture.
"Disqualified Stock" means, with respect to any Person, any Capital Stock
to the extent that by its terms (or by the terms of any security into which it
is convertible or for which it is exchangeable) or upon the happening of any
event, it (i) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise, (ii) is convertible or exchangeable for Indebtedness or
Disqualified Stock or (iii) is redeemable, whole or in part, at the option of
the holder thereof, in each case described in the immediately preceding clauses
(i) , (ii) or (iii), on or prior to the Stated Maturity of the Notes; provided,
however, that any Capital Stock that would not constitute Disqualified Stock but
for provisions thereof giving holders thereof the right to require such Person
to repurchase or redeem such Capital Stock upon the occurrence of an "asset
sale" or "change of control" occurring prior to the Stated Maturity of the Notes
shall not constitute Disqualified Stock if (x) the "asset sale" or "change of
control" provisions applicable to such Capital Stock are not more favorable to
the holders of such Capital Stock than the provisions described under
"-- Certain Covenants -- Limitation on Sales of Assets and Subsidiary Stock" and
"-- Certain Covenants -- Change of Control" and (y) any such requirement only
becomes operative after compliance with such corresponding terms applicable to
the Notes, including the purchase of any Notes tendered pursuant thereto.
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"DRI" means Denbury Resources Inc., a Canadian corporation, and any
successor corporation.
"DRI Guaranty" means the Guarantee of the Notes (on an unconditional,
unsecured senior subordinated basis) by DRI pursuant to the terms of the
Indenture.
"EBITDA" for any period means the sum of Consolidated Net Income, plus
Consolidated Interest Expense plus the following to the extent deducted in
calculating such Consolidated Net Income: (a) provision for taxes based on
income or profits, (b) depletion and depreciation expense, (c) amortization
expense (d) exploration expense (if applicable to the Company after the Issue
Date), (e) unrealized foreign exchange losses and (f) all other non-cash charges
(excluding any such non-cash charge to the extent that it represents an accrual
of or reserve for cash charges in any future period or amortization of a prepaid
cash expense that was paid in a prior period except such amounts as the Company
determines in good faith are nonrecurring), and less, to the extent included in
calculating such Consolidated Net Income and in excess of any costs or expenses
attributable thereto and deducted in calculating such Consolidated Net Income,
the sum of (x) the amount of deferred revenues that are amortized during such
period and are attributable to reserves that are subject to Volumetric
Production Payments, (y) amounts recorded in accordance with GAAP as repayments
of principal and interest pursuant to Dollar-Denominated Production Payments.
Notwithstanding the foregoing, the provision for taxes based on the income or
profits of, and the depletion, depreciation, amortization and exploration and
other non-cash charges of, a Restricted Subsidiary shall be added to
Consolidated Net Income to compute EBITDA only to the extent (and in the same
proportion) that the net income of such Restricted Subsidiary was included in
calculating Consolidated Net Income and only if a
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corresponding amount would be permitted at the date of determination to be
dividended to the Company by such Restricted Subsidiary without prior approval
(that has not been obtained), pursuant to the terms of its charter and all
agreements, instruments, judgments, decrees, orders, statutes, rules and
governmental regulations applicable to such Restricted Subsidiary or its
stockholders and (z) unrealized foreign exchange gains.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exempt Foreign Subsidiary" means (i) any Subsidiary engaged in the Oil and
Gas Business exclusively outside the United States of America, irrespective of
its jurisdiction of incorporation and (ii) any other Subsidiary whose assets
(excluding any cash and Temporary Cash Investments) consist exclusively of
Capital Stock or Indebtedness of one or more Subsidiaries described in clause
(i) of this definition, that, in any case, is so designated by the Company in an
Officers' Certificate delivered to the Trustee and (a) is not a Guarantor of,
and has not granted any Lien to secure, any Indebtedness of the Company or any
Subsidiary other than another Exempt Foreign Subsidiary and (b) does not have
total assets that, when aggregated with the total assets of any other Exempt
Foreign Subsidiary, exceed 25% of the Company's consolidated total assets, as
determined in accordance with GAAP, as reflected on the Company's most recent
quarterly or annual balance sheet. The Company may revoke the designation of any
Exempt Foreign Subsidiary by notice to the Trustee.
"GAAP" means generally accepted accounting principles in the United States
of America as in effect on the Issue Date, including those set forth in (i) the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants, (ii) statements and pronouncements of
the Financial Accounting Standards Board, (iii) such other statements by such
other entity as approved by a significant segment of the accounting profession,
and (iv) the rules and regulations of the SEC governing the inclusion of
financial statements (including pro forma financial statements) in periodic
reports required to be filed pursuant to Section 13 of the Exchange Act,
including opinions and pronouncements in staff accounting bulletins and similar
written statements from the accounting staff of the SEC.
"Guarantee" means, without duplication, any obligation, contingent or
otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of
any Person and any obligation, direct or indirect, contingent or otherwise, of
such Person (i) to purchase or pay (or advance or supply funds for the purchase
or payment of) such Indebtedness of such Person (whether arising by virtue of
partnership arrangements, or by agreements to keep-well, to purchase assets,
goods, securities or services, to take-or-pay or to maintain financial statement
conditions or otherwise) or (ii) entered into for the purpose of assuring in any
other manner the obligee of such Indebtedness of the payment thereof or to
protect such obligee against loss in respect thereof (in whole or in part);
provided, however, that the term "Guarantee" shall not include endorsements for
collection or deposit in the ordinary course of business. The term "Guarantee"
used as a verb has a corresponding meaning. The term "Guarantor" shall mean any
Person Guaranteeing any obligation.
"Guaranties" means the DRI Guaranty and each Subsidiary Guaranty. Each of
the Guaranties is referred to individually as a "Guaranty."
"Guarantors" means DRI and each Subsidiary Guarantor. Each of the
Guarantors is referred to individually as a "Guarantor."
"Guaranty Agreement" means a supplemental indenture, in a form satisfactory
to the Trustee, pursuant to which DRI, a Subsidiary Guarantor or any other
Person becomes subject to the applicable terms and conditions of the Indenture.
"Hedging Obligations" of any Person means the obligations of such Person
pursuant to any Oil and Gas Hedging Contract, Interest Rate Agreement or
Currency Agreement.
"Holder" or "Noteholder" means the Person in whose name a Note is
registered on the Registrar's books.
"Incur" means issue, assume, Guarantee, incur or otherwise become liable
for; provided, however, that any Indebtedness or Capital Stock of a Person
existing at the time such Person becomes a Subsidiary (whether by merger,
consolidation, acquisition or otherwise) shall be deemed to be Incurred by such
Subsidiary at the time it becomes a Subsidiary. The term "Incurrence" when used
as a noun shall have a
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correlative meaning. The accretion of principal of a non-interest bearing or
other discount security shall not be deemed the Incurrence of Indebtedness.
"Indebtedness" means, with respect to any Person on any date of
determination (without duplication), (i) the principal of and premium (if any)
in respect of (A) indebtedness of such Person for money borrowed and (B)
indebtedness evidenced by notes, debentures, bonds or other similar instruments
for the payment of which such Person is responsible or liable; (ii) all Capital
Lease Obligations of such Person and all Attributable Debt in respect of
Sale/Leaseback Transactions entered into by such Person; (iii) all obligations
of such Person issued or assumed as the deferred purchase price of property
(which purchase price is due more than six months after the date of taking
delivery of title to such property), including all obligations of such Person
for the deferred purchase price of property under any title retention agreement
(but excluding trade accounts payable arising in the ordinary course of
business); (iv) all obligations of such Person for the reimbursement of any
obligor on any letter of credit, banker's acceptance or similar credit
transaction (other than obligations with respect to letters of credit securing
obligations (other than obligations described in (i) through (iii) above)
entered into in the ordinary course of business of such Person to the extent
such letters of credit are not drawn upon or, if and to the extent drawn upon,
such drawing is reimbursed no later than the tenth Business Day following
receipt by such Person of a demand for reimbursement following payment on the
letter of credit); (v) the amount of all obligations of such Person with respect
to the redemption, repayment or other repurchase of any Disqualified Stock (but
excluding any accrued dividends); (vi) all obligations of such Person relating
to any Production Payment; (vii) all obligations of the type referred to in
clauses (i) through (vi) of other Persons and all dividends of other Persons for
the payment of which, in either case, such Person is responsible or liable,
directly or indirectly, as obligor, guarantor or otherwise, including by means
of any Guarantee (including, with respect to any Production Payment, any
warranties or guarantees of production or payment by such Person with respect to
such Production Payment but excluding other contractual obligations of such
Person with respect to such Production Payment); (viii) all obligations of the
type referred to in clauses (i) through (vii) of other Persons secured by any
Lien on any property or asset of such first-mentioned Person (whether or not
such obligation is assumed by such first-mentioned Person), the amount of such
obligation being deemed to be the lesser of the value of such property or assets
or the amount of the obligation so secured and (ix) to the extent not otherwise
included in this definition, Hedging Obligations of such Person. The amount of
Indebtedness of any Person at any date shall be the outstanding balance at such
date of all unconditional obligations as described above and the maximum
liability, assuming the contingency giving rise to the obligation were to have
occurred on such date, of any Guarantees outstanding at such date.
None of the following shall constitute Indebtedness: (i) indebtedness
arising from agreements providing for indemnification or adjustment of purchase
price or from guarantees securing any obligations of the Company or any of its
Subsidiaries pursuant to such agreements, incurred or assumed in connection with
the disposition of any business, assets or Subsidiary of the Company, other than
guarantees or similar credit support by the Company or any of its Subsidiaries
of Indebtedness incurred by any Person acquiring all or any portion of such
business, assets or Subsidiary for the purpose of financing such acquisition;
(ii) any trade payables or other similar liabilities to trade creditors and
other accrued current liabilities incurred in the ordinary course of business as
the deferred purchase price of property; (iii) any liability for Federal, state,
local or other taxes owed or owing by such Person; (iv) amounts due in the
ordinary course of business to other royalty and working interest owners; (v)
obligations arising from guarantees to suppliers, lessors, licensees,
contractors, franchisees or customers incurred in the ordinary course of
business; (vi) obligations (other than express Guarantees of indebtedness for
borrowed money) in respect of Indebtedness of other Persons arising in
connection with (A) the sale or discount of accounts receivable, (B) trade
acceptances and (C) endorsements of instruments for deposit in the ordinary
course of business; (vii) obligations in respect of performance bonds provided
by the Company or its Subsidiaries in the ordinary course of business and
refinancing thereof; (viii) obligations arising from the honoring by a bank or
other financial institution of a check, draft or similar instrument drawn
against insufficient funds in the ordinary course of business, provided, however
that such obligation is extinguished within two Business Days of its incurrence;
and (ix) obligations in respect of any obligations under workers' compensation
laws and similar legislation.
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"Interest Rate Agreement" means any interest rate swap agreement, interest
rate cap agreement or other financial agreement or arrangement designed to
protect the Company or any Restricted Subsidiary against fluctuations in
interest rates.
"Investment" in any Person means any direct or indirect advance, loan
(other than advances to customers or joint interest partners or drilling
partnerships sponsored by the Company or any Restricted Subsidiary in the
ordinary course of business that are recorded as accounts receivable on the
balance sheet of the lender) or other extensions of credit (including by way of
Guarantee or similar arrangement) or capital contribution to (by means of any
transfer of cash or other property to others or any payment for property or
services for the account or use of others), or any purchase or acquisition of
Capital Stock, Indebtedness or other similar instruments issued by such Person.
For purposes of the definition of "Unrestricted Subsidiary", the definition of
"Restricted Payment" and the covenant described under "-- Certain
Covenants -- Limitation on Restricted Payments," (i) "Investment" shall include
the portion (proportionate to the Company's equity interest in such Subsidiary)
of the fair market value of the net assets of any Subsidiary of the Company at
the time that such Subsidiary is designated an Unrestricted Subsidiary;
provided, however, that upon a redesignation of such Subsidiary as a Restricted
Subsidiary, the Company shall be deemed to continue to have a permanent
"Investment" in an Unrestricted Subsidiary equal to an amount (if positive)
equal to (x) the Company's "Investment" in such Subsidiary at the time of such
redesignation less (y) the portion (proportionate to the Company's equity
interest in such Subsidiary) of the fair market value of the net assets of such
Subsidiary at the time of such redesignation; and (ii) any property transferred
to or from an Unrestricted Subsidiary shall be valued at its fair market value
at the time of such transfer, in each case as determined in good faith by the
Board of Directors.
"Issue Date" means the date on which the Notes are originally issued.
"Lien" means any mortgage, pledge, security interest, encumbrance, lien or
charge of any kind (including any conditional sale or other title retention
agreement or lease in the nature thereof).
"Limited Recourse Production Payments" means, with respect to any
Production Payments, Indebtedness, the terms of which limit the liability of the
Company and its Restricted Subsidiaries solely to the hydrocarbons covered by
such Production Payments; provided, however, that no default with respect to
such Indebtedness would permit any holder of any other Indebtedness of the
Company or any Restricted Subsidiary to declare a default on such other
Indebtedness or cause the payment thereof to be accelerated or payable prior to
its stated maturity.
"Material Change" means an increase or decrease (excluding changes that
result solely from changes in prices and changes resulting from the incurrence
of previously estimated future development costs) of more than 25% during a
fiscal quarter in the discounted future net revenues from proved crude oil and
natural gas reserves of the Company and its Restricted Subsidiaries, calculated
in accordance with clause (a)(i) of the definition of Adjusted Consolidated Net
Tangible Assets; provided, however, that the following will be excluded from the
calculation of Material Change: (i) any acquisitions during the fiscal quarter
of oil and gas reserves that have been estimated by independent petroleum
engineers and with respect to which a report or reports of such engineers exist
and (ii) any disposition of properties existing at the beginning of such fiscal
quarter that have been disposed of in compliance with the covenant described
under "-- Certain Covenants -- Limitation on Sales of Assets and Subsidiary
Stock."
"Moody's" means Moody's Investor's Service, Inc. and its successors.
"Net Available Cash" from an Asset Disposition means cash payments received
therefrom (including any cash payments received by way of deferred payment of
principal pursuant to a note or installment receivable or otherwise, but only as
and when received, but excluding any other consideration received in the form of
assumption by the acquiring Person of Indebtedness or other obligations relating
to such properties or assets or received in any other noncash form) in each case
net of (i) all legal, title and recording tax expenses, commissions and other
fees (including financial and other advisory fees) and expenses incurred, and
all Federal, state, provincial, foreign and local taxes required to be accrued
as a liability under GAAP, as a consequence of such Asset Disposition, (ii) all
payments made on any Indebtedness which is secured by any
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assets subject to such Asset Disposition, in accordance with the terms of any
Lien upon or other security agreement of any kind with respect to such assets,
or which must by its terms, or in order to obtain a necessary consent to such
Asset Disposition, or by applicable law, be repaid out of the proceeds from such
Asset Disposition, (iii) all distributions and other payments required to be
made to minority interest holders in Subsidiaries or joint ventures as a result
of such Asset Disposition and (iv) the deduction of appropriate amounts provided
by the seller as a reserve, in accordance with GAAP, against any liabilities
associated with the property or other assets disposed in such Asset Disposition
and retained by the Company or any Restricted Subsidiary after such Asset
Disposition.
"Net Cash Proceeds", with respect to any issuance or sale of Capital Stock,
means the cash proceeds of such issuance or sale net of attorneys' fees,
accountants' fees, underwriters' or placement agents' fees, discounts or
commissions and brokerage, consultant and other fees actually incurred in
connection with such issuance or sale and net of taxes paid or payable as a
result thereof.
"Net Present Value" means, with respect to any proved hydrocarbon reserves,
the discounted future net cash flows associated with such reserves, determined
in accordance with the rules and regulations (including interpretations thereof)
of the SEC in effect on the Issue Date.
"Net Working Capital" means (a) all current assets of the Company and its
Restricted Subsidiaries minus (b) all current liabilities of the Company and its
Restricted Subsidiaries, except current liabilities included in Indebtedness,
determined in accordance with GAAP.
"Non-recourse Purchase Money Indebtedness" means Indebtedness (other than
Capital Lease Obligations) of the Company or any Subsidiary Guarantor incurred
in connection with the acquisition by the Company or such Subsidiary Guarantor
in the ordinary course of business of fixed assets used in the Oil and Gas
Business (including office buildings and other real property used by the Company
or such Subsidiary Guarantor in conducting its operations) with respect to which
(1) the holders of such Indebtedness agree that they will look solely to the
fixed assets so acquired which secure such Indebtedness, and neither the Company
nor any Restricted Subsidiary (a) is directly or indirectly liable for such
Indebtedness or (b) provides credit support, including any undertaking,
Guarantee, agreement or instrument that would constitute Indebtedness (other
than the grant of a Lien on such acquired fixed assets), and (ii) no default or
event of default with respect to such Indebtedness would cause, or permit (after
notice or passage of time or otherwise), any holder of any other Indebtedness of
the Company or a Subsidiary Guarantor to declare a default or event of default
on such other Indebtedness or cause the payment, repurchase, redemption,
defeasance or other acquisition or retirement for value thereof to be
accelerated or payable prior to any scheduled principal payment, scheduled
sinking fund payment or maturity.
"Oil and Gas Business" means the business of the exploration for, and
exploitation, development, acquisition, production, processing (but not
refining), marketing, storage and transportation of, hydrocarbons, and other
related energy and natural resource businesses (including oil and gas services
businesses related to the foregoing).
"Oil and Gas Hedging Contract" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed to
provide protection against oil and gas price fluctuations.
"Oil and Gas Liens" means (i) Liens on any specific property or any
interest therein, construction thereon or improvement thereto to secure all or
any part of the costs incurred for surveying, exploration, drilling, extraction,
development, operation, production, construction, alteration, repair or
improvement of, in, under or on such property and the plugging and abandonment
of wells located thereon (it being understood that, in the case of oil and gas
producing properties, or any interest therein, costs incurred for "development"
shall include costs incurred for all facilities relating to such properties or
to projects, ventures or other arrangements of which such properties form a part
or which relate to such properties or interests); (ii) Liens on an oil or gas
producing property to secure obligations incurred or guarantees of obligations
incurred in connection with or necessarily incidental to commitments for the
purchase or sale of, or the transportation or distribution of, the products
derived from such property; (iii) Liens arising under partnership agreements,
oil
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and gas leases, overriding royalty agreements, net profits agreements,
production payment agreements, royalty trust agreements, incentive compensation
programs on terms that are reasonably customary in the Oil and Gas Business for
geologists, geophysicists and other providers of technical services to the
Company or a Restricted Subsidiary, master limited partnership agreements,
farm-out agreements, farm-in agreements, division orders, contracts for the
sale, purchase, exchange, transportation, gathering or processing of oil, gas or
other hydrocarbons, unitizations and pooling designations, declarations, orders
and agreements, development agreements, operating agreements, production sales
contracts, area of mutual interest agreements, gas balancing or deferred
production agreements, injection, repressuring and recycling agreements, salt
water or other disposal agreements, seismic or geophysical permits or
agreements, and other agreements which are customary in the Oil and Gas
Business; provided, however, that in all instances such Liens are limited to the
assets that are the subject of the relevant agreement, program, order or
contract; (iv) Liens arising in connection with Production Payments; and (v)
Liens on pipelines or pipeline facilities that arise by operation of law.
"Permitted Business Investment" means any investment made in the ordinary
course of, and of a nature that is or shall have become customary in, the Oil
and Gas Business including investments or expenditures for actively exploiting,
exploring for, acquiring, developing, producing, processing, gathering,
marketing or transporting oil and gas through agreements, transactions,
interests or arrangements which permit one to share risks or costs, comply with
regulatory requirements regarding local ownership or satisfy other objectives
customarily achieved through the conduct of Oil and Gas Business jointly with
third parties, including (i) ownership interests in oil and gas properties,
processing facilities, gathering systems, pipelines or ancillary real property
interests and (ii) Investments in the form of or pursuant to operating
agreements, processing agreements, farm-in agreements, farm-out agreements,
development agreements, area of mutual interest agreements, unitization
agreements, pooling agreements, joint bidding agreements, service contracts,
joint venture agreements, partnership agreements (whether general or limited),
subscription agreements, stock purchase agreements and other similar agreements
(including for limited liability companies) with third parties, excluding,
however, Investments in corporations other than Restricted Subsidiaries.
"Permitted Holders" means TPG Advisors, Inc. or any Person who on the Issue
Date is an Affiliate thereof or any Person controlled by TPG Advisors, Inc.
"Permitted Investment" means an Investment by the Company or any Restricted
Subsidiary in (i) a Restricted Subsidiary or a Person that will, upon the making
of such Investment, become a Restricted Subsidiary; provided, however,that the
primary business of such Restricted Subsidiary is an Oil and Gas Business; (ii)
another Person if as a result of such Investment such other Person is merged or
consolidated with or into, or transfers or conveys all or substantially all its
assets to, the Company or a Restricted Subsidiary; provided, however, that such
Person's primary business is an Oil and Gas Business; (iii) Temporary Cash
Investments; (iv) receivables owing to the Company or any Restricted Subsidiary
if created or acquired in the ordinary course of business and payable or
dischargeable in accordance with customary trade terms; provided, however, that
such trade terms may include such concessionary trade terms as the Company or
any such Restricted Subsidiary deems reasonable under the circumstances; (v)
payroll, travel and similar advances to cover matters that are expected at the
time of such advances ultimately to be treated as expenses for accounting
purposes and that are made in the ordinary course of business; (vi) loans or
advances to employees made in the ordinary course of business; (vii) stock,
obligations or securities received in settlement of debts created in the
ordinary course of business and owing to the Company or any Restricted
Subsidiary or in satisfaction of judgments; (viii) any Person to the extent such
Investment represents the non-cash portion of the consideration received for an
Asset Disposition as permitted pursuant to the covenant described under
"-- Certain Covenants -- Limitation on Sales of Assets and Subsidiary Stock;"
(ix) Permitted Business Investments; (x) Investments intended to promote the
Company's strategic objectives in the Oil and Gas Business in an aggregate
amount not to exceed 5.0% of ACNTA (determined as of the date of the making of
any such Investment) at any one time outstanding (which Investments shall be
deemed to be no longer outstanding only upon and to the extent of the return of
capital thereof); and (xi) Investments made pursuant to Hedging Obligations of
the Company and the Restricted Subsidiaries.
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"Permitted Liens" means, with respect to any Person, (a) Liens existing as
of the Issue Date; (b) Liens securing the Notes, the DRI Guaranty, any
Subsidiary Guaranty and other obligations arising under the Indenture; (c) any
Lien existing on any property of a Person at the time such Person is merged or
consolidated with or into the Company or a Restricted Subsidiary or becomes a
Restricted Subsidiary (and not incurred in anticipation of or in connection with
such transaction), provided that such Liens are not extended to other property
of the Company or the Restricted Subsidiaries; (d) any Lien existing on any
property at the time of the acquisition thereof (and not incurred in
anticipation of or in connection with such transaction), provided that such
Liens are not extended to other property of the Company or the Restricted
Subsidiaries; (e) any Lien incurred in the ordinary course of business
incidental to the conduct of the business of the Company or the Restricted
Subsidiaries or the ownership of their property (including (i) easements, rights
of way and similar encumbrances, (ii) rights or title of lessors under leases
(other than Capital Lease Obligations), (iii) rights of collecting banks having
rights of setoff, revocation, refund or chargeback with respect to money or
instruments of the Company or the Restricted Subsidiaries on deposit with or in
the possession of such banks, (iv) Liens imposed by law, including Liens under
workers' compensation or similar legislation and mechanics', carriers',
warehousemen's, materialmen's, suppliers' and vendors' Liens, (v) Liens incurred
to secure performance of obligations with respect to statutory or regulatory
requirements, performance or return-of-money bonds, surety bonds or other
obligations of a like nature and incurred in a manner consistent with industry
practice and (vi) Oil and Gas Liens, in each case which are not incurred in
connection with the borrowing of money, the obtaining of advances or credit or
the payment of the deferred purchase price of property (other than trade
accounts payable arising in the ordinary course of business); (f) Liens for
taxes, assessments and governmental charges not yet due or the validity of which
are being contested in good faith by appropriate proceedings, promptly
instituted and diligently conducted, and for which adequate reserves have been
established to the extent required by GAAP as in effect at such time; (g) Liens
incurred to secure appeal bonds and judgment and attachment Liens, in each case
in connection with litigation or legal proceedings that are being contested in
good faith by appropriate proceedings, so long as reserves have been established
to the extent required by GAAP as in effect at such time and so long as such
Liens do not encumber assets by an aggregate amount (together with the amount of
any unstayed judgments against the Company or any Restricted Subsidiary but
excluding any such Liens to the extent securing insured or indemnified judgments
or orders) in excess of $10.0 million; (h) Liens securing Hedging Obligations of
the Company and its Restricted Subsidiaries; (i) Liens securing purchase money
Indebtedness or Capital Lease Obligations, provided that such Liens attach only
to the property acquired with the proceeds of such purchase money Indebtedness
or the property which is the subject of such Capital Lease Obligations; (j)
Liens securing Non-recourse Purchase Money Indebtedness granted in connection
with the acquisition by the Company or any Restricted Subsidiary in the ordinary
course of business of fixed assets used in the Oil and Gas Business (including
the office buildings and other real property used by the Company or such
Restricted Subsidiary in conducting its operations), provided that (i) such
Liens attach only to the fixed assets acquired with the proceeds of such
Non-recourse Purchase Money Indebtedness and (ii) such Non-recourse Purchase
Money Indebtedness is not in excess of the purchase price of such fixed assets;
(k) Liens resulting from the deposit of funds or evidences of Indebtedness in
trust for the purpose of decreasing or legally defeasing Indebtedness of the
Company or any Restricted Subsidiary so long as such deposit of funds is
permitted by the provisions of the Indenture described under "-- Limitation on
Restricted Payments;" (l) Liens resulting from a pledge of Capital Stock of a
Person that is not a Restricted Subsidiary to secure obligations of such Person
and any refinancings thereof; (m) Liens to secure any permitted extension,
renewal, refinancing, refunding or exchange (or successive extensions, renewals,
refinancings, refundings or exchanges), in whole or in part, of or for any
Indebtedness secured by Liens referred to in clauses (a), (b), (c), (d), (i) and
(j) above; provided, however, that (i) such new Lien shall be limited to all or
part of the same property (including future improvements thereon and accessions
thereto) subject to the original Lien and (ii) the Indebtedness secured by such
Lien at such time is not increased to any amount greater than the sum of (A) the
outstanding principal amount or, if greater, the committed amount of the
Indebtedness secured by such original Lien immediately prior to such extension,
renewal, refinancing, refunding or exchange and (B) an amount necessary to pay
any fees and expenses, including premiums, related to such refinancing,
refunding, extension, renewal or replacement; and (n) Liens in favor of DRI, the
Company, or a Restricted Subsidiary. Notwithstanding anything in this paragraph
to the contrary, the term "Permitted Liens" shall not include
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Liens resulting from the creation, incurrence, issuance, assumption or Guarantee
of any Production Payments other than (i) any such Liens existing as of the
Issue Date, (ii) Production Payments in connection with the acquisition of any
property after the Issue Date, provided that any such Lien created in connection
therewith is created, incurred, issued, assumed or Guaranteed in connection with
the financing of, and within 60 days after the acquisition of, such property and
(iii) Production Payments other than those described in clauses (i) and (ii) of
this sentence, to the extent such Production Payments constitute Asset
Dispositions made pursuant to and in compliance with the provisions of the
Indenture described under "-- Limitation on Sales of Assets and Subsidiary
Stock" and (iv) incentive compensation programs for geologists, geophysicists
and other providers of technical services to the Company and any Restricted
Subsidiary; provided, however, that, in the case of the immediately foregoing
clauses (i), (ii), (iii) and (iv), any Lien created in connection with any such
Production Payments shall be limited to the property that is the subject of such
Production Payments.
"Permitted Marketing Obligations" means Indebtedness of the Company or any
Restricted Subsidiary under letter of credit or borrowed money obligations, or
in lieu of or in addition to such letters of credit or borrowed money,
guarantees of such Indebtedness or other obligations of the Company or any
Restricted Subsidiary by any other Restricted Subsidiary, as applicable, related
to the purchase by the Company or any Restricted Subsidiary of hydrocarbons for
which the Company or such Restricted Subsidiary has contracts to sell; provided,
however, that in the event that such Indebtedness or obligations are guaranteed
by the Company or any Restricted Subsidiary, then either (i) the Person with
which the Company or such Restricted Subsidiary has contracts to sell has an
investment grade credit rating from S&P or Moody's, or in lieu thereof, a Person
guaranteeing the payment of such obligated Person has an investment grade credit
rating from S & P or Moody's, or (ii) such Person posts, or has posted for it, a
letter of credit in favor of the Company or such Restricted Subsidiary with
respect to all such Person's obligations to the Company or such Restricted
Subsidiary under such contracts.
"Person" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization, government
or any agency or political subdivision thereof or any other entity.
"Preferred Stock", as applied to the Capital Stock of any corporation,
means Capital Stock of any class or classes (however designated) which is
preferred as to the payment of dividends, or as to the distribution of assets
upon any voluntary or involuntary liquidation or dissolution of such
corporation, over shares of Capital Stock of any other class of such
corporation.
The term "principal" of a Note means the principal of the Note plus the
premium, if any, payable on the Note which is due or overdue or is to become due
at the relevant time.
"Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
"Public Market" means any time when at least 15% of the total issued and
outstanding common stock of DRI has been distributed by means of an effective
registration statement under the Securities Act or sales pursuant to Rule 144
under the Securities Act.
"Refinance" means, in respect of any Indebtedness, to refinance, extend,
renew, refund, repay, prepay, redeem, decease or retire, or to issue other
Indebtedness in exchange or replacement for, such Indebtedness. "Refinanced" and
"Refinancing" shall have correlative meanings.
"Refinancing Indebtedness" means Indebtedness that Refinances any
Indebtedness of the Company or any Restricted Subsidiary existing on the Issue
Date or Incurred in compliance with the Indenture including Indebtedness that
Refinances Refinancing Indebtedness; provided, however, that (i) such
Refinancing Indebtedness has a Stated Maturity no earlier than the Stated
Maturity of the Indebtedness being Refinanced, (ii) such Refinancing
Indebtedness has an Average Life at the time such Refinancing Indebtedness is
Incurred that is equal to or greater than the Average Life of the Indebtedness
being Refinanced, (iii) such Refinancing Indebtedness has an aggregate principal
amount (or if Incurred with original issue discount, an aggregate issue price)
that is equal to or less than the aggregate principal amount (or if Incurred
with original issue discount, the aggregate accreted value) then outstanding or
committed (plus fees and expenses,
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including any premium and defeasance costs) under the Indebtedness being
Refinanced and (iv) if the Indebtedness being Refinanced is Non-recourse
Purchase Money Indebtedness, such Refinancing Indebtedness satisfies clauses (i)
and (ii) of the definition of "Non-recourse Purchase Money Indebtedness;"
provided further, however, that Refinancing Indebtedness shall not include (x)
Indebtedness of a Subsidiary that Refinances Indebtedness of the Company or (y)
Indebtedness of the Company or a Restricted Subsidiary that Refinances
Indebtedness of an Unrestricted Subsidiary.
"Representative" means any trustee, agent or representative (if any) for an
issue of Senior Indebtedness of the Company or of a Guarantor.
"Restricted Payment" with respect to any Person means (i) the declaration
or payment of any dividends or any other distributions of any sort in respect of
its Capital Stock (including any payment in connection with any merger or
consolidation involving such Person) or similar payment to the direct or
indirect holders of its Capital Stock (other than (x) dividends or distributions
payable solely in its Capital Stock (other than Disqualified Stock), (y)
dividends or distributions payable solely to the Company or a Restricted
Subsidiary, and (z) pro rata dividends or other distributions made by a
Subsidiary that is not a Wholly Owned Subsidiary to minority stockholders (or
owners of an equivalent interest in the case of a Subsidiary that is an entity
other than a corporation)), (ii) the purchase, redemption or other acquisition
or retirement for value of any Capital Stock of the Company held by any Person
or of any Capital Stock of a Restricted Subsidiary held by any Affiliate of the
Company (other than a Restricted Subsidiary), including the exercise of any
option to exchange any Capital Stock (other than into Capital Stock of the
Company that is not Disqualified Stock), (iii) the purchase, repurchase,
redemption, defeasance or other acquisition or retirement for value, prior to
scheduled maturity, scheduled repayment or scheduled sinking fund payment of any
Subordinated Obligations of such Person (other than the purchase, repurchase or
other acquisition of Subordinated Obligations purchased in anticipation of
satisfying a sinking fund obligation, principal installment or final maturity,
in each case due within one year of the date of acquisition) or (iv) the making
of any Investment (other than a Permitted Investment) in any Person.
"Restricted Subsidiary" means any Subsidiary of the Company that is not an
Unrestricted Subsidiary.
"S&P" means Standard & Poor's Rating Services, a division of The
McGraw-Hill Company, Inc., and its successors.
"Sale/Leaseback Transaction" means an arrangement relating to property now
owned or hereafter acquired whereby the Company or a Restricted Subsidiary
transfers such property to a Person and the Company or a Restricted Subsidiary
leases it from such Person, provided that the fair market value of such property
(as reasonably determined by the Board of Directors acting in good faith) is $10
million or more.
"SEC" means the Securities and Exchange Commission.
"Secured Indebtedness" means any Indebtedness of the Company secured by a
Lien.
"Senior Indebtedness" means with respect to any Person (i) Indebtedness of
such Person, and all obligations of such Person under any Credit Facility,
whether outstanding on the Issue Date or thereafter Incurred and (ii) accrued
and unpaid interest (including interest accruing on or after the filing of any
petition in bankruptcy or for reorganization relating such Person to the extent
post-filing interest is allowed in such proceeding) in respect of (A)
indebtedness of such Person for money borrowed and (B) indebtedness evidenced by
notes, debentures, bonds or other similar instruments for the payment of which
such Person is responsible or liable unless, with respect to obligations
described in the immediately preceding clause (i) or (ii), in the instrument
creating or evidencing the same or pursuant to which the same is outstanding, it
is provided that such obligations are not superior in right of payment to the
Notes or the applicable Guaranty; provided, however, that Senior Indebtedness
shall not include (1) any obligation of such Person to any Subsidiary of such
Person, (2) any liability for Federal, state, local or other taxes owed or owing
by such Person, (3) any accounts payable or other liability to trade creditors
arising in the ordinary course of business (including guarantees thereof or
instruments evidencing such liabilities), (4) any Indebtedness of such Person
(and any accrued and unpaid interest in respect thereof) which is subordinate or
junior in any respect to any other Indebtedness or other obligation of such
Person or (5) that portion of any Indebtedness which at the
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time of Incurrence is Incurred in violation of the Indenture (other than, in the
case of the Company or any Guarantor that Guarantees any Credit Facility,
Indebtedness under any Credit Facility that is Incurred on the basis of a
representation by the Company or the applicable Guarantor to the applicable
lenders that such Person is permitted to Incur such Indebtedness under the
Indenture).
"Senior Subordinated Indebtedness" means (i) with respect to the Company,
the Notes and any other Indebtedness of the Company that specifically provides
that such Indebtedness is to rank pari passu with the Notes in right of payment
and is not subordinated by its terms in right of payment to any Indebtedness or
other obligation of the Company which is not Senior Indebtedness of the Company
and (ii) with respect to each Guarantor, its Guaranty of the Notes and any other
indebtedness of such Person that specifically provides that such Indebtedness
rank pari passu with its applicable Guaranty in respect of payment and is not
subordinated by its terms in respect of payment to any Indebtedness or other
obligation of such Person which is not Senior Indebtedness of such Person.
"Significant Subsidiary" means any Restricted Subsidiary that would be a
"Significant Subsidiary" of the Company within the meaning of Rule 1-02 under
Regulation S-X promulgated by the SEC.
"Stated Maturity" means, with respect to any security, the date specified
in such security as the fixed date on which the final payment of principal of
such security is due and payable, including pursuant to any mandatory redemption
provision (but excluding any provision providing for the repurchase of such
security at the option of the holder thereof upon the happening of any
contingency unless such contingency has occurred).
"Stock Offering" means a primary offering, whether public or private, of
shares of common stock of DRI or the Company.
"Subordinated Obligation" means any Indebtedness of the Company or any
Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which
is subordinate or junior in right of payment to, in the case of the Company, the
Notes or, in the case of a Guarantor, its Guaranty pursuant to a written
agreement to that effect.
"Subsidiary" means, in respect of any Person, any corporation, association,
partnership or other business entity of which more than 50% of the total voting
power of shares of Capital Stock or other interests (including partnership
interests) entitled (without regard to the occurrence of any contingency) to
vote in the election of directors, managers or trustees thereof is at the time
owned or controlled, directly or indirectly, by (i) such Person, (ii) such
Person and one or more Subsidiaries of such Person or (iii) one or more
Subsidiaries of such Person.
"Subsidiary Guarantor" means any Subsidiary of the Company that Guarantees
the Notes pursuant to a Subsidiary Guaranty.
"Subsidiary Guaranty" means a Guarantee of the Notes (on an unconditional,
unsecured senior subordinated basis) by a Restricted Subsidiary pursuant to the
terms of the Indenture.
"Temporary Cash Investments" means any of the following: (i) any investment
in direct obligations of the United States of America or any agency thereof or
obligations guaranteed by the United States of America or any agency thereof,
(ii) investments in time deposit accounts, certificates of deposit and money
market deposits maturing within one year of the date of acquisition thereof
issued by a bank or trust company which is organized under the laws of the
United States of America, any state thereof or any foreign country recognized by
the United States, and which bank or trust company has capital, surplus and
undivided profits aggregating in excess of $200.0 million (or the foreign
currency equivalent thereof) and has outstanding debt which is rated "A" (or
such similar equivalent rating) or higher by at least one nationally recognized
credit rating organization (as defined in Rule 436 under the Securities Act) or
any money-market fund sponsored by a registered broker dealer or mutual fund
distributor whose assets consist of obligations of the types described in
clauses (i), (ii), (iii), (iv) and (v) hereof, (iii) repurchase obligations with
a term of not more than 30 days for underlying securities of the types described
in clause (i) above entered into with a bank meeting the qualifications
described in clause (ii) above, (iv) investments in commercial paper, maturing
not more than
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one year after the date of acquisition, issued by a Person (other than an
Affiliate of the Company) organized and in existence under the laws of the
United States of America or any foreign country recognized by the United States
of America with a rating at the time as of which any investment therein is made
of "P-2" (or higher) according to Moody's or "A-2" (or higher) according to S&P
or "R-1" (or higher) by Dominion Bond Rating Service Limited or Canadian Bond
Rating Service, Inc. (in the case of a Canadian issuer), (v) investments in
securities with maturities of six months or less from the date of acquisition
issued or fully guaranteed by any state, commonwealth or territory of the United
States of America, or by any political subdivision or taxing authority thereof,
and rated at least "A" by S&P or "A" by Moody's and (vi) investments in
asset-backed securities maturing within one year of the date of acquisition
thereof with a long-term rating at the time as of which any investment therein
is made of "A3" (or higher) by Dominion Bond Rating Service Limited or Canadian
Bond Rating Service, Inc. (in the case of a Canadian issuer).
"Unrestricted Subsidiary" means (i) any Subsidiary of the Company that at
the time of determination shall be designated an Unrestricted Subsidiary by the
Board of Directors in the manner provided below and (ii) any Subsidiary of an
Unrestricted Subsidiary. The Board of Directors may designate any Subsidiary of
the Company (including any newly acquired or newly formed Subsidiary) to be an
Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns
any Capital Stock or Indebtedness of, or holds any Lien on any property of, the
Company or any other Subsidiary of the Company that is not a Subsidiary of the
Subsidiary to be so designated; provided, however, that either (A) the
Subsidiary to be so designated has total assets of $1,000 or less or (B) if such
Subsidiary has assets greater than $1,000, such designation would be permitted
under the covenant described under "-- Certain Covenants -- Limitation on
Restricted Payments". The Board of Directors may designate any Unrestricted
Subsidiary to be a Restricted Subsidiary; provided, however, that immediately
after giving effect to such designation (x) the Company could Incur $1.00 of
additional Indebtedness under paragraph (a) of the covenant described under
"-- Certain Covenants -- Limitation on Indebtedness" and (y) no Default shall
have occurred and be continuing. Any such designation by the Board of Directors
shall be evidenced by the Company to the Trustee by promptly filing with the
Trustee a copy of the board resolution giving effect to such designation and an
Officers' Certificate certifying that such designation complied with the
foregoing provisions.
"U.S. Government Obligations" means direct obligations (or certificates
representing an ownership interest in such obligations) of the United States of
America (including any agency or instrumentality thereof) for the payment of
which the full faith and credit of the United States of America is pledged and
which are not callable at the issuer's option.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" of a Person means all classes of Capital Stock or other
interests (including partnership interests) of such Person then outstanding and
normally entitled (without regard to the occurrence of any contingency) to vote
in the election of directors, managers or trustees thereof.
"Wholly Owned Subsidiary" means a Restricted Subsidiary all the Capital
Stock of which (other than directors' qualifying shares and shares held by other
Persons to the extent such shares are required by applicable law to be held by a
Person other than the Company or a Restricted Subsidiary) is owned by the
Company or one or more Wholly Owned Subsidiaries.
CERTAIN COVENANTS
The Indenture contains covenants including, among others, the following:
LIMITATION ON INDEBTEDNESS. (a) The Company shall not, and shall not permit
any Restricted Subsidiary to, Incur, directly or indirectly, any Indebtedness;
provided, however, that the Company or Restrictive Subsidiary may Incur
Indebtedness if, on the date of such Incurrence and after giving effect thereto,
either (i) the Consolidated Coverage Ratio equals or exceeds 2.25 to 1.0.
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(b) Notwithstanding the foregoing paragraph (a), the Company and any
Restricted Subsidiary may Incur the following Indebtedness:
(1) Indebtedness Incurred pursuant to any Credit Facility, so long as
the aggregate amount of all Indebtedness outstanding under all Credit
Facilities does not, at any one time, exceed the aggregate amount of
borrowing availability as of such date under all Credit Facilities that
determine availability on the basis of a borrowing base or other
asset-based calculation; provided, however, that in no event shall such
amount exceed the greater of (x) $300 million and (y)75% of ACNTA as of the
date of such Incurrence;
(2) Indebtedness owed to and held by the Company or a Wholly Owned
Subsidiary; provided, however, that any subsequent issuance or transfer of
any Capital Stock which results in any such Wholly Owned Subsidiary ceasing
to be a Wholly Owned Subsidiary or any subsequent transfer of such
Indebtedness (other than to the Company or another Wholly Owned Subsidiary)
shall be deemed, in each case, to constitute the Incurrence of such
Indebtedness by the issuer thereof;
(3) The Notes (other than additional Notes);
(4) Indebtedness outstanding on the Issue Date (other than
Indebtedness described in clause (1), (2) or (3) of this covenant);
(5) Indebtedness of (A) a Restricted Subsidiary Incurred and
outstanding on or prior to the date on which such Restricted Subsidiary was
acquired by the Company (other than Indebtedness Incurred in connection
with, or to provide all or any portion of the funds or credit support
utilized to consummate, the transaction or series of related transactions
pursuant to which such Restricted Subsidiary became a Restricted Subsidiary
or was acquired by the Company) and (B) the Company or a Restricted
Subsidiary Incurred for the purpose of financing all or any part of the
cost of acquiring oil and gas properties, another person (other than a
Person that was, immediately prior to such acquisition, a Subsidiary of the
Company) engaged in the Oil and Gas Business or all or substantially all
the assets of such a person; provided, however, that, in the case of each
of clause (A) and clause (B) above, on the date of such Incurrence and
after giving effect thereto, the Consolidated Coverage Ratio equals or
exceeds 2.0 to 1.0;
(6) Refinancing Indebtedness in respect of Indebtedness Incurred
pursuant to paragraph (a) or pursuant to clause (3), (4), (5) above, this
clause (6) or clause (7) below; provided, however, that to the extent such
Refinancing Indebtedness directly or indirectly Refinances Indebtedness or
Preferred Stock of a Restricted Subsidiary described in clause (5), such
Refinancing Indebtedness shall be Incurred only by such Restricted
Subsidiary or the Company;
(7) Non-recourse Purchase Money Indebtedness;
(8) Indebtedness with respect to Production Payments; provided,
however, that any such Indebtedness shall be Limited Recourse Production
Payments; provided further, however, that the Net Present Value of the
reserves related to such Production Payments shall not exceed 30% of ACNTA
at the time of Incurrence;
(9) Indebtedness consisting of the Guaranties and any Guarantees of
Indebtedness Incurred by the Company pursuant to clauses (1) and (3);
(10) Indebtedness consisting of Interest Rate Agreements directly
related to Indebtedness permitted to be Incurred by the Company and its
Restricted Subsidiaries pursuant to the Indenture;
(11) Indebtedness under Oil and Gas Hedging Contracts and Currency
Agreements entered into in the ordinary course of business for the purpose
of limiting risks that arise in the ordinary course of business of the
Company and its Restricted Subsidiaries;
(12) Indebtedness in respect of bid, performance or surety obligations
issued by or for the account of the Company or any Restricted Subsidiary in
the ordinary course of business, including Guarantees
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and letters of credit functioning as or supporting such bid, performance or
surety obligations (in each case other than for an obligation for money
borrowed);
(13) Indebtedness of the Company or a Restricted Subsidiary Incurred
to finance capital expenditures and Refinancing Indebtedness Incurred in
respect thereof in an aggregate amount which, when taken together with the
amount of all other Indebtedness Incurred pursuant to this clause (13) and
then outstanding, does not exceed $20 million;
(14) Permitted Marketing Obligations;
(15) In-kind obligations relating to oil and gas balancing positions
arising in the ordinary course of business; and
(16) Indebtedness in an aggregate amount which, together with the
amount of all other Indebtedness of the Company and its Restricted
Subsidiaries outstanding on the date of such Incurrence (other than
Indebtedness permitted by clauses (1) through (15) above or paragraph (a))
does not exceed $30 million.
(c) Notwithstanding the foregoing, the Company shall not, and shall not
permit any Subsidiary Guarantor to, Incur any Indebtedness pursuant to the
foregoing paragraph (b) if the proceeds thereof are used, directly or
indirectly, to Refinance any Subordinated Obligations unless such Indebtedness
shall be subordinated to the Notes or the relevant Subsidiary Guarantor, as the
case may be to at least the same extent as such Subordinated Obligations.
(d) For purposes of determining compliance with the foregoing covenant, (i)
in the event that an item of Indebtedness meets the criteria of more than one of
the types of Indebtedness described above, the Company, in its sole discretion,
will classify such item of Indebtedness and only be required to include the
amount and type of such Indebtedness in one of the above clauses and (ii) an
item of Indebtedness may be divided and classified in more than one of the types
of Indebtedness described above.
INCURRENCE OF LAYERED INDEBTEDNESS. Notwithstanding paragraphs (a) and (b)
of the covenant described above under "-- Limitation on Indebtedness," DRI and
the Company shall not, and the Company shall not permit any Subsidiary Guarantor
to, Incur any Indebtedness if such Indebtedness is subordinate or junior in
ranking in any respect to any Senior Indebtedness of DRI, the Company or such
Subsidiary Guarantor, as applicable, unless such Indebtedness is Senior
Subordinated Indebtedness or is expressly subordinated in right of payment to
Senior Subordinated Indebtedness.
LIMITATION ON RESTRICTED PAYMENTS. (a) The Company shall not, and shall not
permit any Restricted Subsidiary, directly or indirectly, to make a Restricted
Payment if at the time the Company or such Restricted Subsidiary makes such
Restricted Payment: (1) a Default shall have occurred and be continuing (or
would result therefrom); (2) the Company is not able to Incur an additional
$1.00 of Indebtedness pursuant to paragraph (a) of the covenant described under
"-- Limitation on Indebtedness"; or (3) the aggregate amount of such Restricted
Payment and all other Restricted Payments since the Issue Date would exceed the
sum of: (A) 50% of the aggregate Consolidated Net Income of the Company accrued
on a cumulative basis commencing on the last day of the fiscal quarter
immediately preceding the Issue Date, and ending on the last day of the fiscal
quarter ending on or immediately preceding the date of such proposed Restricted
Payment (or, if such aggregate Consolidated Net Income shall be a deficit, minus
100% of such deficit); (B) the aggregate Net Cash Proceeds received by the
Company from the issuance or sale of its Capital Stock (other than Disqualified
Stock) subsequent to the Issue Date (other than an issuance or sale to a
Subsidiary of the Company and other than an issuance or sale to an employee
stock ownership plan or to a trust established by the Company or any of its
Subsidiaries for the benefit of their employees); (C) the aggregate Net Cash
Proceeds received by the Company from the issue or sale subsequent to the Issue
Date of its Capital Stock (other than Disqualified Stock) to an employee stock
ownership plan; provided, however, that if such employee stock ownership plan
incurs any Indebtedness with respect thereto, such aggregate amount shall be
limited to an amount equal to any increase in the Consolidated Net Worth of the
Company resulting from principal repayments made by such employee stock
ownership plan with respect to such Indebtedness;
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(D) the amount by which Indebtedness of the Company is reduced on the Company's
balance sheet upon the conversion or exchange (other than by a Subsidiary of the
Company) subsequent to the Issue Date, of any Indebtedness of the Company
convertible or exchangeable for Capital Stock (other than Disqualified Stock) of
the Company (less the amount of any cash, or the fair value of any other
property, distributed by the Company upon such conversion or exchange); and (E)
an amount equal to the sum of (i) the net reduction in Investments in any Person
resulting from dividends, repayments of loans or advances or other transfers of
assets, in each case to the Company or any Restricted Subsidiary from such
Person, and (ii) the portion (proportionate to the Company's equity interest in
such Subsidiary) of the fair market value of the net assets of an Unrestricted
Subsidiary at the time such Unrestricted Subsidiary is designated a Restricted
Subsidiary; provided, however, that the foregoing sum shall not exceed, in the
case of any Person, the amount of Investments previously made (and treated as a
Restricted Payment) by the Company or any Restricted Subsidiary in such Person.
(b) The provisions of the foregoing paragraph (a) shall not prohibit: (i)
dividends paid within 60 days after the date of declaration thereof if at such
date of declaration such dividend would have complied with this covenant;
provided, however, that at the time of payment of such dividend, no other
Default shall have occurred and be continuing (or result therefrom); provided
further, however, that such dividend shall be included in the calculation of the
amount of Restricted Payments; (ii) any purchase or redemption of Capital Stock
or Subordinated Obligations of the Company made by exchange for, or out of the
proceeds of the substantially concurrent sale of, Capital Stock of the Company
(other than Disqualified Stock and other than Capital Stock issued or sold to a
Subsidiary of the Company or an employee stock ownership plan or to a trust
established by the Company or any of its Subsidiaries for the benefit of their
employees); provided, however, that (A) such purchase or redemption shall be
excluded in the calculation of the amount of Restricted Payments and (B) the Net
Cash Proceeds from such sale shall be excluded from the calculation of amounts
under clause (3)(B) of paragraph (a) above (but only to the extent that such Net
Cash Proceeds were used to purchase or redeem such Capital Stock as provided in
this clause (ii)); (iii) any purchase, repurchase, redemption, defeasance or
other acquisition or retirement for value of Subordinated Obligations of the
Company made by exchange for, or out of the proceeds of the substantially
concurrent sale of, Subordinated Obligations of the Company; provided, however,
that such purchase, repurchase, redemption, defeasance or other acquisition or
retirement for value shall be excluded in the calculation of the amount of
Restricted Payments; (iv) the repurchase of shares of, or options to purchase
shares of, common stock of the Company or any of its Subsidiaries from
employees, former employees, directors or former directors of the Company or any
of its Subsidiaries (or permitted transferees of such employees, former
employees, directors or former directors), pursuant to the terms of the
agreements (including employment agreements) or plans (or amendments thereto)
approved by the Board of Directors under which such individuals purchase or sell
or are granted the option to purchase or sell, shares of such common stock;
provided, however, that the aggregate amount of such repurchases shall not
exceed $2 million in any calendar year; provided further, however, that such
repurchases shall be excluded in the calculation of the amount of Restricted
Payments; (v) loans made to officers, directors or employees of DRI, the Company
or any Restricted Subsidiary approved by the Board of Directors (or a duly
authorized officer), the net cash proceeds of which are used solely (A) to
purchase common stock of DRI in connection with a restricted stock or employee
stock purchase plan, or to exercise stock options received pursuant to an
employee or director stock option plan or other incentive plan, in a principal
amount not to exceed the exercise price of such stock options or (B) to
refinance loans, together with accrued interest thereon, made pursuant to item
(A) of this clause (v); provided, however, that such loans shall be excluded in
the calculation of the amount of Restricted Payments; or (vi) other Restricted
Payments in an aggregate amount not to exceed $20 million; provided however,
that such Restricted Payments shall be excluded in the calculation of the amount
of Restricted Payments.
LIMITATION ON RESTRICTIONS ON DISTRIBUTIONS FROM RESTRICTED SUBSIDIARIES.
The Company shall not, and shall not permit any Restricted Subsidiary to, create
or otherwise cause or permit to exist or become effective any consensual
encumbrance or restriction on the ability of any Restricted Subsidiary (a) to
pay dividends or make any other distributions on its Capital Stock or pay any
Indebtedness owed to the Company or a Restricted Subsidiary, (b) to make any
loans or advances to the Company or a Restricted Subsidiary or (c) to transfer
any of its property or assets to the Company or a Restricted Subsidiary, except:
(i) any encumbrance
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or restriction in the Credit Agreement on the Issue Date or pursuant to any
other agreement in effect on the Issue Date; (ii) any encumbrance or restriction
with respect to a Restricted Subsidiary pursuant to an agreement relating to any
Indebtedness Incurred by such Restricted Subsidiary on or prior to the date on
which such Restricted Subsidiary was acquired by the Company (other than
Indebtedness Incurred as consideration in, or to provide all or any portion of
the funds or credit support utilized to consummate, the transaction or series of
related transactions pursuant to which such Restricted Subsidiary became a
Restricted Subsidiary or was acquired by the Company) and outstanding on such
date; (iii) any encumbrance or restriction pursuant to an agreement effecting a
Refinancing of Indebtedness Incurred pursuant to an agreement referred to in
clause (i) or (ii) of this covenant or this clause (iii) or contained in any
amendment to an agreement referred to in clause (i) or (ii) of this covenant or
this clause (iii); provided, however, that the encumbrances and restrictions
with respect to such Restricted Subsidiary contained in any such refinancing
agreement or amendment are no less favorable to the Noteholders than
encumbrances and restrictions with respect to such Restricted Subsidiary
contained in such agreements; (iv) any such encumbrance or restriction
consisting of customary nonassignment provisions in leases governing leasehold
interests to the extent such provisions restrict the transfer of the lease or
the property leased thereunder; (v) in the case of clause (c) above,
restrictions contained in security agreements or mortgages securing Indebtedness
of a Restricted Subsidiary to the extent such restrictions restrict the transfer
of the property subject to such security agreements or mortgages; and (vi) any
restriction with respect to a Restricted Subsidiary imposed pursuant to an
agreement entered into for the sale or disposition of all or substantially all
the Capital Stock or assets of such Restricted Subsidiary pending the closing of
such sale or disposition.
LIMITATION ON SALES OF ASSETS AND SUBSIDIARY STOCK. (a) In the event and to
the extent that the Net Available Cash received by the Company or any Restricted
Subsidiary from one or more Asset Dispositions occurring on or after the Issue
Date in any period of 12 consecutive months exceeds 15% of Adjusted Consolidated
Net Tangible Assets as of the beginning of such 12-month period, then the
Company shall (i) within 180 days (in the case of (A) below) or 18 months (in
the case of (B) below) after the date such Net Available Cash so received
exceeds such 15% of Adjusted Consolidated Net Tangible Assets (A) apply an
amount equal to such excess Net Available Cash to repay Senior Indebtedness of
the Company or a Subsidiary Guarantor or Indebtedness of a Restricted Subsidiary
that is not a Subsidiary Guarantor, in each case owing to a Person other than
the Company or any Affiliate of the Company or (B) invest an equal amount, or
the amount not so applied pursuant to clause (A), in Additional Assets or
Permitted Business Investments or (ii) apply such excess Net Available Cash (to
the extent not applied pursuant to clause (i)) as provided in the following
paragraphs of this covenant. The amount of such excess Net Available Cash
required to be applied during the applicable period and not applied as so
required by the end of such period shall constitute "Excess Proceeds."
(b) If, as of the first day of any calendar month, the aggregate amount of
Excess Proceeds not theretofore subject to an Excess Proceeds Offer (as defined
below) totals at least $10 million, the Company must, not later than the
fifteenth Business Day of such month, make an offer (an "Excess Proceeds Offer")
to purchase from the Holders on a pro rata basis an aggregate principal amount
of Notes equal to the Excess Proceeds (rounded down to the nearest multiple of
$1,000) on such date, at a purchase price equal to 100% of the principal amount
of such Notes, plus, in each case, accrued interest (if any) to the date of
purchase (the "Excess Proceeds Payment"), but, if the terms of any Indebtedness
ranking pari passu with the Notes require that an offer be made for such
Indebtedness contemporaneously with the Excess Proceeds Offer, then the Excess
Proceeds shall be prorated between the Excess Proceeds Offer and such pari passu
offer in accordance with the aggregate outstanding principal amounts of the
Notes and such pari passu Indebtedness, and the aggregate principal amount of
Notes for which the Excess Proceeds Offer is made shall be reduced accordingly.
The Company will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
thereunder in the event that such Excess Proceeds are received by the Company
under this covenant and the Company is required to repurchase Notes as described
above. To the extent that the provisions of any securities laws or regulations
conflict with the
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provisions of this covenant, the Company shall comply with the applicable
securities laws and regulations and shall not be deemed to have breached its
obligations under this covenant by virtue thereof.
(c) In the event of an Asset Disposition by the Company or any Restricted
Subsidiary that consists of a sale of hydrocarbons and results in Production
Payments, the Company or such Restricted Subsidiary shall apply an amount equal
to the Net Available Cash received by the Company or such Restricted Subsidiary
to (i) reduce Senior Indebtedness of the Company or a Subsidiary Guarantor or
Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor, in
each case owing to a Person other than the Company or any Affiliate of the
Company, within 180 days after the date such Net Available Cash is so received,
or (ii) invest in Additional Assets or Permitted Business Investments within 18
months after the date such Net Available Cash is so received.
LIMITATION ON AFFILIATE TRANSACTIONS. (a) The Company shall not, and shall
not permit any Restricted Subsidiary to, enter into or permit to exist any
transaction (including the purchase, sale, lease or exchange of any property,
employee compensation arrangements or the rendering of any service) with any
Affiliate of the Company (an "Affiliate Transaction") unless the terms thereof
(1) are no less favorable to the Company or such Restricted Subsidiary than
those that could be obtained at the time of such transaction in arm's-length
dealings with a Person who is not such an Affiliate, (2) if such Affiliate
Transaction involves an amount in excess of $10 million, is set forth in writing
and has been approved by the Board of Directors, including a majority of the
members of the Board of Directors having no personal stake in such Affiliate
Transaction, and (3) if such Affiliate Transaction involves an amount in excess
of $20 million, has been determined by a nationally recognized investment
banking firm or other qualified independent appraiser to be fair, from a
financial standpoint, to the Company and its Restricted Subsidiaries.
(b) The provisions of the foregoing paragraph (a) shall not prohibit (i)
any sale of hydrocarbons or other mineral products to an Affiliate of the
Company or the entering into or performance of Oil and Gas Hedging Contracts,
gas gathering, transportation or processing contracts or oil or natural gas
marketing or exchange contracts with an Affiliate of the Company, in each case,
in the ordinary course of business, so long as the terms of any such transaction
are approved by a majority of the members of the Board of Directors who are
disinterested with respect to such transaction, (ii) the sale to an Affiliate of
the Company of Capital Stock of the Company or DRI that does not constitute
Disqualified Stock, and the sale to an Affiliate of the Company of Indebtedness
(including Disqualified Stock) of the Company or DRI in connection with an
offering of such Indebtedness in a market transaction and on terms substantially
identical to those of other purchasers in such market transaction, (iii)
transactions contemplated by any employment agreement or other compensation plan
or arrangement existing on the Issue Date or thereafter entered into by DRI, the
Company or any of its Restricted Subsidiaries in the ordinary course of
business, (iv) the payment of reasonable fees to directors of DRI, the Company
and its Restricted Subsidiaries who are not employees of DRI, the Company or any
Restricted Subsidiary, (v) transactions between or among DRI, the Company and
its Restricted Subsidiaries, (vi) transactions between DRI, the Company or any
of its Restricted Subsidiaries and Persons that are controlled (as defined in
the definition of "Affiliate") by the Company (an "Unrestricted Affiliate);
provided that no other Person that controls (as so defined) or is under common
control with the Company holds any Investments in such Unrestricted Affiliate;
(vii) Restricted Payments that are permitted by the provisions of the Indenture
described above under the caption "-- Limitation on Restricted Payments", and
(viii) loans or advances to employees in the ordinary course of business and
approved by the Company's Board of Directors in an aggregate principal amount
not to exceed $2.5 million outstanding at any one time.
CHANGE OF CONTROL. (a) Upon the occurrence of a Change of Control, each
Holder shall have the right to require that the Company repurchase such Holder's
Notes at a purchase price in cash equal to 101% of the principal amount thereof
plus accrued and unpaid interest, if any, to the date of purchase (subject to
the right of Holders of record on the relevant record date to receive interest
on the relevant interest payment date), in accordance with the terms
contemplated in paragraph (b) below.
In the event that at the time of such Change of Control the terms of the
Indebtedness under the Credit Agreement restrict or prohibit the repurchase of
Notes pursuant to this covenant, then prior to the mailing of the notice to
Holders provided for in paragraph (b) below, but in any event within 30 days
following any
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Change of Control, the Company shall (i) repay in full the Indebtedness under
the Credit Agreement or (ii) obtain the requisite consent under the agreements
governing the Indebtedness under the Credit Agreement to permit the repurchase
of the Notes as provided for in paragraph (b) below.
(b) Within 30 days following a Change of Control, the Company shall mail a
notice to each Holder with a copy to the Trustee stating: (1) that a Change of
Control has occurred and that such Holder has the right to require the Company
to purchase such Holder's Notes at a purchase price in cash equal to 101% of the
principal amount thereof plus accrued and unpaid interest, if any, to the date
of purchase (subject to the right of Holders of record on the relevant record
date to receive interest on the relevant interest payment date); (2) the
circumstances and relevant facts regarding such Change of Control (including
information with respect to pro forma historical income, cash flow and
capitalization after giving effect to such Change of Control); (3) the
repurchase date (which shall be no earlier than 30 days nor later than 60 days
from the date such notice is mailed); and (4) the instructions determined by the
Company, consistent with this covenant, that a Holder must follow in order to
have its Notes purchased.
(c) The Company shall comply, to the extent applicable, with the
requirements of Section 14(e) of the Exchange Act and any other securities laws
or regulations in connection with the repurchase of Notes pursuant to this
covenant. To the extent that the provisions of any securities laws or
regulations conflict with the provisions of this covenant, the Company shall
comply with the applicable securities laws and regulations and shall not be
deemed to have breached its obligations under this covenant by virtue thereof.
The Change of Control purchase feature is a result of negotiations between
the Company and the Underwriters. Management has no present intention to engage
in a transaction involving a Change of Control, although it is possible that the
Company would decide to do so in the future. Subject to the limitations
discussed below, the Company could, in the future, enter into certain
transactions, including acquisitions, refinancing or other recapitalizations,
that would not constitute a Change of Control under the Indenture, but that
could increase the amount of indebtedness outstanding at such time or otherwise
affect the Company's capital structure or credit ratings. Restrictions on the
ability of the Company to incur additional Indebtedness are contained in the
covenants described under "-- Limitation on Indebtedness", "-- Limitation on
Liens" and "-- Limitation on Sale/Leaseback Transactions". Such restrictions can
only be waived with the consent of the holders of a majority in principal amount
of the Notes then outstanding. Except for the limitations contained in such
covenants, however, the Indenture will not contain any covenants or provisions
that may afford holders of the Notes protection in the event of a highly
leveraged transaction.
The Credit Agreement prohibits the Company from purchasing any Notes and
also provides that the occurrence of certain change of control events with
respect to the Company would constitute a default thereunder. In the event a
Change of Control occurs at a time when the Company is prohibited from
purchasing Notes, the Company could seek the consent of its lenders to the
purchase of Notes or could attempt to refinance the borrowings that contain such
prohibition. If the Company does not obtain such a consent or repay such
borrowings, the Company will remain prohibited from purchasing Notes. In such
case, the Company's failure to purchase tendered Notes would constitute an Event
of Default under the Indenture which would, in turn, constitute a default under
the Credit Agreement. In such circumstances, the subordination provisions in the
Indenture would likely restrict payment to the Holders of Notes.
Future indebtedness of the Company may contain prohibitions on the
occurrence of certain events that would constitute a Change of Control or
require such indebtedness to be repurchased upon a Change of Control. Moreover,
the exercise by the Holders of their right to require the Company to repurchase
the Notes could cause a default under such indebtedness, even if the Change of
Control itself does not, due to the financial effect of such repurchase on the
Company. Finally, the Company's ability to pay cash to the holders of Notes
following the occurrence of a Change of Control may be limited by the Company's
then existing financial resources. There can be no assurance that sufficient
funds will be available when necessary to make any required repurchases.
The provisions under the Indenture relating to the Company's obligation to
make an offer to repurchase the Notes as a result of a Change of Control may be
waived or modified with the written consent of the holders of a majority in
principal amount of the Notes.
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The Company will not be required to make an offer to purchase the Notes as
a result of a Change of Control if a third party (i) makes such offer in the
manner, at the times and otherwise in compliance with the requirements set forth
in the Indenture relating to the Company's obligations to make such an offer and
(ii) purchases all Notes validly tendered and not withdrawn under such an offer.
LIMITATION ON THE SALE OR ISSUANCE OF CAPITAL STOCK OF RESTRICTED
SUBSIDIARIES. The Company shall not sell or otherwise dispose of any shares of
Capital Stock of a Restricted Subsidiary, and shall not permit any Restricted
Subsidiary, directly or indirectly, to issue or sell or otherwise dispose of any
shares of its Capital Stock except (i) to the Company or a Wholly Owned
Subsidiary, (ii) if, immediately after giving effect to such issuance, sale or
other disposition, neither the Company nor any of its Subsidiaries own any
Capital Stock of such Restricted Subsidiary, (iii) if, immediately after giving
effect to such issuance, sale or other disposition, such Restricted Subsidiary
would no longer constitute a Restricted Subsidiary and any Investment in such
Person remaining after giving effect thereto would have been permitted to be
made under the covenant described under "-- Limitation on Restricted Payments"
if made on the date of such issuance, sale or other disposition, or (iv) to the
extent such shares represent directors' qualifying shares or shares required by
applicable law to be held by a Person other than the Company or Restricted
Subsidiary.
LIMITATION ON LIENS. The Company shall not, and shall not permit any
Restricted Subsidiary to, directly or indirectly, enter into, create, incur,
assume or suffer to exist any Lien on or with respect to any property of the
Company or such Restricted Subsidiary, whether owned on the Issue Date or
acquired after the Issue Date, or any interest therein or any income or profits
therefrom, unless the Notes or any Subsidiary Guaranty of such Restricted
Subsidiary, as applicable, are secured equally and ratably with (or prior to)
any and all other obligations secured by such Lien, except that the Company and
its Restricted Subsidiaries may enter into, create, incur, assume or suffer to
exist Permitted Liens and Liens securing Senior Indebtedness.
MERGER AND CONSOLIDATION. The Company shall not consolidate with or merge
with or into, or convey, transfer or lease , in one transaction or a series of
transactions, all or substantially all the assets of the Company and its
Restricted Subsidiaries, taken as a whole, to, any Person, unless: (i) (A) the
resulting, surviving or transferee Person (the "Successor Company") shall be a
Person organized and existing under the laws of the United States of America,
any State thereof or the District of Columbia and (B) the Successor Company (if
not the Company) shall expressly assume, by an indenture supplemental thereto,
executed and delivered to the Trustee, in form satisfactory to the Trustee, all
the obligations of the Company under the Notes and the Indenture; (ii)
immediately after giving effect to such transaction (and treating any
Indebtedness which becomes an obligation of the Successor Company or any
Subsidiary as a result of such transaction as having been Incurred by such
Successor Company or such Subsidiary at the time of such transaction), no
Default shall have occurred and be continuing, (iii) immediately after giving
effect to such transaction, the Successor Company would be able to Incur an
additional $1.00 of Indebtedness pursuant to paragraph (a); (iv) immediately
after giving effect to such transaction, the Successor Company shall have
Adjusted Consolidated Net Tangible Assets that are not less than the Adjusted
Consolidated Net Tangible Assets prior to such transaction; (v) in the case of a
conveyance, transfer or lease of all or substantially all the assets of the
Company and its Restricted Subsidiaries, taken as a whole, such assets shall
have been so conveyed, transferred or leased as an entirety or virtually as an
entirety to one Person; and (vi) the Company shall have complied with certain
additional conditions set forth in the Indenture; provided, however, that
clauses (iii) and (iv) shall not be applicable to any such transaction solely
between DRI, the Company and any Restricted Subsidiary; provided further,
however, that clause (i)(A) shall not be applicable to any merger of the Company
with and into DRI in connection with a transaction in which DRI, substantially
concurrently with such merger, becomes (or is merged with and into) a Person
organized and existing under the laws of the United States of America, any State
thereof or the District of Columbia.
The Successor Company shall be the successor to the Company and shall
succeed to, and be substituted for, and may exercise every right and power of,
the Company under the Indenture, but the predecessor Company in the case of a
lease shall not be released from the obligation to pay the principal of and
interest on the Notes.
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The Company will not permit any Subsidiary Guarantor to consolidate with or
merge with or into, or convey, transfer or lease, in one transaction or a series
of transactions, all or substantially all of its assets to any Person unless:
(i) the resulting, surviving or transferee Person (if not such Subsidiary) shall
be a Person organized and existing under the laws of the jurisdiction under
which such Subsidiary was organized or under the laws of the United States of
America, or any State thereof or the District of Columbia, and such Person shall
expressly assume, by executing a Guaranty Agreement, all the obligations of such
Subsidiary, if any, under its Subsidiary Guaranty; (ii) immediately after giving
effect to such transaction or transactions on a pro forma basis (and treating
any Indebtedness which becomes an obligation of the resulting, surviving or
transferee Person as a result of such transaction as having been issued by such
Person at the time of such transaction), no Default shall have occurred and be
continuing; (iii) in the case of a conveyance, transfer or lease of all or
substantially all the assets of a Subsidiary Guarantor, such assets shall have
been so conveyed, transferred or leased as an entirety or virtually as an
entirety to one Person; and (iv) the Company shall have complied with certain
additional conditions contained in the Indenture. The provisions of clauses (i)
and (ii) above shall not apply to any one or more transactions which constitute
an Asset Disposition if the Company has complied with the applicable provisions
of the covenant described under "-- Limitation on Sales of Assets and Subsidiary
Stock" above.
Pursuant to the Indenture, DRI will covenant not to merge with or into, or
convey, transfer or lease, in one transaction or a series of transactions, all
or substantially all of its assets to any Person unless; (i) the resulting,
surviving or transferee Person (if not DRI) shall be a Person organized and
existing under the laws of Canada or any province thereof or under the laws of
the United States of America, or any State thereof or the District of Columbia,
and such Person shall expressly assume, by executing a Guaranty Agreement, all
the obligations of DRI, if any, under the DRI Guaranty, (ii) immediately after
giving effect to such transaction or transactions on a pro forma basis (and
treating any Indebtedness which becomes an obligation of the resulting,
surviving or transferee Person as a result of such transaction as having been
issued by such Person at the time of such transaction), no Default shall have
occurred and be continuing; (iii) in the case of a conveyance, transfer or lease
of all or substantially all the assets of DRI, such assets shall have been so
conveyed, transferred or leased as an entirety or virtually as an entirety to
one Person; and (iv) the Company shall have complied with certain additional
conditions contained in the Indenture.
SEC REPORTS. Notwithstanding that the Company may not at any time be
subject to the reporting requirements of Section 13 or 15(d) of the Exchange
Act, the Company shall file with the SEC and provide the Trustee and Noteholders
with such annual reports and such information, documents and other reports as
are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a
U.S. corporation subject to such Sections, such information, documents and other
reports to be so filed and provided at the times specified for the filing of
such information, documents and reports under such Sections; provided, however,
that so long as DRI is a Guarantor of the Notes, the reports, information and
other documents required to be filed and provided as described hereunder may, at
the Company's option, be filed by and be those of DRI rather than the Company;
provided further, however, that in the event DRI conducts any business or holds
any significant assets other than the capital stock of the Company at the time
of filing and providing any such report, information or other document
containing financial statements of DRI, DRI shall include in such report,
information or other document summarized financial information (as defined in
Rule 1-02(bb) of Regulation S-X promulgated by the SEC) with respect to the
Company.
FUTURE SUBSIDIARY GUARANTORS. The Company shall cause each Restricted
Subsidiary that represents at least 10% of the book assets of, or 10% of the
ACNTA of, the Company and its Restricted Subsidiaries, taken as a whole, and
that has an aggregate of $15.0 million or more of Indebtedness and Preferred
Stock outstanding at any time to promptly Guarantee the Notes pursuant to a
Subsidiary Guaranty on the terms and conditions set forth in the Indenture.
DEFAULTS
An Event of Default is defined in the Indenture as (i) a default in the
payment of interest on the Notes when due, continued for 30 days, (ii) a default
in the payment of principal of any Note when due at its Stated Maturity, upon
optional redemption, upon required repurchase, upon declaration or otherwise,
(iii) the failure
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by the Company to comply with its obligations under "-- Certain
Covenants -- Merger and Consolidation" above, (iv) the failure by the Company to
comply for 30 days after notice with any of its obligations in the covenants
described above under "-- Certain Covenants," "-- Limitation on Indebtedness,"
"-- Limitation on Restricted Payments," "-- Limitation on Restrictions on
Distributions from Restricted Subsidiaries," "-- Limitation on Sales of Assets
and Subsidiary Stock" (other than a failure to purchase Notes), "-- Limitation
on Affiliate Transactions," "-- Limitation on the Sale or Issuance of Capital
Stock of Restricted Subsidiaries," "-- Change of Control" (other than a failure
to purchase Notes), "-- Limitation on Liens" or "Future Subsidiary Guarantors,"
(v) the failure by the Company to comply for 60 days after notice with its other
agreements contained in the Indenture, (vi) Indebtedness of the Company or the
Guarantor (other than Limited Recourse Production Payments and Non-recourse
Purchase Money Indebtedness) is not paid within any applicable grace period
after final maturity or the maturity of such Indebtedness is accelerated by the
holders thereof because of a default (and such acceleration is not rescinded or
annulled) and the total amount of such Indebtedness unpaid or accelerated
exceeds $10 million (the "cross acceleration provision"), (vii) certain events
of bankruptcy, insolvency or reorganization of the Company or a Significant
Subsidiary (the "bankruptcy provisions"), (viii) any judgment or decree for the
payment of money in an uninsured or unindemnified amount in excess of $10
million or its foreign currency equivalent at the time is rendered against the
Company or a Significant Subsidiary, remains outstanding for a period of 60 days
following such judgment and is not discharged, waived, bonded or stayed within
10 days after notice (the "judgment default provision") or (ix) any Guaranty
ceases to be in full force and effect (other than in accordance with the terms
thereof) or a Guarantor denies or disaffirms its obligations under its Guaranty
if such default continues for a period of ten days after notice thereof to the
Company (the "guaranty default provision"). However, a default under clauses
(iv), (v), (viii) and (ix) will not constitute an Event of Default until the
Trustee or the holders of 25% in principal amount of the outstanding Notes
notify the Company of the default and the Company does not cure such default
within the time specified after receipt of such notice.
If an Event of Default occurs and is continuing, the Trustee or the holders
of at least 25% in principal amount of the outstanding Notes may declare the
principal of and accrued but unpaid interest on all the Notes to be due and
payable. Upon such a declaration, such principal and interest shall be due and
payable immediately. If an Event of Default relating to certain events of
bankruptcy, insolvency or reorganization of the Company occurs and is
continuing, the principal of and interest on all the Notes will ipso facto
become and be immediately due and payable without any declaration or other act
on the part of the Trustee or any holders of the Notes. Under certain
circumstances, the holders of a majority in principal amount of the outstanding
Notes may rescind any such acceleration with respect to the Notes and its
consequences.
Subject to the provisions of the Indenture relating to the duties of the
Trustee, in case an Event of Default occurs and is continuing, the Trustee will
be under no obligation to exercise any of the rights or powers under the
Indenture at the request or direction of any of the holders of the Notes unless
such holders have offered to the Trustee reasonable indemnity or security
against any loss, liability or expense. Except to enforce the right to receive
payment of principal, premium (if any) or interest when due, no holder of a Note
may pursue any remedy with respect to the Indenture or the Notes unless (i) such
holder has previously given the Trustee notice that an Event of Default is
continuing, (ii) holders of at least 25% in principal amount of the outstanding
Notes have requested the Trustee to pursue the remedy, (iii) such holders have
offered the Trustee reasonable security or indemnity against any loss, liability
or expense, (iv) the Trustee has not complied with such request within 60 days
after the receipt thereof and the offer of security or indemnity and (v) the
holders of a majority in principal amount of the outstanding Notes have not
given the Trustee a direction inconsistent with such request within such 60-day
period. Subject to certain restrictions, the holders of a majority in principal
amount of the outstanding Notes are given the right to direct the time, method
and place of conducting any proceeding for any remedy available to the Trustee
or of exercising any trust or power conferred on the Trustee. The Trustee,
however, may refuse to follow any direction that conflicts with law or the
Indenture or that the Trustee determines is unduly prejudicial to the rights of
any other holder of a Note or that would involve the Trustee in personal
liability.
The Indenture provides that if a Default occurs and is continuing and is
known to the Trustee, the Trustee must mail to each holder of the Notes notice
of the Default within 90 days after it occurs. Except in
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the case of a Default in the payment of principal of or interest on any Note,
the Trustee may withhold notice if and so long as a committee of its trust
officers determines that withholding notice is not opposed to the interest of
the holders of the Notes. In addition, the Company is required to deliver to the
Trustee, within 120 days after the end of each fiscal year, a certificate
indicating whether the signers thereof know of any Default that occurred during
the previous year. The Company also is required to deliver to the Trustee,
within 30 days after the occurrence thereof, written notice of any event which
would constitute certain Defaults, their status and what action the Company is
taking or proposes to take in respect thereof.
AMENDMENTS AND WAIVERS
Subject to certain exceptions, the Indenture may be amended with the
consent of the holders of a majority in principal amount of the Notes then
outstanding (including consents obtained in connection with a tender offer or
exchange for the Notes) and any past default or compliance with any provisions
may also be waived with the consent of the holders of a majority in principal
amount of the Notes then outstanding. However, without the consent of each
holder of an outstanding Note affected thereby, no amendment may, among other
things, (i) reduce the amount of Notes whose holders must consent to an
amendment, (ii) reduce the rate of or extend the time for payment of interest on
any Note, (iii) reduce the principal of or extend the Stated Maturity of any
Note, (iv) reduce the premium payable upon the redemption of any Note or change
the time at which any Note may be redeemed as described under "-- Optional
Redemption", (v) make any Note payable in money other than that stated in the
Note, (vi) impair the right of any holder of the Notes to receive payment of
principal of and interest on such holder's Notes on or after the due dates
therefor or to institute suit for the enforcement of any payment on or with
respect to such holder's Notes, (vii) make any change in the amendment
provisions which require each holder's consent or in the waiver provisions,
(viii) make any change to the subordination provisions of the Indenture that
would adversely affect the Noteholders or (ix) make any change in any Guaranty
that could adversely affect such holder.
Without the consent of any holder of the Notes, the Company, the Guarantors
and the Trustee may amend the Indenture to cure any ambiguity, omission, defect
or inconsistency, to provide for the assumption by a successor corporation of
the obligations of the Company or the Guarantors under the Indenture, to provide
for uncertificated Notes in addition to or in place of certificated Notes
(provided that the uncertificated Notes are issued in registered form for
purposes of Section 163(f) of the Code, or in a manner such that the
uncertificated Notes are described in Section 163(f)(2)(B) of the Code), to make
any change in the subordination provisions of the Indenture that would limit or
terminate the benefits available to any holder of Senior Indebtedness of the
Company or any Guarantor thereunder, to add guarantees with respect to the Notes
(including any Subsidiary Guaranty), to secure the Notes, to add to the
covenants of the Company for the benefit of the holders of the Notes or to
surrender any right or power conferred upon the Company or any Guarantor, to
make any change that does not adversely affect the rights of any holder of the
Notes or to comply with any requirement of the SEC in connection with the
qualification of the Indenture under the Trust Indenture Act. However, no
amendment may be made to the subordination provisions of the Indenture that
adversely affects the rights of any holder of Senior Indebtedness of the Company
or the Guarantor then outstanding unless the holders of such Senior Indebtedness
(or their Representative) consents to such change.
The consent of the holders of the Notes is not necessary under the
Indenture to approve the particular form of any proposed amendment. It is
sufficient if such consent approves the substance of the proposed amendment.
After an amendment under the Indenture becomes effective, the Company is
required to mail to holders of the Notes a notice briefly describing such
amendment. However, the failure to give such notice to all holders of the Notes,
or any defect therein, will not impair or affect the validity of the amendment.
TRANSFER
The Notes will be issued in registered form and will be transferable only
upon the surrender of the Notes being transferred for registration of transfer.
The Company may require payment of a sum sufficient to cover any tax, assessment
or other governmental charge payable in connection with certain transfers and
exchanges.
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DEFEASANCE
The Company at any time may terminate all its obligations under the Notes
and the Indenture ("legal defeasance"), except for certain obligations,
including those respecting the defeasance trust and obligations to register the
transfer or exchange of the Notes, to replace mutilated, destroyed, lost or
stolen Notes and to maintain a registrar and paying agent in respect of the
Notes. The Company at any time may terminate its obligations under the covenants
described under "-- Certain Covenants" (other than the covenant described under
"-- Merger and Consolidation"), the operation of the cross acceleration
provision, the bankruptcy provisions with respect to Significant Subsidiaries,
the judgment default provision and the guaranty default provision described
under "-- Defaults" above and the limitations contained in clauses (iii) and
(iv) under the first paragraph of, and in the third and fourth paragraphs of,
"-- Certain Covenants -- Merger and Consolidation" above ("covenant
defeasance").
The Company may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If the Company exercises its
legal defeasance option, payment of the Notes may not be accelerated because of
an Event of Default with respect thereto. If the Company exercises its covenant
defeasance option, payment of the Notes may not be accelerated because of an
Event of Default specified in clause (iv), (vi), (vii) (with respect only to
Significant Subsidiaries) or (viii) under "-- Defaults" above or because of the
failure of the Company to comply with clause (iii) or (iv) under the first of
paragraph of, or with the third and fourth paragraphs of, "-- Certain
Covenants -- Merger and Consolidation" above. If the Company exercises its legal
defeasance option or its covenant defeasance option, each Guarantor will be
released from all its obligations with respect to its Guaranty.
In order to exercise either defeasance option, the Company must irrevocably
deposit in trust (the "defeasance trust") with the Trustee money or U.S.
Government Obligations for the payment of principal and interest on the Notes to
redemption or maturity, as the case may be, and must comply with certain other
conditions, including delivery to the Trustee of an Opinion of Counsel to the
effect that holders of the Notes will not recognize income, gain or loss for
Federal income tax purposes as a result of such deposit and defeasance and will
be subject to Federal income tax on the same amount and in the same manner and
at the same times as would have been the case if such deposit and defeasance had
not occurred (and, in the case of legal defeasance only, such Opinion of Counsel
must be based on a ruling of the Internal Revenue Service or other change in
applicable Federal income tax law).
CONCERNING THE TRUSTEE
Chase Bank of Texas, National Association is to be the Trustee under the
Indenture and has been appointed by the Company as Registrar and Paying Agent
with regard to the Notes.
The Holders of a majority in principal amount of the outstanding Notes will
have the right to direct the time, method and place of conducting any proceeding
for exercising any remedy available to the Trustee, subject to certain
exceptions. The Indenture provides that if an Event of Default occurs (and is
not cured), the Trustee will be required, in the exercise of its power, to use
the degree of care of a prudent man in the conduct of his own affairs. Subject
to such provisions, the Trustee will be under no obligation to exercise any of
its rights or powers under the Indenture at the request of any Holder of Notes,
unless such Holder shall have offered to the Trustee security and indemnity
satisfactory to it against any loss, liability or expense and then only to the
extent required by the terms of the Indenture.
GOVERNING LAW
The Indenture provides that it (including the Guaranties) and the Notes
will be governed by, and construed in accordance with, the laws of the State of
New York without giving effect to applicable principles of conflicts of law to
the extent that the application of the law of another jurisdiction would be
required thereby.
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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
The following is a general discussion of the principal United States
Federal income tax consequences of the purchase, ownership and disposition of
the Notes to initial purchasers thereof who are United States Holders (as
defined below) and the principal United States Federal income and estate tax
consequences of the purchase, ownership and disposition of the Notes to initial
purchasers who are Foreign Holders (as described below). This discussion is
based on currently existing provisions of the Code, existing, temporary and
proposed Treasury regulations promulgated thereunder, and administrative and
judicial interpretations thereof, all as in effect or proposed on the date
hereof and all of which are subject to change, possible with retroactive effect,
or different interpretations. This discussion does not address the tax
consequences to subsequent purchasers of Notes and is limited to purchasers who
hold the Notes as capital assets, within the meaning of section 1221 of the
Code. This discussion also does not address the tax consequences to Foreign
Holders that are subject to United States Federal income tax on a net basis on
income realized with respect to a Note because such income is effectively
connected with the conduct of a United States trade or business. Such Foreign
holders are generally taxed in a similar manner to United States Holders, but
certain special rules do apply. Moreover, this discussion is for general
information only and does not address all of the tax consequences that may be
relevant to particular initial purchasers in light of their personal
circumstances or to certain types of initial purchasers (such as certain
financial institutions, insurance companies, tax-exempt entities, dealers in
securities or persons who have hedged the risk of owning a Note).
PROSPECTIVE PURCHASERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO
THE PARTICULAR TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND
DISPOSITION OF THE NOTES, INCLUDING THE APPLICABILITY OF ANY UNITED STATES
FEDERAL TAX LAWS OR ANY STATE, LOCAL OR FOREIGN TAX LAWS, AND ANY CHANGES (OR
PROPOSED CHANGES) IN APPLICABLE TAX LAWS OR INTERPRETATIONS THEREOF.
UNITED STATES FEDERAL INCOME TAXATION OF UNITED STATES HOLDERS
As used herein, the term "United States Holder" means a holder of a Note
that is, for United States federal income tax purposes, (a) a citizen or
resident of the United States, (b) a corporation, partnership or other entity
created or organized in or under the laws of the United States or any political
subdivision thereof, (c) an estate or trust described in Section 7701(a)(30) of
the Code, or (d) a person whose worldwide income or gain is subject to U.S.
Federal income taxation on a net income basis.
PAYMENT OF INTEREST ON NOTES. Interest paid or payable on a Note will be
taxable to a United States Holder as ordinary interest income, generally at the
time it is received or accrued, in accordance with such holder's regular method
of accounting for United States Federal income tax purposes.
SALE, EXCHANGE OR RETIREMENT OF NOTES. Upon the sale, redemption,
retirement at maturity or other disposition of a Note, a United States Holder
generally will recognize taxable gain or loss equal to the difference between
the sum of cash plus the fair market value of all other property received on
such disposition (except to the extent such cash or property is attributable to
accrued but unpaid interest, which will be taxable as ordinary income) and such
United States Holder's adjusted tax basis in the Note. A United States Holder's
adjusted tax basis in a Note generally will equal the cost of the Note to such
United States Holder, less any principal payments received by such United States
Holder.
Gain or loss recognized on the disposition of a Note generally will be
capital gain or loss and will be long-term capital gain or loss if, at the time
of such disposition, the United States Holder's holding period for the Note is
more than one year. Under the Taxpayer Relief Act of 1997, lower tax rates apply
to the sale or exchange of capital assets by individuals who have held such
assets for more than 18 months.
BACKUP WITHHOLDING AND INFORMATION REPORTING. Backup withholding and
information reporting requirements may apply to certain payments of principal,
premium, if any, and interest on a Note, and to proceeds of the sale or
redemption of a Note before maturity. The Company, its agent, a broker, the
Trustee or any paying agent, as the case may be, will be required to withhold
from any payment that is subject to backup withholding
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a tax equal to 31% of such payment if the United States Holder fails to (i)
furnish his, her or its taxpayer identification number (social security or
employer identification number), (ii) certify that such number is correct, (iii)
certify that such holder is not subject to backup withholding or (iv) otherwise
comply with the applicable requirements of the backup withholding rules. Certain
United States Holders, including all corporations, are not subject to backup
withholding and information reporting requirements. Any amounts withheld under
the backup withholding rules from a payment to a United States Holder will be
allowed as a credit against such United States Holder's United States Federal
income tax liability and may entitle the holder to a refund, provided that the
required information is furnished to the Internal Revenue Service ("IRS").
UNITED STATES FEDERAL INCOME TAXATION OF FOREIGN HOLDERS
As used herein, the term "Foreign Holder" means a holder of a Note that is,
for United States Federal income tax purposes, (a) a nonresident alien
individual, (b) a foreign corporation, (c) a nonresident alien fiduciary of a
foreign estate or trust or (d) a foreign partnership.
PAYMENT OF INTEREST ON NOTES. In general, payments of interest received by
a Foreign Holder will not be subject to a United States Federal withholding tax,
provided that (i) (a) the Foreign Holder does not actually or constructively own
10% or more of the total combined voting power of all classes of stock of DMI
entitled to vote within the meaning of section 871(h)(g) of the Code, (b) the
Foreign Holder is not a controlled foreign corporation that is related to DMI
actually or constructively through stock ownership, (c) such interest payments
are not effectively connected with the conduct by the Foreign Holder of a trade
or business within the United States, and (d) either (I) the beneficial owner of
the Note, under penalties of perjury, provides DMI or its agent with such
beneficial owner's name and address and certifies on IRS Form W-8 (or a suitable
substitute form) that it is not a United States Holder or (II) a securities
clearing organization, bank or other financial institution that holds customers'
securities in the ordinary course of its trade or business (a "financial
institution") holds the Notes and provides a statement to DMI or its agent under
penalties of perjury in which it certifies that an IRS Form W-8 (or a suitable
substitute) has been received by it from the beneficial owner of the Notes or
qualifying intermediary and furnishes DMI or its agent a copy thereof; and (ii)
the Foreign Holder is entitled to the benefits of an income tax treaty under
which interest on the Notes is exempt from United States Federal withholding tax
and the Foreign Holder or such Foreign Holder's agent provides a properly
executed IRS Form 1001 claiming the exemption. Payments of interest not exempt
from United States Federal withholding tax as described above will be subject to
such withholding tax at the rate of 30% (subject to reduction under an
applicable income tax treaty).
SALE, EXCHANGE OR RETIREMENT OF THE NOTES. A Foreign Holder generally will
not be subject to United States Federal income tax (and generally no tax will be
withheld) with respect to gain realized on the sale, exchange, redemption,
retirement at maturity or other disposition of a Note unless the Foreign Holder
is an individual who is present in the United States for a period or periods
aggregating 183 or more days in the taxable year of the disposition and,
generally, either has a "tax home" or an "office or other fixed place of
business" in the United States or such gains are effectively connected with the
conduct by the Foreign Holder of a trade or business within the United States.
BACKUP WITHHOLDING AND INFORMATION REPORTING. Backup withholding and
information reporting requirements do not apply to payments of interest made by
DMI or a paying agent to Foreign Holders if the certification described above
under "-- United States Federal Income Taxation of Foreign Holders -- Payment of
Interest on Notes" is received, provided that the payor does not have actual
knowledge that the holder is a United States Holder. If any payments of
principal and interest are made to the beneficial owner of a Note by or through
the foreign office of a foreign custodian, foreign nominee or the foreign agent
of such beneficial owner, or if the foreign office of a foreign "broker" (as
defined in applicable Treasury regulations) pays the proceeds of the sale of a
Note to the seller thereof, backup withholding information reporting will not
apply. Information reporting requirements (but not backup withholding) will
apply, however, to a payment by a foreign office of a broker that is a United
States person, that derives 50% or more of its gross income for certain periods
from the conduct of a trade or business in the United States, or that is a
"controlled foreign corporation" (generally, a foreign corporation controlled by
certain United States shareholders) with respect
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to the United States unless the broker has documentary evidence in its records
that the holder is a Foreign Holder and certain other conditions are met or the
holder otherwise establishes an exemption. Payment by a United States office of
a broker is subject to both backup withholding at a rate of 31% and information
reporting unless the holder certifies under penalties of perjury that it is a
Foreign Holder or otherwise establishes an exemption.
1997 FINAL REGULATIONS. The procedures described above for withholding tax
on interest payments, and some of the associated backup withholding and
information reporting rules, are the subject of regulations issued in final form
October 7, 1997. The final regulations are effective for payments made after
December 31, 1998, subject to certain transition rules (the "1997 Final
Regulations"). The 1997 Final Regulations will provide alternative methods for
satisfying the statement requirement described in clause (i)(d) of "United
States Federal Income Taxation of Foreign Holders -- Payment of Interest on
Notes" above. The 1997 Final Regulations also will require, in the case of a
Note held by a foreign partnership, that the certification described in clause
(i)(d) above be provided by the partners and the partnership provide certain
information, including its taxpayer identification number. A look-through rule
will apply in the case of tiered partnerships. Prospective investors should
consult their tax advisors regarding the certification requirements for
non-United States Holders.
FEDERAL ESTATE TAX
Subject to applicable estate tax treaty provisions, Notes held at the time
of death (or Notes transferred before death but subject to certain retained
rights or powers) by an individual who at the time of death is a Foreign Holder
will not be included in such Foreign Holder's gross estate for United States
Federal estate tax purposes provided that the individual does not actually or
constructively own 10% or more of the total combined voting power of all classes
of stock of DMI entitled to vote or hold the Notes in connection with a United
States trade or business.
SERVICE AND ENFORCEMENT OF LEGAL PROCESS
DRI is incorporated under the laws of Canada. Some of the directors,
controlling persons and officers of DRI, as well as the experts named herein,
are residents of Canada and all or substantially all of such persons' assets are
located outside of the United States. As a result, it may be difficult for
Noteholders to effect service within the United States upon the directors,
controlling persons, officers and experts who are not residents of the United
States or to realize in the United States upon judgments of courts of the United
States against such persons and DRI predicated upon civil liability under the
United States federal securities laws. DRI has been advised by its counsel,
Burnet, Duckworth & Palmer, Calgary, Alberta, that there is doubt as to the
enforceability in Canada against DRI or against any of its directors,
controlling persons, officers or experts who are not residents of the United
States, in original actions for enforcement of judgments of United States
courts, of liabilities predicated solely upon United States federal securities
laws.
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UNDERWRITERS
Under the terms and subject to the conditions contained in an underwriting
agreement (the "Underwriting Agreement"), the Underwriters named below have
severally agreed to purchase, and DMI has agreed to sell them, the principal
amount of Notes set forth opposite their respective names below:
<TABLE>
<CAPTION>
PRINCIPAL
AMOUNT
UNDERWRITERS OF NOTES
------------ ------------
<S> <C>
Morgan Stanley & Co. Incorporated........................... $ 87,500,000
NationsBanc Montgomery Securities LLC....................... 37,500,000
------------
Total............................................. $125,000,000
============
</TABLE>
The Underwriting Agreement provides that the obligations of the
Underwriters to pay for and accept delivery of the Notes offered hereby are
subject to the approval of certain legal matters by their counsel and to certain
other conditions. If the Notes are purchased by the Underwriters pursuant to the
Underwriting Agreement, all such Notes must be so purchased.
The Underwriters initially propose to offer the Notes directly to the
public at the public offering price set forth on the cover page of this
Prospectus and to certain dealers at a price that represents a concession not in
excess of .250% of the principal amount of the Notes. Each Underwriter may
allow, and such dealers may reallow, a concession to certain other dealers not
in excess of .125% of the principal amount of the Notes. After the initial
offering of the Notes the offering price and other selling terms may from time
to time be varied by the Underwriters.
DMI and the Guarantor have agreed to indemnify the Underwriters against
certain liabilities that may be incurred in connection with the offering of the
Notes, including liabilities under the Securities Act, or to contribute to
payments that the Underwriters may be required to make in respect thereof.
It is expected that delivery of the Notes will be made against payment
therefor on or about the date specified in the last paragraph of the cover page
of this Prospectus, which is the fourth business day following the date hereof.
Under Rule 15c6-1 of the U.S. Securities and Exchange Commission under the
Exchange Act, trades in the secondary market generally are required to settle in
three business days, unless the parties to any such trade expressly agree
otherwise. Accordingly, purchasers who wish to trade Notes on the date hereof
will be required, by virtue of the fact that the Notes initially will settle in
T+4, to specify an alternate settlement cycle at the time of any such trade to
prevent a failed settlement. Purchasers of Notes who wish to trade Notes on the
date hereof should consult their own advisor.
In order to facilitate the Debt Offering, the Underwriters may engage in
transactions that stabilize, maintain or otherwise affect the price of the
Notes. Specifically, the Underwriters may over-allot in connection with the Debt
Offering, creating a short position in the Notes for their own account. In
addition, to cover over-allotments or to stabilize the price of the Notes, the
Underwriters may bid for, and purchase, Notes in the open market. Finally, the
underwriting syndicate may reclaim selling concessions allowed to an underwriter
or a dealer for distributing the Notes in the Debt Offering, if the syndicate
repurchases previously distributed Notes in transactions to cover syndicate
short positions, in stabilization transactions or otherwise. Any of these
activities may stabilize or maintain the market price of the Notes above
independent market levels. The Underwriters are not required to engage in these
activities, and may end any of these activities at any time.
The rules of the National Association of Securities Dealers, Inc. (the
"NASD") provide that no NASD member shall participate in a public offering of an
issuer's securities where more than 10% of the net offering proceeds are
intended to be paid to members participating in the distribution of the offering
or affiliated persons of such members, unless a "qualified independent
underwriter" shall have been engaged on the terms provided in such rules. It is
anticipated that NationsBank of Texas, N.A., an affiliate of NationsBanc
Montgomery Securities LLC and a lender under the Credit Facility, will be
receiving more than 10% of the proceeds from the Offerings in its capacity as a
lender under the Credit Facility. See "Use of Proceeds."
96
<PAGE> 97
In view of such potential use of proceeds, the Debt Offering is being
conducted in accordance with the applicable provisions of Rule 2720 of the
NASD's Conduct Rules ("Rule 2720"). Rule 2720 requires that the yield at which
the Debt Offering will be distributed to the public will be established at a
yield no lower than that recommended by a "qualified independent underwriter".
Accordingly, Morgan Stanley & Co. Incorporated is assuming the responsibilities
of acting as qualified independent underwriter in pricing the Debt Offering,
preparing the Registration Statement of which this Prospectus forms a part and
conducting "due diligence" with respect thereto.
LEGAL MATTERS
The legality of the Notes offered hereby will be passed upon for DMI by
Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain legal
matters in connection with the Offerings will be passed upon for the Company by
Burnet, Duckworth & Palmer, Calgary, Alberta and for the Underwriters by Osler,
Hoskin & Harcourt, Calgary, Alberta and Cravath, Swaine & Moore, New York, New
York.
EXPERTS
The consolidated financial statements and financial statement schedule of
the Company as at December 31, 1995 and 1996 and for each of the three years in
the period ended December 31, 1996 included and incorporated by reference in
this Prospectus and elsewhere in the Registration Statement, have been audited
by Deloitte & Touche, Chartered Accountants, Calgary, Alberta, Canada, as stated
in their reports appearing and incorporated by reference in this Prospectus and
elsewhere in the Registration Statement, and have been so included in reliance
upon the reports of such firm given upon their authority as experts in
accounting and auditing.
The statements of revenues and direct operating expenses of Chevron's
working interest in the Heidelberg Fields acquired by the Company for each of
the two years in the period December 31, 1996 and for the nine months ended
September 30, 1997 included in this Prospectus has been so included in reliance
on the report of Price Waterhouse LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting.
The reference to the reports of Netherland, Sewell & Associates, Inc.,
independent petroleum engineers located in Dallas, Texas, contained herein with
respect to the proved reserves, the estimated future net revenue from such
proved reserves, and the discounted present values of such estimated future net
revenue, is made in reliance upon the authority of such firms as experts with
the respect to such matters.
97
<PAGE> 98
AVAILABLE INFORMATION
The Company is subject to the information requirements of the Exchange Act,
and in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information can be inspected and copied at the public reference facilities
maintained by the Commission at 450 5th Street, N.W., Room 1024, Washington,
D.C. 20549, and at the following regional offices of the Commission: Seven World
Trade Center, 13th Floor, New York, New York 10048 and Citicorp Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661, at prescribed rates. In
addition, such materials filed electronically by the Company with the Commission
are available at the Commission's World Wide Web site at http://www.sec.gov. The
Common Shares are traded on the NYSE and such reports, proxy statements and
other information may be inspected at 20 Broad Street, New York, New York 10005.
The Common Shares are also traded on the TSE and any filings with the TSE may be
inspected at The Exchange Tower, 2 First Canada Plaza, Toronto, Ontario, Canada
M5X 1J2.
The Company has filed with the Commission a Registration Statement on Form
S-3 under the Securities Act, with respect to the securities offered hereby.
This Prospectus does not contain exhibits and schedules and certain other
information which is part of the Registration Statement and which have been
omitted from this Prospectus as permitted by the rules and regulations of the
Commission. Statements contained herein concerning the contents of any contract,
agreement or other document filed as an exhibit to the Registration Statement
are necessarily summaries of such contracts, agreements or documents and are
qualified in their entirety by reference to each such exhibit. The Registration
Statement and the exhibits and schedules forming a part thereof can be obtained
from the Commission.
LISTING OF THE NOTES
Application will be made to list the Notes on the Luxembourg Stock
Exchange. For the purposes of listing on the Luxembourg Stock Exchange, a
Listing Circular (Prospectus de Cotateon) will be issued in Luxembourg on or
about the date of issuance of the Notes. The Company will appoint a special
agent in Luxembourg until such time as the Company is required to appoint a
transfer and paying agent located in Luxembourg. The Company reserves the right
to vary such appointment.
98
<PAGE> 99
GLOSSARY
The terms defined in this section are used throughout this Prospectus.
ANTICLINE. Geologically positive structure favorable for trapping
hydrocarbons.
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d. Barrels of oil produced per day.
Bcf. One billion cubic feet of natural gas.
BOE. One barrel of oil equivalent using the ratio of one barrel of
crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOE/d. BOEs produced per day.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
COMMERCIAL WELL; COMMERCIALLY PRODUCTIVE WELL. An oil and gas well
which produces oil and natural gas in sufficient quantities such that
proceeds from the sale of such production exceed production expenses and
taxes.
DEVELOPMENT WELL. A developmental well is a well drilled within the
presently proved productive area of an oil or natural gas reservoir, as
indicated by reasonable interpretation of available data, with the
objective of completing that reservoir.
DRY HOLE; DRY WELL; NON-PRODUCTIVE WELL. A well found to be incapable
of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
EXPLORATORY WELL. An exploratory well is a well drilled either in
search of a new, as-yet undiscovered oil or natural gas reservoir or to
greatly extend the known limits of a previously discovered reservoir.
FARMOUT. An assignment of an interest in a drilling location and
related acreage conditional upon the drilling of a well on that location.
FORMATION. A succession of sedimentary beds that were deposited under
the same general geologic conditions.
GEOPRESSURED. Pressures in excess of the normal increase in pressure
with depth.
GEOSYNCLINE. A regional area of subsidence in which sediments are
accumulated.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may
be, in which a working interest is owned.
HORIZONTAL WELLS. Wells which are drilled at angles greater than 70
degrees from vertical.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand BOEs.
MBOE/d. One thousand BOE/d.
MBtu. One thousand Btus.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One thousand cubic feet of natural gas produced per day.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBOE. One million BOEs.
99
<PAGE> 100
MMBtu. One million Btus.
MMcf. One million cubic feet of natural gas.
MMcf/d. One million cubic feet of natural gas produced per day.
NET; NET REVENUE INTEREST. Production or revenue that is owned by the
Company and produced for its interest after deducting royalties and other
similar interests.
NET ACRES OR NET WELLS. The sum of the fractional working interests
owned in gross acres or gross wells.
PV10 VALUE. When used with respect to oil and natural gas reserves,
PV10 Value means the estimated future gross revenue to be generated from
the production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect at the determination
date, without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax
expense or to depreciation, depletion and amortization, discounted to
present value using an annual discount rate of 10% in accordance with the
guidelines of the Commission.
PRODUCTIVE WELL. A well that is producing oil or natural gas or that
is capable of production.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be
recovered from existing wells with existing equipment and operating
methods.
PROVED RESERVES. The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion.
ROYALTY INTEREST. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of
costs of production.
Tcf. One trillion cubic feet of natural gas.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been
participated in or completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of whether such
acreage contains proved reserves.
WORKING INTEREST. The cost-bearing interest in a well or property
which gives the owner the right to drill, produce and conduct operating
activities on the property as well as to a share of production.
100
<PAGE> 101
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1997 (UNAUDITED)
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
DENBURY RESOURCES INC. AND SUBSIDIARIES
Independent Auditors' Report.............................. F-2
Consolidated Balance Sheets............................... F-3
Consolidated Statements of Income......................... F-4
Consolidated Statements of Cash Flows..................... F-5
Consolidated Statement of Changes in Shareholders'
Equity................................................. F-6
Notes to Consolidated Financial Statements................ F-7 thru F-29
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF
CHEVRON PROPERTIES
Report of Independent Accountants......................... F-30
Statements of Revenues and Direct Operating Expenses of
Properties............................................. F-31
Notes to Statement of Revenues and Direct Operating
Expenses of Properties................................. F-32 thru F-34
</TABLE>
F-1
<PAGE> 102
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc.
as at December 31, 1995 and 1996 and the consolidated statements of income,
changes in shareholders' equity and cash flows for each of the years in the
three year period ended December 31, 1996. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in Canada and the United States of America. Those standards require
that we plan and perform the audit to obtain reasonable assurance whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly in
all material respects, the financial position of the Company as at December 31,
1995 and 1996 and the results of its operations and the changes in shareholders'
equity and cash flows for each of the years in the three year period ended
December 31, 1996, in accordance with accounting principles generally accepted
in Canada.
Deloitte & Touche
Chartered Accountants
Calgary, Alberta
February 21, 1997
F-2
<PAGE> 103
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------- SEPTEMBER 30,
1995 1996 1997
-------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C>
CURRENT ASSETS
Cash and cash equivalents................................ $ 6,553 $ 13,453 $ 2,236
Accrued production receivable............................ 3,212 11,906 7,097
Trade and other receivables.............................. 1,160 3,643 14,507
-------- -------- --------
Total current assets............................. 10,925 29,002 23,840
-------- -------- --------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties........................... 72,510 159,724 230,521
Unevaluated oil and natural gas properties............... 7,085 6,413 6,389
Less accumulated depreciation and depletion.............. (13,982) (31,141) (53,527)
-------- -------- --------
Net property and equipment....................... 65,613 134,996 183,383
-------- -------- --------
OTHER ASSETS............................................... 1,103 2,507 3,201
-------- -------- --------
TOTAL ASSETS..................................... $ 77,641 $166,505 $210,424
======== ======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities................. $ 2,872 $ 10,903 $ 16,858
Oil and gas production payable........................... 1,014 5,550 4,060
Current portion of long-term debt........................ 177 67 23
-------- -------- --------
Total current liabilities........................ 4,063 16,520 20,941
-------- -------- --------
LONG-TERM LIABILITIES
Senior bank debt......................................... 75 125 20,005
Subordinated debt and other notes payable................ 3,399 -- --
Provision for site reclamation costs..................... 242 613 938
Deferred income taxes and other.......................... 1,361 6,743 12,982
-------- -------- --------
Total long-term liabilities...................... 5,077 7,481 33,925
-------- -------- --------
CONVERTIBLE FIRST PREFERRED SHARES, SERIES A
1,500,000 shares authorized, issued and outstanding at
December 31, 1995..................................... 15,000 -- --
-------- -------- --------
SHAREHOLDERS' EQUITY
Common shares, no par value unlimited shares authorized;
outstanding -- 11,428,809, 20,055,757 and 20,364,799
shares at December 31, 1995, December 31, 1996 and
September 30, 1997, respectively...................... 50,064 130,323 132,744
Retained earnings........................................ 3,437 12,181 22,814
-------- -------- --------
Total shareholders' equity....................... 53,501 142,504 155,558
-------- -------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY....... $ 77,641 $166,505 $210,424
======== ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
Approved by the Board:
<TABLE>
<S> <C>
/s/ GARETH ROBERTS /s/ WIELAND F. WETTSTEIN
- ----------------------------------------------------- -----------------------------------------------------
Gareth Roberts Wieland F. Wettstein
Director Director
</TABLE>
F-3
<PAGE> 104
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(U.S. DOLLARS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES
Oil, natural gas and related product
sales................................... $12,692 $20,032 $52,880 $34,709 $60,083
Interest income and other.................. 23 77 769 425 986
------- ------- ------- ------- -------
Total revenues..................... 12,715 20,109 53,649 35,134 61,069
------- ------- ------- ------- -------
EXPENSES
Production................................. 4,309 6,789 13,495 9,197 15,737
General and administrative................. 1,105 1,832 4,267 2,825 4,535
Interest................................... 1,146 2,085 1,993 1,530 387
Imputed preferred dividends................ -- -- 1,281 1,153 --
Loss on early extinguishment of debt....... -- 200 440 440 --
Depletion and depreciation................. 4,209 8,022 17,904 12,557 23,224
Franchise taxes............................ 65 100 213 160 308
------- ------- ------- ------- -------
Total expenses..................... 10,834 19,028 39,593 27,862 44,191
------- ------- ------- ------- -------
Income before income taxes................... 1,881 1,081 14,056 7,272 16,878
Provision for federal income taxes........... (718) (367) (5,312) (2,932) (6,245)
------- ------- ------- ------- -------
NET INCOME................................... $ 1,163 $ 714 $ 8,744 $ 4,340 $10,633
======= ======= ======= ======= =======
NET INCOME PER COMMON SHARE
Primary.................................... $ 0.19 $ 0.10 $ 0.67 $ 0.37 $ 0.53
Fully diluted.............................. 0.19 0.10 0.62 0.36 0.50
======= ======= ======= ======= =======
Average number of common shares
outstanding................................ 6,240 6,870 13,104 11,616 20,175
======= ======= ======= ======= =======
</TABLE>
See Notes to Consolidated Financial Statements
F-4
<PAGE> 105
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ -------------------
1994 1995 1996 1996 1997
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income..................................... $ 1,163 $ 714 $ 8,744 $ 4,340 $ 10,633
Adjustments needed to reconcile to net cash
flow provided by operations:
Depreciation, depletion and amortization..... 4,304 8,113 17,904 12,557 23,224
Deferred income taxes........................ 718 367 5,312 2,932 6,245
Imputed preferred dividend................... -- -- 1,281 1,153 --
Loss on early extinguishment of debt......... -- 200 440 440 --
Other........................................ -- -- 459 345 64
-------- -------- -------- -------- --------
6,185 9,394 34,140 21,767 40,166
Changes in working capital items relating to
operations:
Accrued production receivable................ (986) (1,303) (8,694) (4,388) 4,809
Trade and other receivables.................. (124) (168) (1,508) (659) (10,864)
Accounts payable and accrued liabilities..... 1,581 (1,660) 6,711 9,688 5,955
Oil and gas production payable............... 261 490 4,536 2,004 (1,490)
-------- -------- -------- -------- --------
NET CASH FLOW PROVIDED BY OPERATIONS............. 6,917 6,753 35,185 28,412 38,576
-------- -------- -------- -------- --------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures............. (10,297) (11,761) (38,450) (25,704) (54,700)
Acquisition of oil and natural gas
properties................................. (6,606) (16,763) (48,407) (47,616) (16,073)
Net purchases of other assets................ (122) (560) (1,726) (1,290) (1,238)
Acquisition of subsidiary, net of cash
acquired................................... -- -- 209 209 --
-------- -------- -------- -------- --------
NET CASH USED FOR INVESTING ACTIVITIES........... (17,025) (29,084) (88,374) (74,401) (72,011)
-------- -------- -------- -------- --------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank borrowings.............................. 9,835 19,350 47,900 44,900 19,900
Bank repayments.............................. (2,485) (34,200) (47,900) -- --
Issuance of subordinated debt................ 1,451 1,772 -- -- --
Issuance of common stock..................... 367 26,825 60,664 1,690 2,421
Issuance of preferred stock.................. -- 15,000 -- -- --
Costs of debt financing...................... (122) (493) (411) (408) (33)
Other........................................ 62 (82) (164) (135) (70)
-------- -------- -------- -------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES........ 9,108 28,172 60,089 46,047 22,218
-------- -------- -------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS.................................... (1,000) 5,841 6,900 58 (11,217)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR... 1,712 712 6,553 6,553 13,453
-------- -------- -------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD....... $ 712 $ 6,553 $ 13,453 $ 6,611 $ 2,236
======== ======== ======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest..... $ 1,027 $ 2,127 $ 1,621 $ 1,080 $ 150
SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES:
Conversion of subordinated debt to common
stock...................................... -- -- $ 3,314 $ 1,465 --
Conversion of preferred stock to common
stock...................................... -- -- 16,281 -- --
Assumption of liabilities in acquisition..... -- -- 1,321 1,321 --
</TABLE>
See Notes to Consolidated Financial Statements
F-5
<PAGE> 106
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
(DOLLAR AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
<TABLE>
<CAPTION>
COMMON SHARES
(NO PAR VALUE)
--------------------- RETAINED
SHARES AMOUNT EARNINGS TOTAL
---------- -------- -------- --------
<S> <C> <C> <C> <C>
BALANCE -- JANUARY 1, 1994........................ 6,208,417 $ 22,872 $ 1,560 $ 24,432
Issued pursuant to employee stock option plan... 96,250 367 -- 367
Net income...................................... -- -- 1,163 1,163
---------- -------- ------- --------
BALANCE -- DECEMBER 31, 1994...................... 6,304,667 23,239 2,723 25,962
---------- -------- ------- --------
Issued pursuant to employee stock option plan... 10,000 54 -- 54
Private placement of Special Warrants
exchanged.................................... 614,143 2,314 -- 2,314
Private placement of common shares.............. 4,499,999 24,457 -- 24,457
Net income...................................... -- -- 714 714
---------- -------- ------- --------
BALANCE -- DECEMBER 31, 1995...................... 11,428,809 50,064 3,437 53,501
---------- -------- ------- --------
Issued pursuant to employee stock option plan... 197,675 1,070 -- 1,070
Issued pursuant to employee stock purchase
plan......................................... 31,311 358 -- 358
Public placement of common shares............... 4,940,000 58,776 -- 58,776
Conversion of preferred stock................... 2,816,372 16,281 -- 16,281
Conversion of warrants.......................... 75,000 460 -- 460
Conversion of subordinated debt................. 566,590 3,314 -- 3,314
Net income...................................... -- -- 8,744 8,744
---------- -------- ------- --------
BALANCE -- DECEMBER 31, 1996...................... 20,055,757 130,323 12,181 142,504
---------- -------- ------- --------
Issued pursuant to employee stock option plan... 270,056 1,764 -- 1,764
Issued pursuant to employee stock purchase
plan......................................... 38,986 657 -- 657
Net income...................................... -- -- 10,633 10,633
---------- -------- ------- --------
BALANCE -- SEPTEMBER 30, 1997 (UNAUDITED)......... 20,364,799 $132,744 $22,814 $155,558
========== ======== ======= ========
</TABLE>
See Notes to Consolidated Financial Statements
F-6
<PAGE> 107
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996 AND FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 1996 AND 1997 (UNAUDITED)
1. SIGNIFICANT ACCOUNTING POLICIES
The Company's operating activities are related to exploration, development
and production of oil and natural gas in the United States. All of the Canadian
operations were sold effective September 1, 1993.
The Company's name was changed on June 7, 1994, from Canadian Newscope
Resources Inc. to Newscope Resources Ltd. and again on December 21, 1995 to
Denbury Resources Inc.
On October 9, 1996 the shareholders of the Company approved an amendment to
the Articles of Continuance to consolidate the number of issued and outstanding
Common Shares on the basis of one Common Share for each two Common Shares
outstanding. All applicable shares and per share data have been adjusted for the
reverse stock split.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles and include the accounts of
the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury
Management, Inc. and Denbury Marine L.L.C. and the Company's equity in the
operation of its 50% owned subsidiary, Denbury Energy Services ("Services"). The
Company acquired the remaining 50% of Services effective May 1, 1996 and began
consolidating all of Services as of that date. All material intercompany
balances and transactions have been eliminated.
OIL AND NATURAL GAS OPERATIONS
a) Capitalized costs
The Company follows the full-cost method of accounting for oil and natural
gas properties. Under this method, all costs related to the exploration for and
development of oil and natural gas reserves are capitalized and accumulated in a
single cost center representing the Company's activities undertaken exclusively
in the United States. Such costs include lease acquisition costs, geological and
geophysical expenditures, lease rentals on undeveloped properties, costs of
drilling both productive and non-productive wells and general and administrative
expenses directly related to exploration and development activities. Proceeds
received from disposals are credited against accumulated costs except when the
sale represents a significant disposal of reserves in which case a gain or loss
is recognized.
b) Depletion and depreciation
The costs capitalized, including production equipment, are depleted or
depreciated on the unit-of-production method, based on proved oil and natural
gas reserves as determined by independent petroleum engineers. Oil and natural
gas reserves are converted to equivalent units based upon the relative energy
content which is six thousand cubic feet of natural gas to one barrel of crude
oil.
c) Site reclamation
Estimated future costs of well abandonment and site reclamation, including
the removal of production facilities at the end of their useful life, are
provided for on a unit-of-production basis. Costs are based on engineering
estimates of the anticipated method and extent of site restoration, valued at
year-end prices, net of estimated salvage value, and in accordance with the
current legislation and industry practice. The annual provision for future site
reclamation costs is included in depletion and depreciation expense.
F-7
<PAGE> 108
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
d) Ceiling test
The capitalized costs less accumulated depletion, depreciation, related
deferred taxes and site reclamation costs are limited to an amount which is not
greater than the estimated future net revenue from proved reserves using
period-end prices less estimated future site restoration and abandonment costs,
future production-related general and administrative expenses, financing costs
and income taxes, plus the cost (net of impairments) of undeveloped properties.
e) Joint interest operations
Substantially all of the Company's oil and natural gas exploration and
production activities are conducted jointly with others. These financial
statements reflect only the Company's proportionate interest in such activities.
FOREIGN CURRENCY TRANSLATION
Since 1993 when the Company sold its Canadian oil and natural gas
properties, virtually all of the Company's assets are located in the United
States. These assets and the United States operations are accounted for and
reported in U.S. dollars and no translation is necessary. The minor amount of
Canadian assets and liabilities are translated to U.S. dollars using year-end
exchange rates and any Canadian operations, which are principally minor
administrative and interest expenses, are translated using the historical
exchange rate.
EARNINGS PER SHARE
Net income per common share is computed by dividing the net income
attributable to common shareholders by the weighted average number of shares of
common stock outstanding. In accordance with Canadian generally accepted
accounting principles ("GAAP"), the imputed dividend during 1996 on the
Convertible First Preferred Shares, Series A has been recorded as an operating
expense in the accompanying financial statements and this is deducted from net
income in computing earnings per share. The conversion of the Convertible First
Preferred Shares, Series A ("Convertible Preferred") was anti-dilutive and was
not included in the calculation of earnings per share. In computing fully
diluted earnings per share, the stock options, warrants and convertible debt
instruments were dilutive for the year ended December 31, 1996 and for the nine
months ended September 30, 1997 and were assumed to be converted or exercised as
of the beginning of the respective period with the proceeds used to reduce
interest expense. For the prior years, these instruments were either
anti-dilutive or immaterial. All of the Convertible Preferred and the
convertible debt were converted into common shares during 1996 and thus were not
relevant to the calculation of earnings per share during 1997.
STATEMENT OF CASH FLOWS
For purposes of the Statement of Cash Flows, cash equivalents include time
deposits, certificates of deposit and all liquid debt instruments with
maturities at the date of purchase of three months or less.
REVENUE RECOGNITION
The Company follows the "sales method" of accounting for its oil and
natural gas revenue whereby the Company recognizes sales revenue on all oil or
natural gas sold to its purchasers, regardless of whether the sales are
proportionate to the Company's ownership in the property. A receivable or
liability is recognized only to the extent that the Company has an imbalance on
a specific property greater than the expected remaining proved reserves. As of
December 31, 1995 and 1996 and September 30, 1997, the Company's aggregate oil
and natural gas imbalances were not material to its financial statements.
F-8
<PAGE> 109
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company recognizes revenue and expenses of purchased producing
properties commencing from the closing or agreement date, at which time the
Company also assumes control.
FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK AND CONCENTRATIONS OF CREDIT
RISK
The Company's product price hedging activities are described in Note 6 to
the consolidated financial statements. Credit risk relating to these hedges is
minimal because of the credit risk standards required for counter-parties and
monthly settlements. The Company has entered into hedging contracts with only
large and financially strong companies.
The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of cash equivalents, short-term investments and
trade and accrued production receivables. The Company's cash equivalents and
short-term investments represent high-quality securities placed with various
investment grade institutions. This investment practice limits the Company's
exposure to concentrations of credit risk. The Company's trade and accrued
production receivables are dispersed among various customers and purchasers;
therefore, concentrations of credit risk are limited. Also, the Company's more
significant purchasers are large companies with excellent credit ratings. If
customers are considered a credit risk, letters of credit are the primary
security obtained to support lines of credit.
FAIR VALUE OF FINANCIAL INSTRUMENTS
As of December 31, 1995, December 31, 1996 and September 30, 1997, the
carrying value of the Company's debt and other financial instruments
approximates its fair market value. The Company's bank debt is based on a
floating interest rate and thus adjusts to market as interest rates change. The
Company's other financial instruments are primarily cash, cash equivalents,
short-term receivables and payables which approximate fair value due to the
nature of the instrument and the relatively short maturities.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amount of certain assets, liabilities,
revenues and expenses as of and for the reporting period. Estimates and
assumptions are also required in the disclosure of contingent assets and
liabilities as of the date of the financial statements. Actual results may
differ from such estimates.
INTERIM FINANCIAL DATA
In the opinion of management, the accompanying unaudited consolidated
financial statements contain all the adjustments (consisting of only normal
recurring accruals) necessary to present fairly the consolidated financial
position as of September 30, 1997, and the results of its operations and its
cash flow for the nine months ended September 30, 1996 and 1997.
2. PROPERTY AND EQUIPMENT
UNEVALUATED OIL AND NATURAL GAS PROPERTIES EXCLUDED FROM DEPLETION
Under full cost accounting, the Company may exclude certain unevaluated
costs from the amortization base pending determination of whether proved
reserves have been discovered or impairment has occurred. A
F-9
<PAGE> 110
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
summary of the unevaluated properties excluded from oil and natural gas
properties being amortized at December 31, 1995 and 1996 and September 30, 1997
and the year in which they were incurred follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 DECEMBER 31, 1996
--------------------------------- ----------------------
INCURRED IN INCURRED IN
------------------------ ----------------------
1993 1994 1995 TOTAL 1995 1996 TOTAL
------ ------ ------ ------ ---- ------ ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Property acquisition cost..... $1,151 $1,230 $2,909 $5,290 $252 $2,614 $2,866
Exploration costs............. -- 1,146 649 1,795 87 3,460 3,547
------ ------ ------ ------ ---- ------ ------
Total............... $1,151 $2,376 $3,558 $7,085 $339 $6,074 $6,413
====== ====== ====== ====== ==== ====== ======
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
(UNAUDITED)
----------------------
INCURRED IN
----------------------
1995 1996 1997 TOTAL
---- ------ ------ ------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
Property acquisition cost.............................. $-- $ 286 $ 930 $1,216
Exploration costs...................................... 53 1,457 3,663 5,173
--- ------ ------ ------
Total........................................ $53 $1,743 $4,593 $6,389
=== ====== ====== ======
</TABLE>
The Company anticipates that approximately $75 million of the costs
relating to the Chevron Acquisition which closed in December, 1997 will be
classified as unevaluated as of December 31, 1997.
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
Pending determination of proved reserves attributable to the above costs, the
Company cannot assess the future impact on the amortization rate.
General and administrative costs that directly relate to exploration and
development activities that were capitalized during the period totaled $480,000,
$630,000 and $1,224,000 for the years ended December 31, 1994, 1995 and 1996 and
$851,000 and $1,675,000 for the nine months ended September 30, 1996 and 1997,
respectively.
Amortization per BOE was $4.03, $5.22, $5.99 and $6.40 for the years ended
December 31, 1994, 1995 and 1996 and nine months ended September 30, 1997,
respectively.
3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
<TABLE>
<CAPTION>
DECEMBER 31,
------------- SEPTEMBER 30,
1995 1996 1997
------ ---- -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
Senior bank loan......................................... $ 100 $100 $ 20,000
Convertible debentures................................... 3,296 -- --
Other notes payable...................................... 255 92 28
------ ---- -------------
3,651 192 20,028
Less portion due within one year......................... (177) (67) (23)
------ ---- -------------
Total long-term debt................................... $3,474 $125 $ 20,005
====== ==== =============
</TABLE>
F-10
<PAGE> 111
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
BANKS
During 1996 the Company entered into a new $150 million credit facility
with NationsBank of Texas, N.A. ("NationsBank"). This refinancing closed on May
31, 1996 and has a borrowing base as of December 31, 1996 of $60 million.
NationsBank is the agent bank and the facility includes two other banks.
The credit facility is a two-year revolving credit facility that converts to a
three year term loan in May 1998, unless renewed or extended. This revolver
conversion date was extended to May 1999 on April 1, 1997. The credit facility
is secured by virtually all the Company's oil and natural gas properties and
interest is payable at either the bank's prime rate or, depending on the
percentage of the borrowing base that is outstanding, ranging from LIBOR plus
7/8% to LIBOR plus 1 3/8%. This credit facility also has several restrictions
including, among others: (i) a prohibition on the payment of dividends, (ii) a
requirement for a minimum equity balance, (iii) a requirement to maintain
positive working capital as defined, and (iv) a prohibition of most debt and
corporate guarantees. As of December 31, 1996, the Company had $100,000
outstanding on this line of credit and $645,000 of letters of credit
outstanding.
The Company made two amendments to its bank credit facility during 1997 and
revised and restated its facility in December, 1997. See Note 12 for additional
disclosures.
SUBORDINATED DEBT
On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of
6 3/4% unsecured convertible debentures and on January 17, 1995, Denbury issued
Cdn. $2,500,000 principal amount of 9 1/2% unsecured convertible debentures.
These debentures were converted into 566,590 Common Shares during 1996.
INDEBTEDNESS REPAYMENT SCHEDULE
The Company's indebtedness is repayable as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1996
-------------------------------------
OTHER NOTES
YEAR BANK LOAN PAYABLE TOTAL
---- --------- ----------- -----
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
1997.............................................. $ -- $67 $ 67
1998.............................................. 17 23 40
1999.............................................. 33 2 35
2000.............................................. 33 -- 33
2001.............................................. 17 -- 17
---- --- ----
$100 $92 $192
==== === ====
</TABLE>
F-11
<PAGE> 112
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
SEPTEMBER 30, 1997 (UNAUDITED)
---------------------------------------
OTHER NOTES
YEAR BANK LOAN PAYABLE TOTAL
---- --------- ----------- -------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
1997........................................... $ -- $ 3 $ 3
1998........................................... -- 23 23
1999........................................... 3,333 2 3,335
2000........................................... 6,667 -- 6,667
2001........................................... 6,667 -- 6,667
2002........................................... 3,333 -- 3,333
------- --- -------
$20,000 $28 $20,028
======= === =======
</TABLE>
4. INCOME TAXES
The Company's tax provision is as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- ------------------
1994 1995 1996 1996 1997
----- ----- ------- ------- -------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Deferred
Federal.................................... $718 $367 $5,312 $2,932 $5,907
State...................................... -- -- -- -- 338
---- ---- ------ ------ ------
Total.............................. $718 $367 $5,312 $2,932 $6,245
==== ==== ====== ====== ======
</TABLE>
Income tax expense for the year varies from the amount that would result
from applying Canadian federal and provincial tax rates to income before income
taxes as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- ------------------
1994 1995 1996 1996 1997
----- ----- ------- ------- --------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Deferred income tax provision calculated
using the Canadian federal and
provincial statutory combined tax rate
of 44.34%............................... $ 834 $ 479 $ 6,233 $3,224 $ 7,484
Increase resulting from:
Imputed preferred dividend.............. -- -- 568 511 --
Non-deductible Canadian expenses........ -- -- 97 64 --
Decrease resulting from:
Effect of lower income tax rates on
United States income................. (116) (112) (1,586) (867) (1,239)
----- ----- ------- ------ -------
$ 718 $ 367 $ 5,312 $2,932 $ 6,245
===== ===== ======= ====== =======
</TABLE>
F-12
<PAGE> 113
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company at December 31, 1996 had net operating loss carryforwards for
U.S. tax purposes of approximately $18,329,000 and approximately $12,485,000 for
alternative minimum tax purposes. The net operating losses are scheduled to
expire as follows:
<TABLE>
<CAPTION>
INCOME ALTERNATIVE
YEAR TAX MINIMUM TAX
---- ------- ------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C>
2004.................................................. $ 39 $ --
2005.................................................. 11 --
2006.................................................. 644 500
2007.................................................. 714 99
2008.................................................. 5,016 4,889
2009.................................................. 3,377 2,868
2010.................................................. 3,467 3,420
2011.................................................. 5,061 710
</TABLE>
5. SHAREHOLDERS' EQUITY
AUTHORIZED
The Company is authorized to issue an unlimited number of Common Shares
with no par value, First Preferred Shares and Second Preferred Shares. The
preferred shares may be issued in one or more series with rights and conditions
as determined by the Directors.
COMMON SHARES
Each Common Share entitles the holder thereof to one vote on all matters on
which holders are permitted to vote. The Texas Pacific Group ("TPG") was granted
a right of first refusal in the private placement (see below), to maintain
proportionate ownership. No stockholder has any right to convert common stock
into other securities. The holders of shares of common stock are entitled to
dividends when and if declared by the Board of Directors from funds legally
available therefore and, upon liquidation, to a pro rata share in any
distribution to stockholders, subject to prior rights of the holders of the
preferred stock. The Company is restricted from declaring or paying any cash
dividend on the Common Shares by its bank loan agreement.
1996 CAPITAL ADJUSTMENTS
During 1996, the Company issued 250,000 Common Shares for the conversion of
the 6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for
the exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10,
1996, the Company effected a one-for-two reverse split of its outstanding common
Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2%
Convertible Debentures ("Debentures") were converted by their holders in
accordance with their terms into 308,642 Common Shares. The holders of the
Debentures also received an additional 7,948 Common Shares in lieu of interest
which would have been due the holders absent an early conversion of the
Debentures. At a special meeting held on October 9, 1996, the shareholders of
the Company approved an amendment to the terms of the First Preferred Shares,
Series A ("Convertible Preferred") to allow the Company to require the
conversion of the Convertible Preferred at any time, provided that the
conversion rate in effect as of January 1, 1999 would apply to any required
conversion prior to that date. The Company converted all of the 1,500,000 shares
of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. The
Company also issued an aggregate of 4,940,000 Common Shares on October 30, 1996
and November 1, 1996 at a net price of $12.035 per share as part of a public
offering for net proceeds to the Company of approximately $58.8 million (the
"Public Offering"). TPG purchased 800,000 of these shares at $12.035 per share.
F-13
<PAGE> 114
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
PRIVATE PLACEMENT OF SECURITIES
In December 1995, the Company closed a $40 million private placement of
securities with partnerships that are affiliated with the Texas Pacific Group
("TPG Placement"). The TPG Placement was comprised of: (i) 4.166 million common
shares issued at $5.85 per share, (ii) 625,000 warrants at a price of $1.00 per
warrant entitling the holder to purchase 625,000 common shares at $7.40 per
share through December 21, 1999 and (iii) 1.5 million shares of $10 stated value
Convertible Preferred. The Convertible Preferred shares were initially
convertible at $7.40 of stated value per common share with such conversion rate
declining 2.5% per quarter. The shares also had a mandatory redemption at a
63.86% premium at December 21, 2000. The Convertible Preferred were converted
into 2,816,372 Common Shares on October 30, 1996. During the period that the
Convertible Preferred were outstanding, the Company made a charge to net income
to accrue the increase during the period in the mandatory redemption premium.
The Company may force conversion of the $7.40 warrants issued in the TPG
Placement after December 21, 1997, if the price of the Common Shares exceeds
$10.00 per share for a period of 40 consecutive days.
As part of the TPG Placement, TPG was granted certain "piggyback"
registration rights which allow TPG to include all or part of the Common Shares
acquired by TPG in any registration statement of the Company during the first
two years. After the initial two years and until December 21, 2000, TPG may
request and receive one demand registration statement to register the Common
Shares acquired by TPG.
The TPG agreement provides that TPG shall have the right, but not the
obligation, to maintain its pro rata ownership interest (after the assumed
exercise of their warrants) in the equity securities of the Company, in the
event that the Company issues any additional equity securities or securities
convertible into Common Shares of the Company, by purchasing additional shares
of the Company on the same terms and conditions. However, this right expires
should TPG's share holdings represent less than 20% of the outstanding Common
Shares. TPG waived its right to maintain its pro rata ownership with regard to
the Equity Offering.
As part of the TPG Placement, Tortuga Investment Corp. was paid a financial
advisor fee of 333,333 Common Shares of the Company. The sole shareholder of
Tortuga Investment Corp. was appointed to the Board of Directors of the Company
and elected Chairman upon the closing of the TPG Placement.
WARRANTS
At December 31, 1996, 75,000 warrants were outstanding at an exercise price
of Cdn. $8.40 expiring on May 5, 2000. TPG holds 625,000 warrants at an exercise
price of $7.40 expiring on December 21, 1999. Each warrant entitles the holder
thereof to purchase one Common Share at any time prior to the expiration date.
SPECIAL WARRANT ISSUES
On April 25, 1995, the Company issued 614,143 Special Warrants at a price
of $4.70 (Cdn. $6.50) per Special Warrant for gross proceeds of $2,750,000
(29,036 Common Share Purchase Warrants were issued to Southcoast Capital
Corporation, as placement agent, in partial payment of their fee). Costs of the
issue were $436,000, resulting in net proceeds to the Company of approximately
$2,314,000. Each Special Warrant was exchanged, at no additional cost, for one
Common Share of Denbury on August 11, 1995.
F-14
<PAGE> 115
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STOCK OPTIONS AND STOCK PURCHASE PLAN
The Company maintains a Stock Option Plan which authorizes the grant of
options of up to 2,243,525 of Common Shares. Under the plan, incentive and
non-qualified options may be issued to officers, key employees and consultants.
The plan is administered by the Stock Option Committee of the Board.
Following is a summary of stock option activity during the years ended
December 31, 1994, 1995 and 1996 and the nine months ended September 30, 1997:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED
------------------------------------------------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------------------- ------------------- --------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE AVERAGE
NUMBER PRICE NUMBER PRICE NUMBER PRICE NUMBER PRICE
------- -------- ------- -------- --------- -------- --------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
OUTSTANDING AT
BEGINNING OF
PERIOD.............. 541,312 $6.68 557,312 $6.30 731,925 $6.11 1,053,000 $ 7.63
Granted............... 138,750 5.64 274,500 5.89 525,500 8.96 750,512 13.64
Terminated............ (26,500) 9.35 (89,887) 7.79 (6,750) 6.28 (21,250) 12.02
Exercised............. (96,250) 3.74 (10,000) 5.42 (197,675) 5.42 (270,056) 6.93
Expired............... -- -- -- -- -- -- -- --
------- ----- ------- ----- --------- ----- --------- ------
OUTSTANDING AT END OF
PERIOD.............. 557,312 $6.30 731,925 $6.11 1,053,000 $7.63 1,512,206 $10.69
======= ===== ======= ===== ========= ===== ========= ======
Options exercisable at
end of period....... 487,937 $6.39 539,675 $6.19 532,375 $6.82 395,222 $ 7.56
======= ===== ======= ===== ========= ===== ========= ======
</TABLE>
<TABLE>
<CAPTION>
WEIGHTED WEIGHTED
OPTIONS OUTSTANDING AS OF OPTIONS AVERAGE WEIGHTED AVERAGE EXERCISABLE AVERAGE
DECEMBER 31, 1996: OUTSTANDING PRICE REMAINING LIFE (YRS.) OPTIONS PRICE
- ------------------------- ----------- -------- --------------------- ----------- --------
<S> <C> <C> <C> <C> <C>
Exercise price of:
$3.65 to $6.99 372,000 $ 5.79 4.3 305,250 $ 5.77
$7.00 to $9.99 444,625 7.78 6.5 175,906 7.70
$10.00 to $14.87 236,375 10.23 9.4 51,219 10.09
</TABLE>
In February 1996, the Company also implemented a Stock Purchase Plan which
authorizes the sale of up to 250,000 Common Shares to all full-time employees
with at least six months of service. Under the plan, the employees may
contribute up to 10% of their base salary and the Company matches 75% of the
employee contribution. The combined funds are used to purchase previously
unissued Common Shares of the Company based on its current market value at the
end of the each quarter. The Company recognizes compensation expense for the 75%
Company matching portion, which for 1996 totaled $147,000 and for the nine
months ended September 30, 1997 totaled $282,000. This plan is administered by
the Stock Purchase Plan Committee of the Board.
6. PRODUCT PRICE HEDGING CONTRACTS
In October 1994, the Company entered into two financial contracts
("collars") to hedge 10,000 Mcf/d of natural gas production for calendar year
1995. The first natural gas contract for 8,000 Mcf/d of natural gas had a floor
of $1.845 per MMBTU and a ceiling of $2.095 per MMBTU. The second natural gas
contract was for 2,000 Mcf/d and had a floor of $1.775 per MMBTU and a ceiling
of $1.885 per MMBTU. These contracts covered 75% of the Company's net revenue
interest production in 1995 and increased oil and natural gas revenues by
approximately $800,000 during such period.
In addition, in 1995 the Company entered into two swap contracts for oil.
The first oil contract was for 500 Bbls/d of oil at a price of $17.79 per barrel
of oil commencing on February 1, 1995, and ending on January 31, 1996. The
second oil contract was also for 500 Bbls/d of oil at a price of $18.83, for the
period commencing on April 12, 1995, and ending on December 30, 1995. These
contracts covered 43% of the Company's net revenue interest production for 1995
and decreased oil and natural gas revenues by approximately $47,000 during such
period.
F-15
<PAGE> 116
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company did not have any hedge contracts in place as of December 31,
1996 or September 30, 1997.
7. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1996, and September 30, 1997 long-term
commitments for these items require the following future minimum rental
payments:
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1996 1997
------------ -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C>
1997............................................. $ 442 $ 123
1998............................................. 441 474
1999............................................. 166 988
2000............................................. -- 1,196
2001............................................. -- 1,192
2002............................................. -- 1,178
------ ------
$1,049 $5,151
====== ======
</TABLE>
On August 6, 1997, the Company entered into a ten year office lease. See
Note 12.
The Company is subject to various possible contingencies which arise
primarily from interpretation of federal and state laws and regulations
affecting the oil and natural gas industry. Such contingencies include differing
interpretations as to the prices at which oil and natural gas sales may be made,
the prices at which royalty owners may be paid for production from their leases
and other matters. Although management believes it has complied with the various
laws and regulations, administrative rulings and interpretations thereof,
adjustments could be required as new interpretations and regulations are issued.
In addition, production rates, marketing and environmental matters are subject
to regulation by various federal and state agencies.
The Company is not currently a party to any litigation which would have a
material impact on its financial statements. However, due to the nature of its
business, certain legal or administrative proceedings may arise in the ordinary
course of its business.
8. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN
CANADA AND THE UNITED STATES
The consolidated financial statements have been prepared in accordance with
GAAP in Canada. The primary differences between Canadian and U.S. GAAP affecting
the Company's consolidated financial statements are as discussed below.
LOSS ON EXTINGUISHMENT OF DEBT AND IMPUTED PREFERRED DIVIDENDS
The most significant GAAP difference relates to the presentation of the
early extinguishment of debt and the imputed dividend on the Convertible
Preferred. During 1996, the Company expensed $1,281,000 relating to the imputed
preferred dividend, as required under Canadian GAAP. Under U.S. GAAP, this
dividend would be deducted from net income to compute the net income
attributable to the common shareholders. The Company also expensed its debt
issue cost relating to the Company's prior bank credit agreements totaling
$200,000 and $440,000 for 1995 and 1996, respectively. Under Canadian GAAP this
is an operating expense, while under U.S. GAAP a loss on early extinguishment of
debt is an extraordinary item. While net income per common share and all balance
sheet accounts are not affected by these differences in GAAP, the net income
F-16
<PAGE> 117
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
for 1995 and 1996 under U.S. GAAP would be $714,000 and $10,025,000,
respectively, while under Canadian GAAP the amounts reported were $714,000 and
$8,744,000, respectively.
EARNINGS PER SHARE
In addition, the methodology for computing earnings per common share is not
consistent between the two countries. For Canadian purposes, dilutive securities
are only considered in the fully diluted presentation of earnings per share and
the proceeds from such dilutive securities are used to reduce debt in the
calculation. Under U.S. GAAP, the proceeds from such instruments are used to
repurchase Common Shares, using a slightly different methodology for the primary
and fully diluted calculations. For the years ended December 31, 1994 and 1995,
the stock options, warrants, convertible debt and the conversion of the
Convertible Preferred were either anti-dilutive or immaterial and were not
included in the earnings per share under either GAAP calculation. For the year
ended December 31, 1996, the Convertible Preferred was still anti-dilutive, but
the stock options, convertible debt and warrants were dilutive and included in
the earnings per share calculations, but with different results under the two
respective GAAP's. Under U.S. GAAP for the year ended December 31, 1996, the
primary earnings per share would be $.64 and the fully-diluted earnings per
share would be $.63 as compared to the $.67 and $.62 as reported under Canadian
GAAP.
For the first nine months of 1996, under U.S. GAAP, the primary and
fully-diluted earnings per common share would be $0.36 and $0.35, compared to
the $0.37 and $0.36, respectively, as reported under Canadian GAAP. Under U.S.
GAAP for the first nine months of 1997, the primary and fully-diluted earnings
per common share would be $0.50 and $0.49, as compared to the $0.53 and $0.50,
respectively, as reported under Canadian GAAP.
During 1996, the Company issued 4,940,000 Common Shares in a public
offering and used a portion of the proceeds to retire bank debt. On a pro forma
basis using U.S. GAAP and assuming that the Common Shares had been issued as of
January 1, 1996 and the interest expense for 1996 relating to the bank debt was
reversed, the primary earnings per share would be $.57 per share. No interest
income was assumed in the pro forma calculation even though the proceeds from
the equity issuance exceeded the bank debt that was retired.
STOCK-BASED COMPENSATION
In 1995, the United States Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for
Stock-Based Compensation." SFAS No. 123 is effective for fiscal years beginning
after December 31, 1995 and requires companies to use recognized option pricing
models to estimate the fair value of stock-based compensation, including stock
options. The Statement requires additional disclosures based on this fair value
based method of accounting for an employee stock option and encourages, but does
not require, companies to recognize the value of these stock option grants as
additional compensation using the methodology of SFAS No. 123. The Company has
elected to continue recognizing expense as prescribed by APB Opinion No. 25,
"Accounting for Stock Issued to Employees", as allowed under SFAS No. 123 rather
than recognizing compensation expense as calculated under SFAS No. 123. As such,
the adoption of SFAS No. 123 during 1996 did not have any effect on the
Company's consolidated financial statements.
F-17
<PAGE> 118
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company has two stock-based compensation plans as more fully described
in Note 5. With regard to its stock option plan, the Company applies APB Opinion
No. 25 in accounting for this plan and accordingly no compensation cost has been
recognized. Had compensation expense been determined based on the fair value at
the grant dates for the stock option grants consistent with the method of SFAS
No. 123, the Company's net income and net income per common share would have
been reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1996
------- --------
<S> <C> <C>
Net income:
As reported (thousands)................................... $ 714 $8,744
Pro forma (thousands)..................................... 503 8,215
Net income per common share:
As reported............................................... $0.10 $ 0.67
Pro forma................................................. 0.07 0.63
Stock options issued during period (thousands).............. 275 526
Weighted average exercise price............................. $5.90 $ 8.96
Average per option compensation value of options
granted(a)................................................ 2.34 2.95
Compensation cost (thousands)............................... 320 801
</TABLE>
- ---------------
(a) Calculated in accordance with the Black-Scholes option pricing model, using
the following assumptions; expected volatility computed using, as of the
date of grant, the prior three-year monthly average of the Common Shares as
listed on the TSE, which ranged from 32% to 67%; expected dividend
yield -- 0%; expected option term -- 3 years, and risk-free rate of return
as of the date of grant which ranged from 5.3% to 7.8%, based on the yield
of five-year U.S. treasury securities.
DEFERRED INCOME TAXES
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1995 and 1996 balance sheet dates.
At December 31, 1995, and 1996, all deferred tax assets and liabilities were
computed based on Canadian GAAP amounts and were noncurrent as follows:
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
DECEMBER 31, SEPTEMBER 30,
------------------ -------------
1995 1996 1997
------- ------- -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
Deferred tax assets:
Loss carryforwards............................... $(4,511) $(4,902) $(10,100)
Deferred tax liabilities:
Exploration and intangible development costs..... 5,942 11,645 23,088
------- ------- --------
Net deferred tax liability......................... $ 1,431 $ 6,743 $ 12,988
======= ======= ========
</TABLE>
RECENTLY ISSUED ACCOUNTING STANDARDS
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants has adopted Statement of Position 96-1,
"Environmental Remediation Liabilities," which provides guidance on the
recognition, measurement, display and disclosure of environmental remediation
liabilities. The Statement is effective for the Company's 1997 fiscal year.
Management evaluated such Statement and believes that it will not have a
material effect on the financial position or results of operations of the
Company.
F-18
<PAGE> 119
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In February 1997 the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 Earnings Per Share, ("SFAS 128")
simplifies the standards for computing earnings per share ("EPS") and makes them
more comparable to international EPS standards. SFAS 128 replaces the
presentation of primary EPS with a presentation of basic EPS. Basic EPS excludes
dilution and is computed by dividing income available to common shareholders by
the weighted average number of common shares outstanding for the period. Diluted
EPS reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised, converted into common stock or
resulted in the issuance of common shares that then shared in the earnings of
the entity. Diluted EPS is computed similarly to fully diluted EPS pursuant to
Accounting Principles Board Opinion No. 15. SFAS 128 is effective for financial
statements issued for periods ending after December 15, 1997, including interim
periods. Earlier application is not permitted. Basic EPS for the year ended
December 31, 1994, 1995 and 1996 and the nine months ended September 30, 1996
and 1997 under SFAS 128 would $0.19, $0.10, $0.67, $0.37, and $0.53 per common
share respectively. This compares to $0.19, $0.10, $0.64, $0.36, and $0.50
respective periods as computed under current U.S. GAAP.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for reporting and
display of comprehensive income in the financial statements. Comprehensive
income is the total of net income and all other non-owner changes in equity.
SFAS No. 131 requires that companies disclose segment data based on how
management makes decisions about allocating resources to segments and measuring
their performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of
these standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.
9. SUPPLEMENTAL INFORMATION
SIGNIFICANT OIL AND NATURAL GAS PURCHASERS
Oil and natural gas sales are made on a day-to-day basis or under
short-term contracts at the current area market price. The loss of any purchaser
would not be expected to have a material adverse effect upon operations. For the
period ended December 31, 1996, the Company sold 10% or more of its net
production of oil and natural gas to the following purchasers: Natural Gas
Clearinghouse (20%), Penn Union Energy Services (19%), Enron Oil Trading &
Transportation (13%), and Hunt Refining (15%).
COSTS INCURRED
The following table summarizes costs incurred in oil and natural gas
property acquisition, exploration and development activities. Property
acquisition costs are those costs incurred to purchase, lease, or otherwise
acquire property, including both undeveloped leasehold and the purchase of
revenues in place. Exploration costs include costs of identifying areas that may
warrant examination and in examining specific areas that are considered to have
prospects containing oil and natural gas reserves, including costs of drilling
exploratory wells, geological and geophysical costs and carrying costs on
undeveloped properties. Development costs are incurred to obtain access to
proved reserves, including the cost of drilling development wells, and to
provide facilities for extracting, treating, gathering, and storing the oil and
natural gas.
F-19
<PAGE> 120
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs incurred in oil and natural gas activities for the years ended
December 31, 1994, 1995 and 1996 and the nine months ended September 1997 are as
follows:
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------- SEPTEMBER 30,
1994 1995 1996 1997
------- ------- ------- -------------
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C>
Property acquisition......................... $ 6,736 $17,198 $48,856 $17,592
Exploration.................................. 1,796 1,687 4,592 14,058
Development.................................. 8,371 9,639 33,409 39,123
------- ------- ------- -------
$16,903 $28,524 $86,857 $70,773
======= ======= ======= =======
</TABLE>
PROPERTY ACQUISITIONS
During April 1996, the Company closed an acquisition of additional working
interests in five Mississippi oil and natural gas properties in which the
Company already owned an interest, plus certain overriding royalty interests in
other areas for approximately $7.5 million (the "Ottawa Acquisition"). The
properties were acquired from Ottawa Energy, Inc., a subsidiary of Highridge
Exploration Ltd.
On April 17, 1996, Denbury entered into a purchase and sale agreement with
Amerada Hess Corporation to purchase producing oil and natural gas properties in
Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in
Ohio, for approximately $37.2 million (the "Hess Acquisition"). The Company
funded this acquisition with bank financing from its NationsBank credit facility
and closed this transaction during June 1996.
These two acquisitions were accounted for under purchase accounting and the
results of operations were consolidated during the second quarter of 1996. Pro
forma results of operations of the Company as if the acquisitions had occurred
at the beginning of each respective period are as follows:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
-----------------
1995 1996
------- -------
<S> <C> <C>
Revenues (thousands)........................................ $41,273 $61,573
Net income (thousands)...................................... 899 9,820
Net income per common share................................. 0.13 0.75
</TABLE>
In computing the pro forma results, depreciation, depletion and
amortization expense was computed using the units of production method, and an
adjustment was made to interest expense reflecting the bank debt that was
required to fund the acquisitions. The pro forma results reflect an increase of
$250,000 and $500,000 for 1996 and 1995, respectively, in general and
administrative expense for additional personnel and associated costs relating to
the acquired properties, net of anticipated allocations to operations and
capitalization of exploration costs.
F-20
<PAGE> 121
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Hess Acquisition by the Company
and are presented on the full cost accrual basis of accounting. Depreciation,
depletion, and amortization, allocated general and administrative expenses,
interest expense and income, and income taxes have been excluded because the
property interests acquired represent only a portion of a business and these
expenses are not necessarily indicative of the expenses to be incurred by the
Company.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1995 1996
------- ------- -------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product sales............. $17,787 $18,210 $20,165
Direct operating expenses:
Lease operating expense................................ 6,598 7,888 6,302
------- ------- -------
Excess of revenues over direct operating expenses........ $11,189 $10,322 $13,863
======= ======= =======
</TABLE>
The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Ottawa Acquisition by the
Company and are presented on the full cost accrual basis of accounting.
Depreciation, depletion, and amortization, allocated general and administrative
expenses, interest expense and income, and income taxes have been excluded
because the property interests acquired represent only a portion of a business
and these expenses are not necessarily indicative of the expenses to be incurred
by the Company.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1996
------------
(AMOUNTS IN
THOUSANDS)
<S> <C>
Revenues:
Oil, natural gas and related product sales................ $4,215
Direct operating expenses:
Lease operating expense................................... 760
------
Excess of revenues over direct operating expenses........... $3,455
======
</TABLE>
In November 1995, the Company acquired seven producing wells and certain
non-producing leases in the Gibson/Humphreys Fields of Terrebonne Parish,
Louisiana for approximately $10.2 million.
See also Note 12 for disclosures regarding the Chevron Acquisition made in
December, 1997.
F-21
<PAGE> 122
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Denbury Management, Inc. will be issuing debt securities during early 1998
which will be fully and unconditionally guaranteed by Denbury Resources Inc.
Denbury Holdings Ltd. was merged into Denbury Resources Inc. in December 1997
and is not a guarantor of the debt. Condensed consolidating financial
information for Denbury Resources Inc. and Subsidiaries as of December 31, 1995
and 1996 and September 30, 1997 and for the years ended December 31, 1994, 1995
and 1996 and for the nine months ended September 30, 1996 and 1997 is as
follows:
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
(IN THOUSANDS OF U.S. DOLLARS)
<TABLE>
<CAPTION>
DECEMBER 31, 1995
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets.......................... $10,910 $ -- $ 15 $ -- $10,925
Property and equipment (using full cost
accounting)........................... 65,613 -- -- -- 65,613
Investment in subsidiaries (equity
method)............................... -- 71,693 70,130 (141,823) --
Other assets............................ 1,075 -- 1,591 (1,563) 1,103
------- ------- ------- --------- -------
Total assets................... $77,598 $71,693 $71,736 $(143,386) $77,641
======= ======= ======= ========= =======
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current liabilities..................... $ 4,054 $ -- $ 9 $ -- $ 4,063
Long-term liabilities................... 1,851 1,563 3,226 (1,563) 5,077
Convertible First Preferred Shares...... -- -- 15,000 -- 15,000
Shareholders' equity.................... 71,693 70,130 53,501 (141,823) 53,501
------- ------- ------- --------- -------
Total liabilities and
shareholders' equity......... $77,598 $71,693 $71,736 $(143,386) $77,641
======= ======= ======= ========= =======
</TABLE>
F-22
<PAGE> 123
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
(IN THOUSANDS OF U.S. DOLLARS)
<TABLE>
<CAPTION>
DECEMBER 31, 1996
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets............................. $ 28,722 $ -- $ 280 $ -- $ 29,002
Property and equipment (using full cost
accounting).............................. 134,996 -- -- -- 134,996
Investment in subsidiaries (equity
method).................................. -- 142,321 140,763 (283,084) --
Other assets............................... 2,505 -- 1,560 (1,558) 2,507
-------- -------- -------- --------- --------
Total assets....................... $166,223 $142,321 $142,603 $(284,642) $166,505
======== ======== ======== ========= ========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current liabilities........................ $ 16,421 $ -- $ 99 $ -- $ 16,520
Long-term liabilities...................... 7,481 1,558 -- (1,558) 7,481
Shareholders' equity....................... 142,321 140,763 142,504 (283,084) 142,504
-------- -------- -------- --------- --------
Total liabilities and shareholders'
equity........................... $166,223 $142,321 $142,603 $(284,642) $166,505
======== ======== ======== ========= ========
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1997 (UNAUDITED)
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets............................. $ 23,453 $ -- $ 387 $ -- $ 23,840
Property and equipment (using full cost
accounting).............................. 183,383 -- -- -- 183,383
Investment in subsidiaries (equity
method).................................. -- 155,174 153,630 (308,804) --
Other assets............................... 3,200 -- 1,545 (1,544) 3,201
-------- -------- -------- --------- --------
Total assets....................... $210,036 $155,174 $155,562 $(310,348) $210,424
======== ======== ======== ========= ========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current liabilities........................ $ 20,937 $ -- $ 4 $ -- $ 20,941
Long-term liabilities...................... 33,925 1,544 -- (1,544) 33,925
Shareholders' equity....................... 155,174 153,630 155,558 (308,804) 155,558
-------- -------- -------- --------- --------
Total liabilities and shareholders'
equity........................... $210,036 $155,174 $155,562 $(310,348) $210,424
======== ======== ======== ========= ========
</TABLE>
F-23
<PAGE> 124
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(IN THOUSANDS OF U.S. DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1994
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $12,714 $ -- $ 1 $ -- $12,715
Expenses................................... 10,607 -- 227 -- 10,834
------- ------- ------- -------- -------
Income (loss) before the following: 2,107 -- (226) -- 1,881
Equity in net earnings of subsidiaries... -- 1,389 1,389 (2,778) --
------- ------- ------- -------- -------
Income before income taxes................. 2,107 1,389 1,163 (2,778) 1,881
Provision for federal income taxes......... (718) -- -- -- (718)
------- ------- ------- -------- -------
Net income................................. $ 1,389 $ 1,389 $ 1,163 $ (2,778) $ 1,163
======= ======= ======= ======== =======
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $20,107 $ -- $ 460 $ (458) $20,109
Expenses................................... 19,026 -- 460 (458) 19,028
------- ------- ------ --------- -------
Income (loss) before the following: 1,081 -- -- -- 1,081
Equity in net earnings of subsidiaries... -- 714 714 (1,428) --
------- ------- ------ --------- -------
Income before income taxes................. 1,081 714 714 (1,428) 1,081
Provision for federal income taxes......... (367) -- -- -- (367)
------- ------- ------ --------- -------
Net income................................. $ 714 $ 714 $ 714 $ (1,428) $ 714
======= ======= ====== ========= =======
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $53,631 $ -- $ 179 $ (161) $53,649
Expenses................................... 38,008 -- 1,746 (161) 39,593
------- ------- ------- -------- -------
Income (loss) before the following: 15,623 -- (1,567) -- 14,056
Equity in net earnings of subsidiaries... -- 10,311 10,311 (20,622) --
------- ------- ------- -------- -------
Income before income taxes................. 15,623 10,311 8,744 (20,622) 14,056
Provision for federal income taxes......... (5,312) -- -- -- (5,312)
------- ------- ------- -------- -------
Net income................................. $10,311 $10,311 $ 8,744 $(20,622) $ 8,744
======= ======= ======= ======== =======
</TABLE>
F-24
<PAGE> 125
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(IN THOUSANDS OF U.S. DOLLARS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1996 (UNAUDITED)
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $35,130 $ -- $ 117 $ (113) $35,134
Expenses................................... 26,507 -- 1,468 (113) 27,862
------- ------- ------- --------- -------
Income (loss) before the following: 8,623 -- (1,351) -- 7,272
Equity in net earnings of subsidiaries... -- 5,691 5,691 (11,382) --
------- ------- ------- --------- -------
Income before income taxes................. 8,623 5,691 4,340 (11,382) 7,272
Provision for federal income taxes......... (2,932) -- -- -- (2,932)
------- ------- ------- --------- -------
Net income................................. $ 5,691 $ 5,691 $ 4,340 $ (11,382) $ 4,340
======= ======= ======= ========= =======
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1997 (UNAUDITED)
------------------------------------------------------------------------------
DENBURY DENBURY DENBURY
MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC.
INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED
------------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Revenues................................... $61,066 $ -- $ 105 $ (102) $61,069
Expenses................................... 44,191 -- 102 (102) 44,191
------- ------- ------- --------- -------
Income (loss) before the following: 16,875 -- 3 -- 16,878
Equity in net earnings of subsidiaries... -- 10,630 10,630 (21,260) --
------- ------- ------- --------- -------
Income before income taxes................. 16,875 10,630 10,633 (21,260) 16,878
Provision for federal income taxes......... (6,245) -- -- -- (6,245)
------- ------- ------- --------- -------
Net income................................. $10,630 $10,630 $10,633 $ (21,260) $10,633
======= ======= ======= ========= =======
</TABLE>
11. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31, 1995
and 1996 were prepared by Netherland & Sewell and the net oil and natural gas
reserve estimates as of December 31, 1994 were prepared by The Scotia Group,
Inc., both independent petroleum engineers located in Dallas, Texas. The
reserves were prepared in accordance with guidelines established by the
Securities and Exchange Commission and accordingly, were based on existing
economic and operating conditions. Oil and natural gas prices in effect as of
the reserve report date were used without any escalation except in those
instances where the sale is covered by contract, in which case the applicable
contract prices including fixed and determinable escalations were used for the
duration of the contract, and thereafter the last contract price was used.
Operating costs, production and ad valorem taxes and future development costs
were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in the United States.
F-25
<PAGE> 126
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ESTIMATED QUANTITIES OF RESERVES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1994 1995 1996
--------------- --------------- ---------------
OIL GAS OIL GAS OIL GAS
(Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) (MMcf)
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Balance beginning of year............... 3,583 13,029 4,230 42,047 6,292 48,116
Revisions of previous estimates....... (48) 2,827 830 (1,620) (490) 3,737
Revisions due to price changes........ -- -- -- -- 1,053 402
Extensions, discoveries and other
additions.......................... 640 14,978 732 -- 3,492 5,480
Production............................ (489) (3,326) (728) (4,844) (1,500) (8,933)
Acquisition of minerals in place...... 544 14,539 1,228 12,533 6,205 25,300
----- ------ ----- ------ ------ ------
Balance at end of period................ 4,230 42,047 6,292 48,116 15,052 74,102
===== ====== ===== ====== ====== ======
Proved developed reserves:
Balance at beginning of year.......... 3,418 12,303 3,755 35,578 5,290 34,894
Balance at end of period.............. 3,755 35,578 5,290 34,894 13,371 58,634
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND NATURAL GAS RESERVES
The Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure")
does not purport to present the fair market value of the Company's oil and
natural gas properties. An estimate of such value should consider, among other
factors, anticipated future prices of oil and natural gas, the probability of
recoveries in excess of existing proved reserves, the value of probable reserves
and acreage prospects, and perhaps different discount rates. It should be noted
that estimates of reserve quantities, especially from new discoveries, are
inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices, adjusted for fixed and determinable escalations, to
the estimated future production of year-end proved reserves. Future cash inflows
were reduced by estimated future production and development costs based on
year-end costs to determine pre-tax cash inflows. Future income taxes were
computed by applying the statutory tax rate to the excess of pre-tax cash
inflows over the Company's tax basis in the associated proved oil and natural
gas properties. Tax credits and net operating loss carry forwards were also
considered in the future income tax calculation. Future net cash inflows after
income taxes were discounted using a 10% annual discount rate to arrive at the
Standardized Measure.
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1994 1995 1996
-------- -------- ---------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows................................. $126,129 $214,932 $ 627,476
Future production costs............................. (35,069) (56,323) (134,986)
Future development costs............................ (7,369) (16,154) (28,722)
-------- -------- ---------
Future net cash flows before taxes.................. 83,691 142,455 463,768
10% annual discount for estimated timing of cash
flows.......................................... (31,000) (45,490) (147,670)
-------- -------- ---------
Discounted future net cash flows before taxes....... 52,691 96,965 316,098
Discounted future income taxes...................... (5,763) (15,801) (74,226)
-------- -------- ---------
Standardized measure of discounted future net
cash.............................................. $ 46,928 $ 81,164 $ 241,872
======== ======== =========
</TABLE>
F-26
<PAGE> 127
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1995 1996
------- -------- --------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Beginning of year..................................... $28,465 $ 46,928 $ 81,164
Sales of oil and natural gas produced, net of
production costs.................................... (8,383) (13,243) (39,385)
Net changes in sales prices........................... 863 23,037 116,587
Extensions and discoveries, less applicable future
development and production costs.................... 13,416 1,926 34,113
Previously estimated development costs incurred....... 2,492 2,193 5,278
Revisions of previous estimates, including revised
estimates of development costs, reserves and rates
of production....................................... (2,914) 3,958 7,747
Accretion of discount................................. 2,847 4,693 8,116
Purchase of minerals in place......................... 15,732 21,710 86,677
Net change in income taxes............................ (5,590) (10,038) (58,425)
------- -------- --------
End of period......................................... $46,928 $ 81,164 $241,872
======= ======== ========
</TABLE>
12. SUBSEQUENT EVENTS (UNAUDITED)
On December 30, 1997, Denbury acquired producing oil and natural gas
properties in Mississippi, for approximately $202 million (the "Chevron
Acquisition"). The acquisition included 122 wells, of which 96 wells will be
Company operated. The Company funded this acquisition with bank financing from a
revised and restated credit facility.
This acquisition was accounted for under purchase accounting and the
results of operations will be consolidated effective December 31, 1997. Pro
forma results of operations of the Company as if the Chevron Acquisition had
occurred at the beginning of each respective period are as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED SEPTEMBER 30,
DECEMBER 31, ----------------------
1996 1996 1997
-------------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Revenues........................................... $77,311 $52,534 $75,103
Net income......................................... 4,909 1,181 6,886
Net income per common share........................ 0.37 0.10 0.34
</TABLE>
In computing the pro forma results, depreciation, depletion and
amortization expense was computed using the units of production method, and an
adjustment was made to interest expense reflecting the bank debt that was
required to fund the acquisitions. The pro forma results reflect an increase of
$687,000, $514,000 and $514,000 for 1996 and the nine months ended September 30,
1996 and 1997, respectively, in general and administrative expense for
additional personnel and associated costs relating to the acquired properties,
net of anticipated allocations to operations and capitalization of exploration
costs.
F-27
<PAGE> 128
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following represents the revenues and direct operating expenses
attributable to the net interest acquired in the Chevron Acquisition by the
Company and are presented on the full cost accrual basis of accounting.
Depreciation, depletion, and amortization, allocated general and administrative
expenses, interest expense and income, and income taxes have been excluded
because the property interests acquired represent only a portion of a business
and these expenses are not necessarily indicative of the expenses to be incurred
by the Company.
<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS
DECEMBER 31, ENDED
----------------- SEPTEMBER 30,
1995 1996 1997
------- ------- -------------
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product............... $17,460 $23,662 $14,034
Direct operating expenses:
Lease operating expense............................ 5,825 6,650 5,237
------- ------- -------
Excess of revenues over direct operating expenses.... $11,635 $17,012 $ 8,797
======= ======= =======
</TABLE>
The Company made two amendments to its credit facility during 1997. In
April, 1997, the Company amended its bank credit facility (i) to extend the
revolver by one year to May 31, 1999, (ii) to extend the termination date by one
year to May 31, 2002, and (iii) to reduce the commitment fee percentages.
In October, 1997, the Company further amended its bank credit facility to
(i) modify the security requirement of the facility such that mortgages will
only be required by the banks to the extent that they were in place as of the
date of the amendment and (ii) to modify certain other definitions and minor
provisions of the agreement.
In order to fund the Chevron Acquisition, the Company revised and restated
its credit facility (the "Credit Facility") with NationsBank of Texas, as agent,
("NationsBank") a group of banks and increased the size of the facility from
$150 million to $300 million. This restatement was made during the fourth
quarter of 1997, with an adjusted borrowing base as of December 31, 1997 of $260
million of which $20 million was available. The Credit Facility includes a five
year revolving credit facility of $165 million, unless renewed or extended, plus
an Acquisition Tranche of $95 million. Unless the acquisition tranche is repaid,
the interest rate on the total loan escalates 0.25% each quarter beginning March
1, 1998 through March 31, 1999. Upon repayment of the acquisition tranche, the
interest rate reverts back to the LIBOR margins applicable to borrowings where
borrowings under the Acquisition Tranche are not outstanding.
On August 6, 1997, the Company entered into a ten year office lease for its
corporate headquarters which is expected to commence late in 1998. The estimated
minimum annual rental payments for the first five years of the lease are
projected to be $1.15 million per year (commencing on occupancy) and the minimum
annual rental payments during the remaining five years of the lease are
projected to be $1.25 million per year.
F-28
<PAGE> 129
DENBURY RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 1995 and 1996 and the first three quarters of 1997 (in
thousands except per share amounts).
<TABLE>
<CAPTION>
1995
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Revenues.................................. $ 4,381 $ 4,636 $ 4,841 $ 6,251
Expenses.................................. 3,723 4,583 4,554 6,168
Net income................................ 435 35 190 54
Net income per share (primary)............ 0.08 0.00 0.02 0.00
Cash flow from operations(a).............. 2,112 1,913 2,234 3,135
</TABLE>
<TABLE>
<CAPTION>
1996
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Revenues.................................. $ 9,092 $11,682 $14,359 $18,516
Expenses.................................. 6,767 9,608 11,486 11,732
Net income................................ 1,380 1,215 1,745 4,404
Net income per share (primary)(b)......... 0.12 0.11 0.14 0.25
Cash flow from operations(a).............. 6,065 7,238 8,464 12,373
</TABLE>
<TABLE>
<CAPTION>
1997
---------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30
-------- ------- ------------
<S> <C> <C> <C> <C>
Revenues.................................. $21,653 $19,015 $20,401
Expenses.................................. 13,375 15,512 15,304
Net income................................ 5,215 2,207 3,211
Net income per share (primary)............ 0.26 0.11 0.16
Cash flow from operations(a).............. 14,922 12,001 13,243
</TABLE>
- ---------------
(a) Exclusive of the net change in non-cash working capital balances.
(b) Due to the significant variances between quarters in net income and average
shares outstanding, the combined quarterly income per share does not equal
the reported earnings per share for 1996.
F-29
<PAGE> 130
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
of Denbury Resources Inc.
We have audited the accompanying statement of revenues and direct operating
expenses of Chevron U.S.A. Inc.'s working interest in the Heidelberg Fields (the
"Properties") acquired by Denbury Resources Inc. (the "Company") for each of the
two years in the period ended December 31, 1996 and for the nine months ended
September 30, 1997. This statement is the responsibility of the Company's
management. Our responsibility is to express an opinion on this statement based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of revenues and direct
operating expenses is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statement of revenues and direct operating expenses. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the statement of
revenues and direct operating expenses. We believe that our audit provides a
reasonable basis for our opinion.
The accompanying statement of revenues and direct operating expenses was
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission (for inclusion in the registration statement
on Form S-3 of Denbury Resources Inc.) as described in Note 1 and is not
intended to be a complete presentation of the Properties' revenues and expenses.
In our opinion, the statement of revenues and direct operating expenses
referred to above presents fairly, in all material respects, the revenues and
direct operating expenses of the Properties described in Note 1 for each of the
two years in the period ended December 31, 1996 and for the nine months ended
September 30, 1997, in conformity with generally accepted accounting principles.
Price Waterhouse LLP
San Francisco, California
December 19, 1997
F-30
<PAGE> 131
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF PROPERTIES
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, NINE MONTHS ENDED
------------------ SEPTEMBER 30,
1995 1996 1997
------- ------- -----------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil, natural gas and related product sales......... $17,460 $23,662 $14,034
Direct operating expenses:
Lease operating expense............................ 5,825 6,650 5,237
------- ------- -------
Excess of revenues over direct operating expense..... $11,635 $17,012 $ 8,797
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these statements.
F-31
<PAGE> 132
NOTES TO STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF PROPERTIES
1. BASIS OF PRESENTATION
Denbury Resources Inc. (the "Company") agreed on November 25, 1997 to
acquire Chevron U.S.A. Inc.'s working interest in the Heidelberg Fields for
approximately $202 million. The Properties are located in the state of
Mississippi. The acquisition is expected to close in December 1997. These
acquired Properties will be consolidated in the Company's financial statements
effective January 1, 1998. Other owners of working interests in the Properties
covered by the acquisition agreement have the preferential right to acquire the
Properties, which if exercised could reduce the interest acquired by the
Company.
Historical financial statements reflecting financial position, results of
operations and cash flows required by generally accepted accounting principles
are not presented, as such information is neither readily available on an
individual property basis nor meaningful for the Properties acquired because the
entire acquisition cost is being assigned to oil and natural gas properties.
Accordingly, the statement of revenues and direct operating expenses is
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X.
The accompanying statement of revenues and direct operating expenses (the
"Statement") relates only to the working interest in the Properties acquired and
may not be representative of future operations. The Statement includes revenues
from natural gas sales and direct operating expenses for each of the periods
presented. The Statement does not include federal and state income taxes,
interest, depletion, depreciation and amortization or general and administrative
expenses because such amounts would not be indicative of those expenses which
would be incurred by the Company.
Revenues in the Statement are recognized on the entitlement method.
The accompanying Statement has been prepared on the accrual basis in
accordance with generally accepted accounting principles. Preparation of the
Statement in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts reported in
the Statement and accompanying notes. Actual results could differ from those
estimates.
2. COMMITMENTS AND CONTINGENCIES
Chevron U.S.A. Inc. is a defendant in numerous lawsuits, including, along
with other oil companies, actions challenging oil royalty and severance tax
payments based on posted prices. Plaintiffs may seek to recover large and
sometimes unspecified amounts, and some matters may remain unresolved for
several years. The amount of such future cost is indeterminable. Such liability
for events occurring prior to the effective date of the acquisition shall be
retained by Chevron U.S.A. Inc. and Chevron U.S.A. Inc. has indemnified the
Company for any costs incurred by it in conjunction with these suits.
Given the nature of the Properties acquired and as stipulated in the
purchase agreement, the Company is subject to loss contingencies, if any,
pursuant to existing or expected environmental laws, regulations, and leases
covering the acquired Properties. Management does not believe such matters will
have a material impact on the Statement.
3. CONCENTRATION OF CUSTOMERS
During the year ended December 31, 1996 and the nine months ended September
30, 1997, approximately 67% and 31% of the Properties' production was sold to
Hunt Refining Company and Southland Oil Company, respectively. During the year
ended December 31, 1995, approximately 88% and 10% of the Properties' production
was sold to Amerada Hess Corporation and Hunt Refining Company, respectively.
While management believes that its relationships with these purchasers is good,
any loss of revenue from these purchasers due to nonpayment or late payment by
the purchaser would have an adverse effect on the Statement.
F-32
<PAGE> 133
NOTES TO STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF PROPERTIES -- (CONTINUED)
4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED)
The Properties' proved oil and natural gas reserves at December 31, 1997,
1996 and 1995 have been estimated by the Company's petroleum consultants,
Netherland & Sewell, in accordance with guidelines established by the Securities
and Exchange Commission ("SEC"). The December 31, 1997 reserves have been
adjusted by production from the Properties to estimate the September 30, 1997
reserves.
<TABLE>
<CAPTION>
OIL GAS
ESTIMATED QUANTITIES OF PROVED RESERVES (MBbl) (MMCF)
--------------------------------------- -------- -------
<S> <C> <C>
January 1, 1995............................................. 31,331.1 3,303.7
Production................................................ 1,321.5 290.6
-------- -------
December 31, 1995........................................... 30,009.6 3,013.1
Production................................................ 1,252.0 245.1
-------- -------
December 31, 1996........................................... 28,757.6 2,768.0
Production................................................ 793.6 160.1
-------- -------
September 30, 1997.......................................... 27,964.0 2,607.9
======== =======
Proved Developed Reserves:
As of January 1, 1995..................................... 17,230.8 3,303.7
As of December 31, 1995................................... 15,909.3 3,013.1
As of December 31, 1996................................... 14,657.3 2,768.0
As of September 30, 1997.................................. 13,863.7 2,607.9
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATED TO OIL AND NATURAL GAS RESERVES
The standardized measure of discounted future net cash flows ("Standardized
Measure") relating to oil and natural gas reserves acquired is calculated in
accordance with regulations prescribed by the SEC. The Standardized Measure has
been prepared assuming year-end selling prices adjusted for future fixed and
determinable price changes, year-end development and production costs and a 10%
annual discount rate. The reserves and the related Standardized Measure at
September 30, 1997 were adjusted for production during the nine-months ended
September 30, 1997 and the years ended December 31, 1996 and 1995, and in
addition, Standardized Measure was also adjusted for price changes to derive
reserves and the Standardized Measure as of September 30, 1997, December 31,
1996 and December 31, 1995. The Standardized Measure is not a fair market value
of the mineral interests purchased and the Standardized Measure presented for
the proved oil and natural gas reserves does not purport to present the fair
market value of the oil and natural gas properties. An estimate of such value
should consider, among other factors, anticipated future prices of oil and
natural gas, the probability of recoveries of existing proved reserves, the
value of probable reserves and acreage prospects, and perhaps different discount
rates. It should be noted that estimates of reserve quantities are inherently
imprecise and subject to substantial revision.
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------- SEPTEMBER 30,
1995 1996 1997
--------- --------- -------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows............................ $ 470,689 $ 613,780 $ 426,489
Future production and development costs........ (201,520) (204,876) (189,243)
--------- --------- ---------
Future net cash flows undiscounted............. 269,169 408,904 237,246
10% annual discount for estimated timing of
cash flows................................... (142,503) (203,206) (113,931)
--------- --------- ---------
Standardized measure of discounted future net
cash flows................................... $ 126,666 $ 205,698 $ 123,315
========= ========= =========
</TABLE>
F-33
<PAGE> 134
NOTES TO STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES OF PROPERTIES -- (CONTINUED)
The following are principal sources of changes in the standardized measure
of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS
DECEMBER 31, ENDED
-------------------- SEPTEMBER 30,
1995 1996 1997
-------- -------- -------------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure of discounted future net
cash flows at beginning of period.............. $ 97,753 $126,666 $205,698
Changes resulting from:
Net change in prices........................... 30,772 83,377 (89,014)
Sales of oil and natural gas produced.......... (11,635) (17,012) (8,797)
Accretion of discount.......................... 9,776 12,667 15,428
-------- -------- --------
Standardized measure of discounted future net
cash flows at end of period.................... $126,666 $205,698 $123,315
======== ======== ========
</TABLE>
F-34
<PAGE> 135
[NSAI LETTERHEAD]
January 13, 1998
Mr. William E. Gross
Denbury Management, Inc.
17304 Preston Road, Suite 200
Dallas, Texas 75252
Dear Mr. Gross:
In accordance with your request, we have estimated the proved and probable
reserves and future revenue, as of December 31, 1997, to the Denbury Management,
Inc. (DMI) interest in certain oil and gas properties located in Louisiana,
Mississippi, Ohio, and Texas as listed in the accompanying tabulations. These
properties include those in the East Heidelberg and West Heidelberg Fields
acquired from Chevron U.S.A. Inc. (CUSA) effective December 31, 1997. For the
purposes of this report, all DMI properties except those acquired from CUSA are
referred to as the Corporate Properties. This report has been prepared using
constant prices and costs as set forth in this letter. For the proved reserves,
this report conforms to the guidelines of the Securities and Exchange Commission
(SEC). However, inasmuch as the SEC does not recognize probable reserves, the
sections of this report dealing with such reserves should not be used in filings
with the SEC.
As presented in the accompanying summary projections, Tables I through V,
we estimate the net reserves and future net revenue to the DMI interest, as of
December 31, 1997, to be:
<TABLE>
<CAPTION>
NET RESERVES FUTURE NET REVENUE
----------------------- ----------------------------
OIL GAS PRESENT WORTH
CATEGORY (BARRELS) (MCF) TOTAL AT 10%
-------- ---------- ---------- ------------ -------------
<S> <C> <C> <C> <C>
Proved Developed
Producing....................... 20,495,088 32,925,654 $240,589,400 $182,575,200
Non-Producing................... 10,860,120 36,879,723 174,904,500 93,904,400
Proved Undeveloped................ 20,663,028 7,385,636 187,968,700 84,849,000
---------- ---------- ------------ ------------
Total Proved............ 52,018,236 77,191,013 $603,462,600 $361,328,600
</TABLE>
The oil reserves shown include crude oil, condensate, and gas plant
liquids. Oil volumes are expressed in barrels which are equivalent to 42 United
States gallons. Gas volumes are expressed in thousands of standard cubic feet
(MCF) at the contract temperature and pressure bases.
As shown in the Table of Contents, this report is divided into sections for
Corporate Properties and Chevron Acquisition Properties. Each section includes
summary projections of reserves and revenue for each reserve category and by
reserve category for each state along with one-line summaries of reserves,
economics, and basic data by lease. Supplemental data summaries are also
included by reserve category for each state. For the purposes of this report,
the term "lease" refers to a single economic projection.
[NSAI LETTERHEAD FOOTER]
A-1
<PAGE> 136
The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, proved undeveloped,
and probable reserves. No study was made to determine whether possible reserves
might be established for these properties. This report does not include any
value which could be attributed to interests in undeveloped acreage beyond those
tracts for which undeveloped reserves have been estimated.
Future gross revenue to the DMI interest is prior to deducting state
production taxes and ad valorem taxes. Future net revenue is after deducting
these taxes, future capital costs, and operating expenses, but before
consideration of federal income taxes. In accordance with SEC guidelines, the
future net revenue has been discounted at an annual rate of 10 percent to
determine its "present worth." The present worth is shown to indicate the effect
of time on the value of money and should not be construed as being the fair
market value of the properties.
For the purposes of this report, a field inspection of the properties has
not been performed nor has the mechanical operation or condition of the wells
and their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability.
Also, our estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.
Oil prices used in this report are based on a December 1997 average Koch
West Texas Intermediate posted price of $16.18 per barrel, adjusted by lease for
gravity, transportation fees, and regional posted price differentials. The
natural gas liquids price used for Gibson Field, Louisiana, is $12.26 per
barrel. Gas prices used in this report are based on a December 1997 NYMEX Henry
Hub Natural Gas Contract settlement price of $2.58 per MMBTU, adjusted by lease
for transportation fees, BTU content, and regional price differentials. Oil,
natural gas liquids, and gas prices are held constant in accordance with SEC
guidelines.
Lease and well operating costs are based on operating expense records of
DMI and CUSA. For non-operated properties, these costs include the per-well
overhead expenses allowed under joint operating agreements along with costs
estimated to be incurred at and below the district and field levels. As
requested, lease and well operating costs for the operated properties include
only direct lease and field level costs. Headquarters general and administrative
overhead expenses of DMI are not included. Lease and well operating costs are
held constant in accordance with SEC guidelines. Capital costs are included as
required for workovers, new development wells, and production equipment.
We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the DMI interest.
Therefore, our estimates of reserves and future revenue do not include
adjustments for the settlement of any such imbalances; our projections are based
on DMI receiving its net revenue interest share of estimated future gross gas
production.
The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the revenues therefrom and the costs related thereto could be more or less than
the estimated amounts. A substantial portion of these reserves are for
behind-pipe zones, undeveloped locations, and producing wells that lack
sufficient production history upon which performance-related estimates of
reserves can be based. Therefore, these reserves are based on estimates of
reservoir volumes and recovery efficiencies along with analogies to similar
production. As such reserve estimates are usually subject to greater revision
than those based on substantial production and pressure data, it may be
necessary to revise these estimates up or down in the future as additional
performance data become available. The sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may vary from
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.
In evaluating the information at our disposal concerning this report, we
have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgments.
A-2
<PAGE> 137
The titles to the properties have not been examined by Netherland, Sewell &
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Denbury Management, Inc.; Chevron U.S.A. Inc.; other interest owners; various
operators of the properties; and the nonconfidential files of Netherland, Sewell
& Associates, Inc. and were accepted as accurate. We are independent petroleum
engineers, geologists, and geophysicists; we do not own an interest in these
properties and are not employed on a contingent basis. Basic geologic and field
performance data together with our engineering work sheets are maintained on
file in our office.
Very truly yours,
/s/ FREDERIC D. SEWELL
DMA:EIB
A-3
<PAGE> 138
DMI LOGO
