UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
--------------------------------
(Mark One)
X Quarterly report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the quarterly period ended June 30, 2002
Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Commission file number 1-12935
----------------------------------------
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 75-2815171
(State or other jurisdictions of (I.R.S. Employer
incorporation or organization) Identification No.)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at July 31, 2002
----- ----------------------------
Common Stock, $.001 par value 53,338,471
DENBURY RESOURCES INC.
INDEX
Page
Part I. Financial Information
- ------------------------------
Item 1. Financial Statements
Independent Accountants' Report 3
Condensed Consolidated Balance Sheets at June 30, 2002 (Unaudited)
and December 31, 2001 4
Condensed Consolidated Statements of Operations for the Three and Six Months
Ended June 30, 2002 and 2001 (Unaudited) 5
Condensed Consolidated Statements of Cash Flows for the Six Months
Ended June 30, 2002 and 2001 (Unaudited) 6
Notes to Condensed Consolidated Financial Statements 7-18
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 19-34
Item 3. Quantitative and Qualitative Disclosures about Market Risk 34
Part II. Other Information
---------------------------
Item 4. Submission of Matters to a Vote of Security Holders 34
Item 6. Exhibits and Reports on Form 8-K 35
Signatures 36
Part I. Financial Information
Item 1. Financial Statements
- -----------------------------
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Directors of Denbury Resources Inc.:
We have reviewed the accompanying condensed consolidated balance sheet of
Denbury Resources Inc. and subsidiaries (the "Company") as of June 30, 2002, and
the related condensed consolidated statements of operations for the three and
six month periods ended June 30, 2002 and 2001 and cash flows for the six month
periods ended June 30, 2002 and 2001. These financial statements are the
responsibility of the Company's management.
We conducted our reviews in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and of making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted in
accordance with auditing standards generally accepted in the United States of
America, the objective of which is the expression of an opinion regarding the
financial statements taken as a whole. Accordingly, we do not express such an
opinion.
Based on our reviews, we are not aware of any material modifications that should
be made to such condensed consolidated financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of
Denbury Resources Inc. and subsidiaries as of December 31, 2001 and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year then ended (not presented herein); and in our report dated February 25,
2002, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
condensed consolidated balance sheet as of December 31, 2001 is fairly stated,
in all material respects, in relation to the consolidated balance sheet from
which it has been derived.
/s/ Deloitte & Touche LLP
Dallas, Texas
August 7, 2002
3
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
June 30, December 31,
2002 2001
---------------- ---------------
(Unaudited)
Assets
Current assets
Cash and cash equivalents $ 20,175 $ 23,496
Accrued production receivables 29,006 22,823
Trade and other receivables 13,779 32,512
Derivative assets 628 23,458
Deferred tax asset 15,134 989
------------ -----------
Total current assets 78,722 103,278
------------ -----------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,142,504 1,098,263
Unevaluated 48,767 44,521
CO2 properties and equipment 51,858 45,555
Less accumulated depletion and depreciation (565,071) (520,332)
------------ -----------
Net property and equipment 678,058 668,007
------------ -----------
Investment in Genesis Energy, Inc. 2,060 -
Other assets 21,512 18,703
------------ -----------
Total assets $ 780,352 $ 789,988
============ ===========
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 33,224 $ 66,491
Oil and gas production payable 13,409 13,447
Derivative liabilities 7,543 -
------------ -----------
Total current liabilities 54,176 79,938
------------ -----------
Long-term liabilities
Long-term debt 330,394 334,769
Provision for site reclamation costs 5,666 4,318
Derivative liabilities 5,452 -
Deferred tax liability 30,265 18,422
Other 3,381 3,373
------------ -----------
Total long-term liabilities 375,158 360,882
------------ -----------
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding - -
Common stock, $.001 par value, 100,000,000 shares authorized;
53,337,376 and 52,956,825 shares issued and outstanding at June 30,
2002 and December 31, 2001, respectively 53 53
Paid-in capital in excess of par 394,079 391,557
Accumulated deficit (38,626) (56,670)
Accumulated other comprehensive income (loss) (4,488) 14,228
------------ -----------
Total stockholders' equity 351,018 349,168
------------ -----------
Total liabilities and stockholders' equity $ 780,352 $ 789,988
============ ===========
(See accompanying notes to Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- -------------------------
2002 2001 2002 2001
------------- ------------- ------------ ------------
Revenues
Oil, natural gas and related product sales $ 71,114 $ 65,123 $ 122,024 $ 143,438
CO2 sales 1,896 1,424 3,386 2,283
Gain on settlements of derivative contracts 12 618 2,648 618
Interest and other income 411 242 822 248
------------- ------------- ------------ ------------
Total revenues 73,433 67,407 128,880 146,587
------------- ------------- ------------ ------------
Expenses
Lease operating costs 17,124 12,417 32,552 24,887
Production taxes and marketing expenses 3,297 2,532 5,911 5,140
CO2 operating costs 362 277 529 335
General and administrative 2,933 2,004 5,782 4,405
Interest 6,572 4,582 13,226 9,245
Depletion and depreciation 24,205 12,648 47,131 24,993
Amortization of derivative contracts and other
non-cash hedging adjustments (1,012) 724 (2,093) 3,864
Franchise taxes 361 300 728 575
------------- ------------- ------------ ------------
Total expenses 53,842 35,484 103,766 73,444
------------- ------------- ------------ ------------
Equity in net income of Genesis Energy, Inc. 20 - 20 -
------------- ------------- ------------ ------------
Income before income taxes 19,611 31,923 25,134 73,143
Income tax provision (benefit)
Current income taxes 33 400 (448) 2,400
Deferred income taxes 6,080 11,412 7,538 24,663
------------- ------------- ------------ ------------
Net income $ 13,498 $ 20,111 $ 18,044 $ 46,080
============= ============= ============ ============
Net income per common share
Basic $ 0.25 $ 0.44 $ 0.34 $ 1.00
Diluted 0.25 0.42 0.33 0.97
Weighted average common shares outstanding
Basic 53,158 46,132 53,077 46,072
Diluted 54,301 47,322 54,024 47,262
(See accompanying notes to Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
(Unaudited)
Six Months Ended
June 30,
----------------------------------
2002 2001
------------- ------------
Cash flow from operating activities:
Net income $ 18,044 $ 46,080
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 47,131 24,993
Amortization of derivative contracts and other non-cash hedging
adjustments (2,093) 3,865
Deferred income taxes 7,538 24,663
Amortization of debt issue costs and other 1,327 575
------------- ------------
71,947 100,176
Changes in assets and liabilities:
Accrued production receivable (6,183) 9,303
Trade and other receivables 20,105 (15,031)
Derivative assets and liabilities 7,836 (17,967)
Other assets (1,582) -
Accounts payable and accrued liabilities (33,267) 18,637
Oil and gas production payable (38) 1,857
Other liabilities (214) -
------------- ------------
Net cash provided by operations 58,604 96,975
------------- ------------
Cash flow used for investing activities:
Oil and natural gas expenditures (49,650) (70,469)
Acquisitions of oil and gas properties (2,268) (1,755)
Investment in Genesis Energy, Inc. (2,040) -
Acquisitions of CO2 assets and capital expenditures (5,934) (42,001)
Increase in restricted cash (3,543) (187)
Proceeds from disposition of oil and natural gas properties 4,552 -
Net purchases of other assets (315) (870)
------------- ------------
Net cash used for investing activities (59,198) (115,282)
------------- ------------
Cash flow from financing activities:
Bank repayments (10,000) (13,130)
Bank borrowings 5,130 31,000
Issuance of common stock 2,143 1,605
Costs of debt financing - (125)
------------- ------------
Net cash provided by (used for) financing activities (2,727) 19,350
------------- ------------
Net increase (decrease) in cash and cash equivalents (3,321) 1,043
Cash and cash equivalents at beginning of period 23,496 22,293
------------- ------------
Cash and cash equivalents at end of period $ 20,175 $ 23,336
============= ============
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 12,120 $ 8,011
Cash paid (refunded) during the period for income taxes (1,305) 1,704
(See accompanying notes to Condensed Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Interim Financial Statements
The accompanying condensed consolidated financial statements of Denbury
Resources Inc. (the "Company" or "Denbury") have been prepared in accordance
with generally accepted accounting principles and pursuant to the rules and
regulations of the Securities and Exchange Commission ("SEC"). These financial
statements and the notes thereto should be read in conjunction with the
Company's annual report on Form 10-K for the year ended December 31, 2001. Any
capitalized terms used but not defined in these Notes to Condensed Consolidated
Financial Statements have the same meaning given to them in the Form 10-K.
The financial data for the three and six month periods ended June 30, 2002
and 2001, included herein, have been subjected to a limited review by Deloitte &
Touche LLP, Denbury's independent accountants. Accounting measurements at
interim dates inherently involve greater reliance on estimates than at year end
and the results of operations for the interim periods shown in this report are
not necessarily indicative of results to be expected for the fiscal year. In the
opinion of management of Denbury, the accompanying unaudited condensed
consolidated financial statements include all adjustments (of a normal recurring
nature) necessary to present fairly the consolidated financial position of the
Company as of June 30, 2002 and the consolidated results of its operations for
the three and six months ended June 30, 2002 and 2001 and its cash flows for the
six months ended June 30, 2002 and 2001. Certain prior period items have been
reclassified to make the classification consistent with this quarter.
On May 14, 2002, a subsidiary of the Company acquired Genesis Energy, Inc.,
the general partner of Genesis Energy, L.P., a publicly traded master limited
partnership engaged in crude oil gathering, marketing and transportation. The
Company is accounting for its ownership and interest in Genesis Energy, L.P.
under the equity method of accounting. See Note 6, "Acquisition of Genesis
Energy, L.L.C.," for further data regarding this acquisition and summary
financial information for Genesis.
Net Income per Common Share
Basic net income per common share is computed by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
Diluted net income per common share is calculated in the same manner but also
considers the impact on net income and common shares for the potential dilution
from stock options and any other convertible securities outstanding. For the
three and six month periods ended June 30, 2002 and 2001, there were no
adjustments to net income for purposes of calculating diluted net income per
common share. The following is a reconciliation of the weighted average common
shares used in the basic and diluted net income per common share calculations
for the three and six month periods ended June 30, 2002 and 2001(shares in
thousands).
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------ ----------------------------
2002 2001 2002 2001
-------------- -------------- ------------- ------------
Weighted average common shares - basic 53,158 46,132 53,077 46,072
Potentially dilutive securities:
Stock options 1,143 1,190 947 1,190
-------------- -------------- ------------- ------------
Weighted average common shares - diluted 54,301 47,322 54,024 47,262
============== ============== ============= ============
7
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 2002, additional options
outstanding to purchase 1.7 million and 2.3 million shares of common stock,
respectively, were excluded from the diluted net income per common share
calculations as the exercise prices of these options exceeded the average market
price of the Company's common stock during these periods. For the three and six
months ended June 30, 2001, additional options outstanding to purchase 1.3
million shares of common stock were excluded from the diluted net income per
common share calculations as the exercise prices of these options exceeded the
average market price of the Company's common stock during these periods.
Recently Issued Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 143, ("SFAS No. 143"),
"Accounting for Asset Retirement Obligations." SFAS No. 143 requires that the
fair value of a liability for an asset retirement obligation be recorded in the
period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability is
accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is
recognized. The standard is effective for the Company beginning in 2003, but
earlier adoption is encouraged. Adoption of the standard will result in
recording a cumulative effect of a change in accounting principle in the period
of adoption. The Company has not yet determined the impact of this new standard.
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 144, ("SFAS No. 144"), "Accounting for the Impairment or Disposal of
Long-Lived Assets." SFAS No. 144 supersedes SFAS No. 121 but retains its
fundamental provisions for the (a) recognition/measurement of impairment of
long-lived assets to be held and used and (b) measurement of long-lived assets
to be disposed of by sale. SFAS No. 144 also supersedes other pronouncements
which currently do not affect the Company. SFAS No. 144 was effective for the
Company beginning January 1, 2002 and has not had any impact on the Company's
financial statements.
In June 2002, the FASB issued Statement of Financial Accounting Standards
No. 146, ("SFAS No. 146"), "Accounting for Costs Associated with Exit or
Disposal Activities." SFAS No. 146 requires companies to recognize costs
associated with exit or disposal activities when they are incurred rather than
at the date of a commitment to an exit or disposal plan. SFAS No. 146 supersedes
EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)." SFAS No. 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. The Company has not yet
determined the impact of this new standard.
2. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
June 30, December 31,
2002 2001
--------------- ---------------
(Amounts in thousands)
(Unaudited)
Senior bank loan $ 136,000 $ 140,870
9% Senior Subordinated Notes Due 2008 125,000 125,000
9% Series B Senior Subordinated Notes Due 2008 75,000 75,000
Discount on 9% Series B Senior Subordinated Notes Due 2008 (5,606) (6,101)
--------------- ---------------
Total long-term debt $ 330,394 $ 334,769
=============== ===============
The Company's bank credit facility provides for a semi-annual
redetermination of the borrowing base on April 1st and October 1st. At the April
1, 2002 redetermination, the Company's borrowing base was reaffirmed at $220
million, leaving the Company with a borrowing capacity on its bank credit line
of approximately $84 million as of June 30, 2002.
8
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3. COMPREHENSIVE INCOME
The following tables present comprehensive income for the three and six months ended June 30, 2002.
Three Months Ended
(Amounts in thousands) June 30, 2002
-----------------------------------
Accumulated other comprehensive income - March 31, 2002 $ (1,919)
Net income $ 13,498
Other comprehensive income - net of tax
Reclassification adjustments related to derivative contracts (2,245)
Amortization of derivative contracts 1,607
Change in fair value of outstanding hedging positions (1,931)
---------------
Total other comprehensive income (2,569) (2,569)
--------------- --------------
Comprehensive income $ 10,929
===============
Accumulated other comprehensive income - June 30, 2002 $ (4,488)
==============
Six Months Ended
(Amounts in thousands) June 30, 2002
-----------------------------------
Accumulated other comprehensive income - December 31, 2001 $ 14,228
Net income $ 18,044
Other comprehensive income - net of tax
Reclassification adjustments related to derivative contracts (4,546)
Amortization of derivative contracts 3,227
Change in fair value of outstanding hedging positions (17,397)
---------------
Total other comprehensive income (18,716) (18,716)
--------------- --------------
Comprehensive income $ (672)
===============
Accumulated other comprehensive income - June 30, 2002 $ (4,488)
==============
9
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following tables present comprehensive income for the three and six months ended June 30, 2001.
Three Months Ended
(Amounts in thousands) June 30, 2001
-----------------------------------
Accumulated other comprehensive income - March 31, 2001 $ 390
Net income $ 20,111
Other comprehensive income - net of tax
Reclassification adjustments related to derivative contracts (234)
Change in fair value of outstanding hedging positions 9,613
---------------
Total other comprehensive income 9,379 9,379
--------------- --------------
Comprehensive income $ 29,490
===============
Accumulated other comprehensive income - June 30, 2001 $ 9,769
==============
Six Months Ended
(Amounts in thousands) June 30, 2001
-----------------------------------
Accumulated other comprehensive income - December 31, 2000 $ -
Net income $ 46,080
Other comprehensive income - net of tax
Cumulative effect of change in accounting principle - January 1, 2001 1,012
Reclassification adjustments related to derivative contracts (856)
Change in fair value of outstanding hedging positions 9,613
---------------
Total other comprehensive income 9,769 9,769
--------------- --------------
Comprehensive income $ 55,849
===============
Accumulated other comprehensive income - June 30, 2001 $ 9,769
==============
4. PRODUCT PRICE HEDGING CONTRACTS
The Company enters into various financial contracts to hedge its exposure
to commodity price risk associated with anticipated future oil and natural gas
production. These hedge contracts are purchased to either protect the Company's
capital development budget or to protect a rate of return on acquisitions. These
contracts have historically consisted of price ceilings and floors, collars and
fixed price swaps. All of the mark-to-market valuations used for the Company's
financial derivatives are provided by external sources and are based on prices
that are actively quoted. The Company attempts to manage and control market and
counterparty credit risk through established internal control procedures which
are reviewed on an ongoing basis. The Company also minimizes its credit risk
exposure to counterparties through formal credit policies, monitoring
procedures, and diversification.
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and
Hedging Activities." This statement requires that every derivative instrument be
recorded on the balance sheet as either an asset or a liability measured at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the change in fair value is recognized in earnings. If the derivative
qualifies for hedge accounting, the change in fair value of the derivative is
recognized in other comprehensive income (equity) assuming that the hedge is
effective. In order for a hedge to be effective and qualify for hedge
accounting, the changes in fair value or cash flows of the hedging instruments
and the hedged items must have a high degree of correlation.
10
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Upon adoption on January 1, 2001, the Company recorded a $1.6 million
increase in assets for the fair value of the Company's floors in place, with a
corresponding increase to accumulated other comprehensive income of
approximately $1.0 million, after tax, for the transition adjustment as of
January 1, 2001. In the first quarter of 2001, the Company's fair value of its
derivative contracts decreased by $4.1 million. The Company recognized this loss
as a $3.1 million loss in "Amortization of derivative contracts and other
non-cash hedging adjustments" in the Company's Condensed Consolidated Statements
of Operations, with the remaining $1.0 million ($622,000 net of income taxes)
recorded as a reclassification out of accumulated other comprehensive income.
In the second quarter of 2001, the FASB amended its original guidance to
allow companies to amortize the cost of net purchased options over the period of
the applicable contract. As a result, since the second quarter of 2001 the
Company has been amortizing its derivative contract premiums over the periods
during which the contracts expire. During the second quarter and first six
months of 2002, this resulted in the amortization of $2.6 million and $5.1
million of derivative contract premiums, respectively. This amortization was
offset by pre-tax income, representing the reversal of accumulated other
comprehensive income relating to the hedges purchased from Enron in 2001 that
remained at the time that hedge accounting was discontinued, in the amounts of
$3.6 million and $7.2 million for the three and six months ended June 30, 2002,
respectively. The accumulated other comprehensive income related to these former
Enron hedges is being amortized into pre-tax income over the original expected
life of the hedges (i.e. through December 2003). See "Natural Gas Hedges
Historical Data" below for a full discussion of the impact of these hedges
purchased from Enron.
Oil Hedges Historical Data
During 2000, the Company purchased a $22.00 price floor on its 2001
production covering 12,800 Bbls/d at an aggregate cost of $1.8 million. This
contract covered approximately 75% of the Company's anticipated 2001 oil
production, excluding any anticipated production from acquisitions. During the
first half of 2001, nothing was collected on this price floor.
During July 2001, the Company purchased a $21.00 price floor on 10,000
Bbls/d for 2002 production at an aggregate cost of approximately $4.7 million.
This price floor covered approximately 60% of the Company's then anticipated oil
production for 2002. During the first quarter of 2002, $0.4 million was
collected on this price floor, which was recorded as part of the "Gain on
settlements of derivative contracts" in the Company's Condensed Consolidated
Statement of Operations. Nothing was collected on this contract during the
second quarter of 2002.
In May 2002, the Company acquired collars with three different financial
institutions covering 10,000 Bbls/d during calendar 2003 with a floor price of
$20.00 per barrel and a ceiling price of $30.00 per barrel. It is expected that
these hedges will cover between 40% and 60% of the Company's current
expectations for 2003 oil production.
In June 2002, the Company acquired oil hedges from two different financial
institutions to hedge through 2004 almost 100% of the forecasted proved
developed oil production from the pending COHO acquisition. The oil hedges are
no-cost swaps with an average fixed price of $24.26 per barrel during calendar
2003 and an average fixed price of $22.94 per barrel during calendar 2004. In
addition, the Company supplemented COHO's 2002 oil hedges the Company expects to
receive as part of the COHO asset purchase, by acquiring an oil swap for the
fourth quarter of 2002 covering 2,750 Bbls/d at a fixed price of $25.50 per
barrel.
Natural Gas Hedges Historical Data
During 2000, the Company purchased a $2.80 price floor on its 2001
production covering 37,500 MMBtu/d at an aggregate cost of $0.8 million. This
contract covered approximately 75% of the Company's then anticipated 2001
natural gas production, excluding any anticipated production from acquisitions.
During the first half of 2001, nothing was collected on this price floor.
11
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Concurrent with the acquisition of Thornwell Field, the Company purchased
price floors for these predominately natural gas properties in the fourth
quarter of 2000. The price floors covered nearly all of the anticipated proven
natural gas production from these properties for 2001 and 2002. These floors
cost $2.5 million with varying volumes and price floors each quarter for 2001
and 2002. During the first quarter of 2001, nothing was collected on these price
floors, but during the first quarter of 2002, approximately $594,000 was
collected from these price floors, recorded as part of the "Gain on settlements
of derivative contracts" in the Company's Condensed Consolidated Statement of
Operations. During the second quarter of 2001 and 2002, approximately $9,000 and
$12,000 were collected from these price floors, respectively.
For the Matrix properties acquired in July 2001 (see also "Note 5") the
Company purchased price floors covering nearly all of the forecasted proven
natural gas production through December 2003. During the second quarter of 2001,
the Company collected approximately $609,000 on these price floors. When Enron
filed for bankruptcy during the fourth quarter of 2001, the Company's hedges
with Enron ceased to qualify for hedge accounting treatment as required by
Financial Accounting Standards No. 133, and the accounting treatment changed at
that point in time. This change meant that any change in the current market
value of these assets must be reflected in the Company's income statement and
any remaining accumulated other comprehensive income (part of equity) left at
the time of the accounting change must be recognized over the original periods
the hedging contracts were to expire. To adjust the Enron hedges down to the
current market value, which was determined to be the amount the claims were sold
for in February 2002, the Company recorded a pre-tax write down of $24.4 million
in the fourth quarter of 2001. The accumulated other comprehensive income
previously recorded as part of the mark-to-market value adjustment each quarter
remained to be recognized over 2002 and 2003, the periods during which these
hedges would have expired. The result is that the Company will recognize pre-tax
income attributable to these Enron hedges during 2002 of approximately $13.4
million and recognize pre-tax income during 2003 of approximately $5.1 million
as the balance in accumulated other comprehensive income relating to these
hedges is reclassified. The three year total pre-tax net loss will be
approximately $5.9 million, which approximates the difference between the amount
collected and paid for the Enron portion of the Matrix price floors. During the
second quarter and first six months of 2002, the Company recognized pre-tax
income of $3.6 million and $7.2 million, respectively, related to the Enron
hedges in "Amortization of derivative contracts and other non-cash hedging
adjustments" in the Company's Condensed Consolidated Statement of Operations.
Subsequent to the Enron bankruptcy, the Company purchased additional hedges
to protect against any further deterioration in natural gas prices. These have a
floor price of $2.50 per MMBtu and an average ceiling price of around $4.15 per
MMBtu and cover not only the then anticipated gas production from the Matrix
properties, but a substantial portion of the Company's other natural gas
production as well. Overall, these hedges, which were purchased from four
different financial institutions, cover approximately 75% of the Company's then
forecasted total 2002 natural gas production. In the first quarter of 2002, the
Company collected $1.6 million from these natural gas hedges which is recorded
in "Gain on settlements of derivative contracts" in the Company's Condensed
Consolidated Statement of Operations. Nothing was collected during the second
quarter of 2002.
In February 2002 the Company acquired no-cost collars from three different
financial institutions covering 70,000 MMBtu/d during calendar 2003 with a floor
price of $2.75 per MMBtu and a weighted average ceiling price of $4.025 per
MMBtu. The Company expects that these hedges will cover between 50% and 75% of
its currently anticipated 2003 natural gas production.
12
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Hedges as of June 30, 2002
The following table lists all of the Company's individual hedges in place as of June 30, 2002.
Crude Oil Contracts:
------------------
NYMEX Contract Prices Per Bbl
-------------------------------------------------------
Collar Prices Estimated
------------------------- Fair Value at
Type of Contract and Period Bbls/day Swap Price Floor Price Floor Ceiling June 30, 2002
- ------------------------------- ------------ ------------ ------------ ----------- ----------- -----------------
Floor Contracts (thousands)
July 2002 - Dec. 2002 10,000 $ - $ 21.00 $ - $ - $ 496
Swap Contracts
Oct. 2002 - Dec. 2002 2,750 $ 25.50 $ - $ - $ - $ -
Jan. 2003 - Dec. 2003 2,500 24.22 - - - -
Jan. 2003 - Dec. 2003 2,000 24.30 - - - -
Jan. 2004 - Dec. 2004 2,500 22.89 - - - -
Jan. 2004 - Dec. 2004 2,000 23.00 - - - -
Collar Contracts
Jan. 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ 47
Natural Gas Contracts:
- ----------------------
NYMEX Contract Prices Per MMBtu
------------------------------------------------------
Collar Prices Estimated
----------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2002
- ------------------------------- -------------- ------------ -------------- ---------- ----------- -----------------
Floor Contracts (thousands)
July 2002 - Sept. 2002 2,873 $ - $ 3.38 $ - $ - $ 50
Oct. 2002 - Dec. 2002 2,135 - 3.38 - - 59
Collar Contracts
July 2002 - Dec. 2002 40,000 $ - $ - $ 2.50 $ 4.10 $ (788)
July 2002 - Dec. 2002 25,000 - - 2.50 4.20 (766)
July 2002 - Dec. 2002 25,000 - - 2.50 4.17 (502)
Jan. 2003 - Dec. 2003 45,000 - - 2.75 4.00 (6,914)
Jan. 2003 - Dec. 2003 25,000 - - 2.75 4.07 (3,673)
At June 30, 2002, the Company's derivative contracts were recorded at their
fair value, which was a net liability of approximately $12.0 million, a decrease
of approximately $35.5 million from the $23.5 million fair value asset recorded
as of December 31, 2001. This change is the result of (i) a decrease in the fair
market value of the Company's hedges due to an increase in oil and natural gas
commodity prices between December 31, 2001 and June 30, 2002, (ii) the
liquidation of the Company's Enron hedge positions in February 2002, and (iii)
the expiration of certain derivative contracts in the first six months of 2002
for which the Company recorded amortization expense of $5.1 million.
The balance in accumulated other comprehensive loss of $4.5 million at June
30, 2002, represents the deficit in the fair market value of the Company's
derivative contracts as compared to the cost of the hedges, net of related
income taxes, and also includes the remaining accumulated other comprehensive
income relating to the Enron hedges, as these assets are no longer accounted for
with hedge accounting treatment due to the Enron bankruptcy. The remaining
accumulated other comprehensive income relating to these Enron hedges will be
reversed in 2002 and 2003, during the
13
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
periods that the hedges would have otherwise expired. Of the $4.5 million in
accumulated other comprehensive loss as of June 30, 2002, $7.7 million of the
deficit relates to current hedging contracts that will expire within the next 12
months and $2.3 million relates to contracts which expire subsequent to June 30,
2003. Other comprehensive loss also includes $5.5 million related to future
income associated with former Enron hedging contracts that will be reclassified
out of accumulated other comprehensive loss during the next twelve months.
5. ACQUISITION OF MATRIX OIL AND GAS, INC.
On July 10, 2001, the Company completed the acquisition of Matrix Oil &
Gas, Inc.("Matrix"), an independent oil and gas company based in Covington,
Louisiana. Under the merger agreement, Denbury paid a total of approximately
$158.5 million, comprised of $99.3 million (63%) in cash and $59.2 million (37%)
in the form of 6.6 million shares of Denbury's common stock. The purchase price
may be adjusted on a post-closing basis under certain provisions of the
acquisition agreement. The Company expects that any remaining adjustments to the
purchase price, principally based upon potential post-closing adjustments for
liabilities and contingencies of Matrix for periods prior to the closing date,
will be determined within the next few months. The acquired operations of Matrix
were reflected in the Company's financial statements beginning July 1, 2001.
The following pro forma information reflects the consolidated results of
operations for the three and six month periods ended June 30, 2001, based upon
adjustments to the historical financial statements of the Company and the
historical financial statements of Matrix to give effect to the acquisition by
the Company as if such acquisition had occurred on January 1, 2001 (in
thousands, except per share data):
Three Months Six Months
Ended Ended
June 30, 2001 June 30, 2001
--------------- -----------------
Operating revenues $ 84,390 $ 186,018
Net income 21,250 52,344
Income per common share:
Basic $ 0.40 $ 0.99
Diluted 0.39 0.97
6. ACQUISITION OF GENESIS ENERGY, L.L.C.
On May 14, 2002, a subsidiary of the Company acquired Genesis Energy,
L.L.C. (which was converted to Genesis Energy, Inc.), the general partner of
Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership,
for total consideration, including expenses and commissions, of approximately
$2.0 million. Genesis is engaged in two primary lines of business: crude oil
gathering and marketing and pipeline transportation primarily in Mississippi,
Texas, Alabama and Florida.
The general partner the Company acquired owns 2% of Genesis and the Company
is accounting for its ownership in Genesis under the equity method of
accounting. The Company has significant influence over the limited partnership
as a result of its ownership of the general partner interest, but because of the
terms of the partnership agreement, does not meet the criteria for control which
would require the Company to consolidate the limited partnership. The Company's
equity in Genesis' net income for the second quarter of 2002 was $20,000,
representing 2% of Genesis' net income from May 15, 2002 through June 30, 2002.
Summarized financial information of Genesis has been provided as supplemental
data below. Genesis Energy, Inc., the 100% owned general partner, has guaranteed
the bank debt of
14
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Genesis, which as of June 30, 2002, was $1.5 million, plus $27.5 million
outstanding letters of credit of which $5.9 million were for purchases from
Denbury. There are no other guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, Inc. The Company's
investment of $2.0 million exceeded its percentage of net equity in the limited
partnership at the time of acquisition by approximately $830,000, which
represents goodwill and is not subject to amortization.
Genesis has historically been a purchaser of crude oil from the Company and
future purchases of the Company's crude oil by Genesis are anticipated. For the
period from May 15, 2002 through June 30, 2002, the Company recorded sales to
Genesis of $3.4 million and at June 30, 2002, had a production receivable from
Genesis for $2.2 million. For the year ended December 31, 2001, Genesis
purchased approximately 17% of the Company's crude oil production and accounted
for 8% of the Company's total oil and natural gas revenues.
Summarized financial information of Genesis Energy L.P. is as follows
(amounts in thousands):
Three Months Six Months
Ended Ended
June 30, 2002 June 30, 2002
--------------------- -----------------------
Revenues $ 240,769 $ 480,008
Cost of sales 234,547 468,348
Other expenses 4,116 8,240
--------------------- -----------------------
Net income $ 2,106 $ 3,420
===================== =======================
June 30, December 31,
2002 2001
--------------------- -----------------------
Current assets $ 83,518 $ 182,100
Non-current assets 44,009 48,013
--------------------- -----------------------
Total assets $ 127,527 $ 230,113
===================== =======================
Current liabilities $ 90,083 $ 183,689
Non-current liabilities 2,015 14,415
Partners' capital 35,429 32,009
--------------------- -----------------------
Total liabilities and
partners' capital $ 127,527 $ 230,113
===================== =======================
15
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
7. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of August 2001, all of the Company's subordinated debt securities were
fully and unconditionally guaranteed by Denbury Resources Inc.'s significant
subsidiaries. Condensed consolidating financial information for Denbury
Resources Inc. and its significant subsidiaries as of June 30, 2002 and December
31, 2001 and for the three and six months ended June 30, 2002 and 2001 is as
follows:
Condensed Consolidating Balance Sheets
June 30, 2002 (Unaudited)
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- ------------- --------------
ASSETS
Current assets..................................$ 64,794 $ 13,928 $ - $ 78,722
Property and equipment.......................... 464,929 213,129 - 678,058
Investment in subsidiaries (equity method)...... 168,260 2,060 (168,260) 2,060
Other assets.................................... 18,227 3,285 - 21,512
-------------- ------------- ------------- --------------
Total assets...............................$ 716,210 $ 232,402 $ (168,260) $ 780,352
============== ============= ============= ==============
LIABILITIES AND STOCKHOLDERS'EQUITY
Current liabilities.............................$ 47,785 $ 6,391 $ - $ 54,176
Long-term liabilities........................... 317,407 57,751 - 375,158
Stockholders' equity............................ 351,018 168,260 (168,260) 351,018
-------------- ------------- ------------- --------------
Total liabilities and stockholders' equity.$ 716,210 $ 232,402 $ (168,260) $ 780,352
============== ============= ============= ==============
December 31, 2001
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- -------------- --------------
ASSETS
Current assets..................................$ 98,182 $ 5,096 $ - $ 103,278
Property and equipment.......................... 445,693 222,314 - 668,007
Investment in subsidiaries (equity method)...... 164,830 - (164,830) -
Other assets.................................... 15,684 3,019 - 18,703
-------------- ------------- -------------- --------------
Total assets...............................$ 724,389 $ 230,429 $ (164,830) $ 789,988
============== ============= ============== ==============
LIABILITIES AND STOCKHOLDERS'EQUITY
Current liabilities.............................$ 68,937 $ 11,001 $ - $ 79,938
Long-term liabilities........................... 306,284 54,598 - 360,882
Stockholders' equity............................ 349,168 164,830 (164,830) 349,168
-------------- ------------- -------------- --------------
Total liabilities and stockholders' equity.$ 724,389 $ 230,429 $ (164,830) $ 789,988
============== ============= ============== ==============
16
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 57,116 $ 16,317 $ - $ 73,433
Expenses..................................... 40,456 13,386 - 53,842
--------------- -------------- -------------- --------------
Income before the following: 16,660 2,931 - 19,591
Equity in net earnings of subsidiaries.. 1,842 20 (1,842) 20
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 18,502 2,951 (1,842) 19,611
Income tax provision......................... 5,004 1,109 - 6,113
--------------- -------------- -------------- --------------
Net income (loss)............................$ 13,498 $ 1,842 $ (1,842) $ 13,498
=============== ============== ============== ==============
Three Months Ended June 30, 2001 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- --------------- --------------
Revenues.....................................$ 67,383 $ 24 $ - $ 67,407
Expenses..................................... 35,498 (14) - 35,484
--------------- -------------- --------------- --------------
Income before the following: 31,885 38 - 31,923
Equity in net earnings of subsidiaries.. 38 - (38) -
--------------- -------------- --------------- --------------
Income (loss) before income taxes............ 31,923 38 (38) 31,923
Provision for income taxes................... 11,812 - - 11,812
--------------- -------------- --------------- --------------
Net income (loss)............................$ 20,111 $ 38 $ (38) $ 20,111
=============== ============== =============== ==============
Six Months Ended June 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 102,449 $ 26,431 $ - $ 128,880
Expenses..................................... 78,873 24,893 - 103,766
--------------- -------------- -------------- --------------
Income before the following: 23,576 1,538 - 25,114
Equity in net earnings of subsidiaries.. 950 20 (950) 20
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 24,526 1,558 (950) 25,134
Income tax provision......................... 6,482 608 - 7,090
--------------- -------------- -------------- --------------
Net income (loss)............................$ 18,044 $ 950 $ (950) $ 18,044
=============== ============== ============== ==============
17
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations (continued)
Six Months Ended June 30, 2001 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- --------------- --------------
Revenues.....................................$ 146,951 $ (364) $ - $ 146,587
Expenses..................................... 73,496 (52) - 73,444
--------------- -------------- --------------- --------------
Income before the following: 73,455 (312) - 73,143
Equity in net earnings of subsidiaries.. (312) - 312 -
--------------- -------------- --------------- --------------
Income (loss) before income taxes............ 73,143 (312) 312 73,143
Provision for income taxes................... 27,063 - - 27,063
--------------- -------------- --------------- --------------
Net income (loss)............................$ 46,080 $ (312) $ 312 $ 46,080
=============== ============== =============== ==============
Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 50,742 $ 7,862 $ - $ 58,604
Cash flow from investing activities.......... (54,424) (4,774) - (59,198)
Cash flow from financing activities.......... (2,727) - - (2,727)
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... (6,409) 3,088 - (3,321)
Cash, beginning of period.................... 17,052 6,444 - 23,496
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 10,643 $ 9,532 $ - $ 20,175
================= ============== ============== ==============
Six Months Ended June 30, 2001 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 88,969 $ 8,006 $ - $ 96,975
Cash flow from investing activities.......... (115,282) - - (115,282)
Cash flow from financing activities.......... 19,350 - - 19,350
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... (6,963) 8,006 - 1,043
Cash, beginning of period.................... 22,285 8 - 22,293
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 15,322 $ 8,014 $ - $ 23,336
================= ============== ============== ==============
18
DENBURY RESOURCES INC.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
- --------------------------------------------------------------------------------
You should read the following in conjunction with our financial statements
contained herein and our Form 10-K for the year ended December 31, 2001, along
with Management's Discussion and Analysis of Financial Condition and Results of
Operations contained in such Form 10-K. Any terms used but not defined in the
following discussion have the same meaning given to them in the Form 10-K.
Denbury is a growing independent oil and natural gas company engaged in
acquisition, development and exploration activities in the U.S. Gulf Coast
region. We have significant reserves and production in Mississippi, where we are
the largest oil and natural gas producer, in onshore Louisiana and in the
offshore Gulf of Mexico. Our strategy is to increase the value of properties we
acquire in our core areas through a combination of exploitation, drilling and
proven engineering extraction processes.
CAPITAL RESOURCES AND LIQUIDITY
Oil and natural gas prices were unusually high early in 2001, but generally
declined throughout 2001 to a NYMEX price of around $20.00 per Bbl and $2.50 per
Mcf as of year-end 2001. During the first quarter of 2002, the average NYMEX
prices were relatively unchanged from year-end levels, but late in the first
quarter commodity prices began to increase, averaging approximately $26.25 per
Bbl of oil and $3.40 per MMBtu of natural gas for the second quarter of 2002.
Although higher than the prior quarter and year-end price levels, prices during
the second quarter of 2002 were still less than those in the second quarter of
2001. NYMEX prices for the second quarter of 2001 averaged approximately $28.00
per Bbl of oil (7% higher than the current quarter) and $4.65 per Mcf of natural
gas (37% higher than the current quarter). As more fully described under
"Results of Operations" below, higher production levels partially offset the
lower commodity prices, with the net result of a 4% decrease to cash flow from
operations (before changes in assets and liabilities) in the second quarter of
2002 as compared to the second quarter of 2001. On a six month comparison, the
cash flow from operations was approximately 28% lower in the first half of 2002
than in the first half of 2001, as the disparity in commodity prices was much
more significant during the respective first quarters.
Our net average commodity price per BOE was 14% lower in the second quarter
of 2002 than in the second quarter of 2001, but production rates averaged 27%
higher. The single most significant change between the respective second
quarters and comparative six month periods, other than commodity prices, relates
to the effects of the acquisition of Matrix Oil & Gas, Inc. in July of 2001.
This acquisition initially contributed approximately 40 MMcfe/d (6,667 BOE/d) of
additional production (8,146 BOE/d in the second quarter of 2002) and
corresponding increases in revenues, but also contributed to an increase in most
expenses, including operating expenses, general and administrative expenses,
interest expense and depreciation and amortization expense. During the second
quarter of 2002, our net income was $13.5 million and our cash flow from
operations (before the changes in assets and liabilities) was $43.4 million, as
compared to $20.1 million of net income and $45.2 million of cash flow for the
second quarter of 2001.
During the first six months of 2002, we incurred $49.7 million on oil and
natural gas property expenditures, plus we made approximately $2.3 million of
oil and natural gas property acquisitions. Our cash flow from operations (before
changes in assets and liabilities) for the same six month period totaled $71.9
million. The excess cash flow was used to fund a reduction in our net payables
and to reduce bank debt by approximately $4.9 million. We anticipate that our
capital spending, excluding any possible acquisitions, will be equal to or less
than our cash flow generated from operations for 2002, as has been our policy
since 1999. We currently have budgeted $110 million of new development and
exploratory projects for 2002, plus we carried over approximately $6 million of
projects from 2001. Based on current projections, using futures prices as of the
first part of August 2002, this spending level is expected to be as much as $35
million to $50 million below our forecasted cash flow. However, commodity prices
are highly variable, as has been demonstrated during the last few years, and our
anticipated cash flow is highly dependent on commodity prices. We plan to use
any excess funds generated from operations to pay down debt or fund, in whole or
in part, acquisitions. We review our capital expenditure budget every quarter
and make adjustments as necessary to reflect the successes or failures in our
drilling program and to adjust to changes in commodity prices. As a result,
since 1999, we have been able to keep our capital spending program (excluding
acquisitions) at, or less than, our cash flow from operations.
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PROPOSED ACQUISITION OF CERTAIN COHO PROPERTIES: On June 28, 2002, we
announced that we were the high bidder for the COHO Energy, Inc. Gulf Coast
properties auctioned in the U.S. Bankruptcy Court in Dallas, Texas. On August 6,
2002, the court made a final ruling on this matter and awarded us these
properties, subject to the finalization of environmental and title issues, with
closing anticipated for late August. The acquisition includes nine fields, eight
of which are located in Mississippi and one in Texas, eight of which are
operated by COHO. Our initial estimates indicate the acquisition will add
approximately 14.4 million barrels of proven oil reserves, with production on
these properties currently averaging between 4,000 and 4,500 Bbls/d. The
purchase price of $50.3 million, before adjustments, will be funded by a draw on
the $84 million available to us under our bank facility. We do not expect the
acquisition to require much incremental infrastructure as we are currently very
active in the same areas that these COHO properties are located in. We have
hedged nearly 100% of the forecasted proved developed production relating to
this acquisition through the end of 2004 with no-cost oil swaps. The average
fixed price in 2003 is $24.26 per barrel and the average fixed price in 2004 is
$22.94 per barrel. We are considering the possible sale of a portion of these
acquired properties, along with other minor properties that we own. This would
likely take place during the fourth quarter of 2002, with estimated net proceeds
ranging from a minimum of $5 million to as much as $35 million, depending on the
level of interest, commodity prices at the time, and the bids that we obtain.
This sale is not expected to materially impact our current production, although
it could be as much as 50% of the production from the properties included in the
COHO acquisition. We plan to use any proceeds that we obtain from property sales
to reduce our bank debt.
Although we have a significant inventory of development and exploration
projects in-house, on a long-term basis we will need to make acquisitions in
order to continue our growth and to replace our production. We are continuing to
pursue acquisitions that are near our CO2 pipeline in Western Mississippi and
Northeastern Louisiana. These acquisitions are generally inexpensive, as most of
these fields have only minor remaining oil production and thus do not have
significant value to the current owners. We plan to purchase more of these
fields and attempt to increase production and reserves by flooding them with CO2
we own, just as we have at Little Creek and Mallalieu Fields. We also continue
to look for acquisitions in our other core areas, which normally would have a
much higher acquisition cost on both an absolute and per BOE basis. Any
acquisitions that we make will likely be funded with either our excess cash flow
or bank debt.
The bank borrowing base on our credit facility is set by our banks at their
sole discretion based on various factors, some of which are out of our control.
Our borrowing base is reviewed semi-annually and was left unchanged at $220
million as of the latest review effective April 1, 2002. As of August 9, 2002,
we had $136 million of bank debt outstanding, leaving us $84 million of current
bank line availability. After the proposed COHO acquisition scheduled to close
in late August, we will have approximately $186 million outstanding with $34
million of availability. The next borrowing base review by the banks will be
October 1, 2002. We do not anticipate any significant change in the borrowing
base, nor do we currently plan to ask for an increase, even though it would be
reasonable for us to do so with the additional properties to be acquired from
COHO, as we anticipate that we will be able to end the year with less bank debt
than the $186 million anticipated to be outstanding after the COHO acquisition.
This debt reduction is expected to come from the aforementioned planned property
sales and anticipated excess cash flow from operations, assuming that commodity
prices do not decrease appreciably.
We have no significant off balance sheet arrangement, special purpose
entities, financing partnerships or guarantees, nor any debt or equity triggers
based upon our stock or commodity prices. Our bank debt is not due until
December 31, 2003, a date we expect to extend at our forthcoming semi-annual
review effective October 1, 2002, and our subordinated debt is due in March
2008. Our only other obligations that are not currently recorded on our balance
sheet are our operating leases, which primarily relate to our office space and
minor equipment leases, and various spending obligations for development and
exploratory expenditures arising from purchase agreements or other transactions
common to our industry, which have not changed materially since December 31,
2001. Our capital spending obligations total approximately $13.6 million over
the next four years, none of which is required in 2002. In addition as is common
in
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
our industry, we commit to make certain expenditures on a regular basis as part
of our ongoing development and exploration program. These commitments generally
relate to projects that will occur during the subsequent six months and are part
of our annual budget process which we can scale up or down based on commodity
prices, available capital, etc. We also have an obligation to deliver
approximately 90 Bcf of CO2 to our industrial customers. Based on the size of
our proven CO2 reserves and our current production capabilities, we are
confident we can meet these delivery obligations. At June 30, 2002, we had a
total of $5.4 million outstanding in letters of credit, primarily to secure the
proposed COHO acquisition. We do not have any material transactions with related
parties other than transactions with Genesis Energy, L.P. as discussed in Note 6
to the financial statements.
We have purchased oil price floors and collars that cover 50% to 60% of our
currently expected 2002 oil production and 40% to 60% of our anticipated 2003
oil production, and have purchased natural gas collars covering 80% to 85% of
our currently expected 2002 natural gas production and 50% to 75% of our
anticipated 2003 natural gas production. In addition, we have hedged nearly 100%
of the forecasted proved developed production from the COHO acquisition through
2004 (see also "Market Risk Management" for more detail on these hedges). We
have entered into these hedges in order to protect our cash flow, so that a
majority of our capital program can be implemented, and so that we can achieve a
minimum rate of return on acquisitions, provided that our other assumptions
related to the acquisitions are correct. None of these hedges are currently in
the money, but they do offer significant protection should commodity prices drop
in the future.
SOURCES AND USES OF FUNDS
During the first six months of 2002, we spent approximately $49.7 million
on oil and natural gas development and exploration expenditures and $2.3 million
on acquisitions. The oil and gas exploration and development expenditures
included $32.5 million spent on drilling, $10.3 million spent on geological,
geophysical and acreage expenditures and $6.9 million spent on workover costs.
We also spent $5.9 million on CO2 acquisition and development expenditures
during the first six months of 2002. All of these expenditures were funded with
cash flow from operations.
During the first six months of 2001, we spent approximately $70.5 million
on oil and natural gas development and exploration expenditures and
approximately $1.8 million on acquisitions, net of purchase price adjustments.
The exploration and development expenditures included approximately $44.8
million spent for drilling, $7.7 million for geological, geophysical and acreage
expenditures and $18.0 million for workover costs. Also, during the first six
months of 2001 we spent approximately $91,000 on CO2 development expenditures
and $41.9 million on an acquisition of CO2 properties. These expenditures were
funded by cash flow from operations and bank debt.
ACQUISITION OF GENESIS GENERAL PARTNER
On May 14, 2002, a newly-formed subsidiary of Denbury acquired Genesis
Energy, L.L.C. (which was converted to Genesis Energy, Inc.), the general
partner of Genesis Energy, L.P.("Genesis"), a publicly traded master limited
partnership, for total consideration, including expenses and commissions, of
approximately $2.0 million. The general partner owns a 2% interest in the
limited partnership. Genesis is engaged in two primary lines of business: crude
oil gathering and marketing and pipeline transportation. We are accounting for
our investment in Genesis under the equity method of accounting, which increased
our net income for the second quarter of 2002 by $20,000. We have included in
the footnotes to the consolidated financial statements summarized financial
information of Genesis (see Note 6, "Acquisition of Genesis Energy LLC").
Genesis Energy, Inc., the 100% owned general partner, has guaranteed the bank
debt of Genesis, which as of June 30, 2002, was $1.5 million, plus $27.5 million
outstanding letters of credit of which $5.9 million were for purchases from
Denbury. There are no other guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Our operating results for the first quarter of 2002 were substantially
lower than results for the first quarter of the prior year due to the sharp
decrease in commodity prices, partially offset by higher overall production
levels. The operating results for the comparative second quarters were not as
divergent, as commodity prices increased in the second quarter of 2002 relative
to those in the first quarter of 2002, whereas commodity prices decreased in the
second quarter of 2001 relative to the first quarter of 2001, and we had
significantly higher production in the 2002 periods than in those for 2001. Our
net income, net income per common share and cash flow from operations were as
follows:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------- ------------------------------ -----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 2002 2001 2002 2001
- -------------------------------------------------- ------------- --------------- ------------- --------------
Net income $ 13,498 $ 20,111 $ 18,044 $ 46,080
Net income per common share:
Basic $ 0.25 $ 0.44 $ 0.34 $ 1.00
Diluted 0.25 0.42 0.33 0.97
Cash flow from operations (1) $ 43,423 $ 45,194 $ 71,947 $ 100,176
- -------------------------------------------------- ------------- --------------- ------------- ---------------
(1) Represents cash flow provided by operations, before changes in assets and
liabilities.
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------- ------------------------------ -----------------------------
2002 2001 2002 2001
- -------------------------------------------------- -------------- ------------ -------------- --------------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 17,921 16,454 17,831 16,362
Mcf 105,634 68,685 105,680 65,458
BOE(1) 35,526 27,902 35,444 27,272
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 37,404 $ 34,355 $ 65,237 $ 69,756
Natural gas sales 33,710 30,768 56,787 73,682
Gain on settlements of derivative contracts 12 618 2,648 618
------------- ------------ ------------- --------------
Total oil and natural gas revenues $ 71,126 $ 65,741 $ 124,672 $ 144,056
------------- ------------ ------------- --------------
Lease operating costs $ 17,124 $ 12,417 $ 32,552 $ 24,887
Production taxes and marketing expenses 3,297 2,532 5,911 5,140
------------- ------------ ------------- --------------
Total production expenses $ 20,421 $ 14,949 $ 38,463 $ 30,027
------------- ------------ ------------- --------------
CO2 sales to industrial customers $ 1,896 $ 1,424 $ 3,386 $ 2,283
CO2 operating costs 362 277 529 335
------------- ------------ ------------- --------------
CO2 operating margin $ 1,534 $ 1,147 $ 2,857 $ 1,948
------------- ------------ ------------- --------------
UNIT PRICES-INCLUDING IMPACT OF HEDGES
Oil price per barrel ("Bbl") $ 22.94 $ 22.94 $ 20.36 $ 23.55
Gas price per thousand cubic feet ("Mcf") 3.51 5.02 3.08 6.27
UNIT PRICES-EXCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 22.94 $ 22.94 $ 20.21 $ 23.55
Gas price per Mcf 3.51 4.92 2.97 6.22
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE(1)
Oil and natural gas revenues $ 22.00 $ 25.65 $ 19.02 $ 29.06
------------- ------------ ------------- --------------
Oil and gas lease operating costs $ 5.30 $ 4.89 $ 5.07 $ 5.04
Oil and gas production taxes and marketing expense 1.02 1.00 0.92 1.04
------------- ------------ ------------- --------------
Total oil and gas production expenses $ 6.32 $ 5.89 $ 5.99 $ 6.08
- ------------------------------------------------- ------------- ------------ ------------- --------------
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
PRODUCTION: Our production for the second quarter of 2002 averaged 35,526
BOE/d, a 27% increase from the second quarter of 2001 average of 27,902 BOE/d,
and just slightly higher than the first quarter of 2002 average of 35,361 BOE/d.
Approximately 6,667 BOE/d (87%) of the year-over-year quarterly increase was
attributable to the acquisition of Matrix Oil & Gas, Inc. in July 2001 (the
average daily production rate at the time of acquisition). The production on
these Matrix properties has increased each quarter during the last three
quarters, averaging 8,146 BOE/d in the second quarter of 2002, the highest
quarterly average to date for these properties, an increase of 620 BOE/d over
the first quarter of 2002.
CO2 FLOOD PROPERTIES. We also had higher production from our CO2 flood
properties, Little Creek and Mallalieu Fields. Production at Little Creek Field,
including West Little Creek, increased from 2,293 BOE/d in the second quarter of
2001 to 3,701 BOE/d in the second quarter of 2002 as the tertiary floods
continued to respond. This compares to an
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
average of 3,623 BOE/d in the first quarter of 2002. Mallalieu Field, another
tertiary flood project that we purchased in April 2001, began to respond to the
injection of CO2 which commenced in the fourth quarter of 2001, increasing from
approximately 75 Bbls/d at the time of acquisition to a quarterly average of 572
Bbls/d for the second quarter of 2002. The response at this field is ahead of
expectations, although the response has leveled off recently due to the lack of
deliverability and injection of CO2. Subsequent to June 30, 2002, we added
additional compression and commenced the drilling of an additional CO2 well,
with plans to add additional compression during the next sixty days in order to
increase our available CO2. By year-end, we expect to be able to increase our
CO2 production from the second quarter of 2002 average of 101 MMcf/d to around
160 MMcf/d. The anticipated incremental CO2 production will be available to
increase the CO2 injected per day at Little Creek and Mallalieu, with the
anticipation that oil production from these fields will continue to incline
throughout 2002 and 2003 as a result of the higher injection volumes. Overall,
the oil production from our CO2 properties has increased from approximately
2,000 Bbls/d at the beginning of 2001 to an average of 4,278 Bbls/d during the
second quarter of 2002. We have committed to the purchase of two other
potentially significant CO2 flood properties along our CO2 pipeline, Brookhaven
Field which is part of the COHO acquisition expected to close in late August
(see "Capital Resources and Liquidity" above) and McComb Field which is also
expected to close during August at a cost of approximately $2.5 million. In
addition, we are continuing to acquire leases on three other oil fields along
our CO2 pipeline, and we are in the process of creating a long-term development
plan for these fields. We anticipate that as part of this plan, we will spend
between $25 million and $50 million per year on these properties that we now
control, or are about to control, which should result in a general increase in
the oil production from these properties each year for the next five to seven
years.
The production increases from our CO2 floods and offshore properties were
partially offset by general production declines from normal depletion in our
other two core areas, Eastern Mississippi and Louisiana. Our production for the
first six months of 2002 was almost perfectly balanced, with 50% oil and 50%
natural gas, similar to our production ratio during the last half of 2001. In
comparison, the production during the first six months of 2001 was approximately
60% oil. The Matrix acquisition in July 2001 added predominately natural gas,
the primary reason for the change in our overall mix of production. The COHO
acquisition expected to close in late August is virtually all oil production,
which will cause the fourth quarter of 2002 ratio to become more weighted
towards oil.
Production rates at other significant fields during the second quarter of
2002 included an average of 3,479 BOE/d at Thornwell Field, a 10% decrease over
production levels in the second quarter of 2001 and a 21% decrease from
production levels in the first quarter of 2002. The majority of the production
at Thornwell is short-lived natural gas production and thus volumes can
fluctuate significantly from period to period depending on the level of
activity, the timing of well completions, etc. Overall, the Thornwell
acquisition in October of 2000 has performed well, as we have recovered most of
our initial cost, yet at year-end 2001 had a remaining reserve value of $34.9
million based on the SEC pricing of $19.84 per Bbl and $2.57 per MMBtu.
Production at Thornwell is expected to increase in the third quarter with the
recent completion of two new wells.
Production at our Heidelberg Field averaged 7,458 BOE/d during the second
quarter of 2002, a 6% decrease from production levels in the second quarter of
2001 and a 3% decrease from production levels in the first quarter of 2002.
Overall production from this field is expected to remain relatively flat or
slightly decline as the waterfloods appear to have reached a plateau. The
natural gas production at Heidelberg has also begun to decline as a result of
our reduced natural gas drilling activity there in late 2001 and early 2002.
However, we have recently drilled four natural gas wells at Heidelberg, due to
the higher natural gas prices in the second quarter of 2002, which should
increase the natural gas production at Heidelberg in the third quarter.
OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues for the second
quarter of 2002 increased $5.4 million, or 8%, from the comparable quarter of
2001, although they were down $19.4 million, or 13%, when comparing the first
six months of 2001 and 2002. In general, the unusually high natural gas prices
early in 2001 and relatively low
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
natural gas price in early 2002 were the primary reasons for the significant
decrease in revenue during the first six months of 2002 when compared to the
prior year period. During the respective second quarters, the higher production
rates in 2002 were enough to offset the decline in commodity prices from 2001
levels (see a discussion of overall commodity prices in the first paragraph of
"Capital Resources and Liquidity" above). For the first half of 2002, the
decline in commodity prices reduced revenues by $64.4 million, or 45%, from
levels in the comparable period in 2001. This decrease was offset in part by an
increase in production volumes which increased revenues by $43.0 million, or
30%, and higher cash receipts from derivative contracts which increased revenues
by $2.0 million, or 1%, from levels in the comparable period of 2001. When
comparing the respective second quarters, the same factors apply, although the
commodity price differential was not as large and thus the higher production
levels more than offset the commodity price decline. The increase in production
volumes in the second quarter of 2002 increased revenues by $17.8 million, or
27%, over the level of the second quarter of 2001. This increase was partially
offset by lower commodity prices in the second quarter of 2002, which reduced
revenues by $11.8 million, or 18%, from levels in the comparable period in 2001.
The Company had cash receipts from derivative contracts of $618,000 in the
second quarter of 2001 and only $12,000 of such receipts in the second quarter
of 2002, which decreased revenues by $606,000, or 1% of the change in oil and
natural gas revenues between the comparative periods.
Our realized natural gas prices (excluding hedges) for the second quarter
and first six months of 2002 averaged $3.51 and $2.97 per Mcf, respectively, a
29% and 52% respective decrease from the average prices of $4.92 and $6.22 per
Mcf during the comparable periods of 2001. Our realized oil prices (excluding
hedges) for the second quarter and first six months of 2002 averaged $22.94 and
$20.21 per Bbl, respectively, resulting in no change for the comparative second
quarters but a 14% decrease from the $23.55 per Bbl average in the first six
months of 2001. During the second quarter of 2002, our average oil price was
approximately $3.30 less than the average NYMEX oil price, which is
approximately $1.00 to $1.75 better than our recent NYMEX price differentials.
The improved net oil price resulted from a favorable move of certain oil
indices, such as the West Texas Sour posting and the price of Mayan crude,
relative to the NYMEX prices. We are not able to predict how these specific
indices will fluctuate relative to NYMEX in the future, although we would expect
them to return to more normal historical averages, which would reduce our net
average oil price in the future relative to the NYMEX price.
We collected $2.6 million on our commodity hedges in the first six months
of 2002 (virtually all in the first quarter), increasing our average realized
natural gas price by $0.11 per Mcf and our average realized oil price by $0.15
per Bbl for the six month period. For the first six months of 2001 we collected
$618,000 on our natural gas hedges (all in the second quarter) which increased
our average realized natural gas price by $0.05 for the first six months of
2001.
CO2 OPERATIONS: We received net operating cash flow from our sales of CO2
to third parties of $1.5 million for the second quarter of 2002 and $2.9 million
for the first half of 2002 as compared to $1.1 million for the second quarter of
2001 and $1.9 million for the first half of 2001. These sales have gradually
increased since our acquisition of these properties in February of 2001. During
the second quarter of 2002, we used approximately 53% of the CO2 that we
produced for our tertiary recovery operations and sold the remainder to third
parties for industrial use. Our average production for the second quarter of
2002 was 101 MMcf/d.
PRODUCTION EXPENSES: Our oil and natural gas lease operating expenses
increased 8% and 1% on a per BOE basis between the respective second quarters
and first six months of 2002 and 2001. The increases were primarily due to more
than usual workover expenses, principally offshore on the Matrix properties.
These increased costs were partially offset by savings resulting from the
general increases in production and from our ownership of CO2 purchased in
February 2001. Lease operating expenses increased on a gross basis by $4.7
million, or 38%, between the respective second quarters and by $7.7 million, or
31%, between the respective six month periods, primarily as a result of the
Matrix acquisition in July 2001.
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Production taxes and marketing expenses on a per BOE basis increased 2%
between the respective second quarters and decreased 12% between the first six
months of 2002 and 2001. The increase was primarily due an increase in marketing
and transportation expenses due to the acquisition of the Matrix properties and
the increases in production thereon, partially offset by the decline in
commodity prices.
The CO2 acquisition in February 2001, continues to lower our cost for CO2
that we use in our tertiary recovery operations at Little Creek and Mallalieu
Fields. Prior to the CO2 acquisition, we were paying approximately $0.25 per
thousand cubic feet for CO2. Subsequent to the acquisition, we began allocating
the operating expenses of our CO2 field and pipeline between the sales to
commercial users and the CO2 used for our own account. This translates into an
average operating cost of approximately $0.10 for each thousand cubic feet of
CO2 produced during the second quarter of 2002, or a savings of $0.15 per
thousand cubic feet of CO2 used by us. The estimated total cost per thousand
cubic feet of CO2 for us is approximately $0.15, after inclusion of the
depreciation and amortization expense. As a result of the lower cost of CO2,
coupled with inclining production, the operating cost per BOE at Little Creek
Field has declined from the $11.00 per BOE range before we acquired the CO2
properties to an average of $8.78 per BOE in the most recent quarter.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 13% on a per BOE
basis between the respective second quarters, were almost identical on a per BOE
basis for the respective six month periods, and increased on a gross basis as
set forth below:
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------------- --------------------------------- --------------------------------
2002 2001 2002 2001
- ------------------------------------------- --------------- --------------- -------------- ---------------
NET G&A EXPENSES (THOUSANDS)
Gross G&A expenses $ 9,471 $ 7,462 $ 18,980 $ 14,944
State franchise taxes 361 300 728 575
Operator overhead charges (5,345) (4,485) (10,548) (8,680)
Capitalized exploration costs (1,193) (973) (2,650) (1,859)
--------------- --------------- -------------- ---------------
Net G&A expense $ 3,294 $ 2,304 $ 6,510 $ 4,980
--------------- --------------- -------------- ---------------
Average G&A expense per BOE $ 1.02 $ 0.90 $ 1.01 $ 1.01
Employees as of June 30 332 271 332 271
- ------------------------------------------- --------------- -------------- -------------- ---------------
Gross G&A expenses increased $2.0 million, or 27%, between the second
quarters of 2001 and 2002 and increased $4.0 million, or 27%, between the
respective first six months. The largest components of these increases were
salaries, bonus accruals, and other related employee costs, which accounted for
approximately $3.6 million of the increase for the respective six month periods.
The increase in employee costs is due to salary increases and employee related
additions resulting from our growth and the Matrix acquisition in July 2001. The
increase in gross G&A expense is offset in part by an increase in operator
overhead recovery charges and capitalized exploration costs in 2002. Our well
operating agreements allow us, when we are the operator, to charge a well with a
specified overhead rate during the drilling phase and also charge a monthly
fixed overhead rate for each producing well. As a result of the additional
operated wells, primarily from our recent acquisitions, the amount recovered by
us as operator overhead charges increased by 19% between the respective second
quarters of 2001 and 2002 and by 22% between the respective first six months.
However, the overhead amount recovered by us as a percent of gross G&A expense
declined in the respective 2002 periods as the drilling activity to date in 2002
has been less than in 2001 as a result of the overall lower commodity prices and
smaller capital budget. Capitalized exploration costs increased between the
comparable periods in 2001 and 2002 along with the increase in gross G&A
expenses and the additional technical personnel added as part
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of the Matrix acquisition, although it is relatively consistent as a percentage
of gross G&A expense. The net effect of the increase in gross G&A expenses,
operator overhead charges and capitalized exploration costs was a 43% increase
in net G&A expense between the second quarters of 2001 and 2002 and a 31%
increase in net G&A expense between the respective first six month periods.
On a per BOE basis, G&A expense increased 13% in the second quarter of 2002
as compared to the second quarter of 2001 due to a lower percentage of G&A
expense recovered through operator overhead charges because of the reduced
drilling activity in 2002. On a per BOE basis, G&A expense was almost identical
between the respective six month periods. As compared to the fourth quarter of
2001, G&A expense per BOE in the first and second quarters of 2002 increased by
approximately $0.28 to $0.30 (38%), primarily as a result of a $1.0 million
reduction in the amount recovered from operator overhead charges as a result of
an overall lower level of development and exploration activity.
Interest and Financing Expenses
Three Months Ended Six Months Ended
June 30, June 30,
- ----------------------------------------------------- ----------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2002 2001 2002 2001
- ----------------------------------------------------- -------------- ------------- ------------ ------------
Interest expense $ 6,572 $ 4,582 $ 13,226 $ 9,245
Non-cash interest expense (650) (283) (1,301) (548)
-------------- ------------- ------------ ------------
Cash interest expense 5,922 4,299 11,925 8,697
Interest and other income (411) (242) (822) (248)
-------------- ------------- ------------ ------------
Net cash interest expense $ 5,511 $ 4,057 $ 11,103 $ 8,449
-------------- ------------- ------------ ------------
Average net cash interest expense per BOE $ 1.70 $ 1.60 $ 1.73 $ 1.71
Average debt outstanding $ 342,593 $ 209,727 $ 342,502 $ 209,564
- ----------------------------------------------------- -------------- ------------- ------------ ------------
Interest expense for the second quarter and first six months of 2002
increased from the comparable prior year periods primarily due to (i) higher
average outstanding debt balances during the first half of 2002 following the
CO2 and Matrix acquisitions in February 2001 and July 2001, respectively, and
(ii) the August 2001 issuance of $75 million of Series B 9% Senior Subordinated
Notes due 2008 which carries a higher interest rate than the bank debt it
replaced, offset in part by decreases throughout 2001 in interest rates on our
variable rate bank debt. During 2001 we borrowed $146 million on our bank credit
facility to partially fund the Matrix Acquisition ($100 million) and the CO2
Acquisition ($42 million). We repaid a total of $79.1 million of our bank
borrowings during 2001, of which (i) $13.0 million related to excess cash flow
generated from operations, and (ii) $65.9 million represented the net proceeds
of our $75 million issuance of Series B 9% Senior Subordinated Notes due 2008,
which closed on August 15, 2001. These notes were issued at a discount, with an
estimated yield to maturity of 10 7/8%. During the first quarter of 2002, we
borrowed $5.1 million to fund a reduction in our net payables but repaid $10.0
million during the second quarter with our excess cash flow.
Interest expense per BOE increased 6% between the respective second
quarters and 1% between the respective six month periods, less than the increase
in gross cost as the absolute increase was partially offset by higher production
levels.
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depletion, Depreciation and Site Restoration
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------------------- ----------------------------- -----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2002 2001 2002 2001
- --------------------------------------------------- ------------- ------------- ------------- --------------
Depletion and depreciation $ 22,383 $ 11,803 $ 43,599 $ 23,297
Depreciation of CO2 assets 613 451 1,139 701
Site restoration provision 789 53 1,563 335
Depreciation of other fixed assets 420 341 830 660
------------- ------------- ------------- --------------
Total DD&A $ 24,205 $ 12,648 $ 47,131 $ 24,993
------------- ------------- ------------- --------------
DD&A per BOE:
Oil and natural gas properties $ 7.17 $ 4.67 $ 7.04 $ 4.79
CO2 assets and other fixed assets 0.32 0.31 0.31 0.27
------------- ------------- ------------- --------------
Total DD&A cost per BOE $ 7.49 $ 4.98 $ 7.35 $ 5.06
- -------------------------------------------------- ------------- ------------- ------------- --------------
Our depletion, depreciation and amortization ("DD&A") rate on a BOE basis
increased from $5.06 per BOE for the first half of 2001 to $7.35 per BOE for the
first half of 2002, which was just slightly higher than the average DD&A rate
per BOE during the second half of 2001. The primary reason for the increase was
the acquisition of Matrix Oil & Gas, Inc. in July 2001. The DD&A rate did
increase slightly in the second quarter of 2002 from the prior quarter due to
the additional capital expenditures made during the first half of 2002 on CO2
properties, the uncertain timing as to when additional proved reserves may be
realized on these properties, and a slight increase in the cost estimates for
the future development costs relating to these tertiary floods. If the COHO
acquisition is consummated as planned (see "Capital Resources and Liquidity"
above), we expect our DD&A rate per BOE to decrease slightly to around $7.15 per
BOE as these properties are being purchased at a rate less than our current DD&A
rate. In addition, the rate may also move significantly up or down in the last
half of 2002 as the DD&A calculation will be adjusted to reflect the impact of
the updated proved reserve estimates as of December 31, 2002.
Income Taxes
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------------- ------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS AND TAX RATES 2002 2001 2002 2001
- ---------------------------------------------------------- ------------ ----------- ------------ ------------
Current income tax expense (benefit) $ 33 $ 400 $ (448) $ 2,400
Deferred income tax expense 6,080 11,412 7,538 24,663
------------ ----------- ------------ ------------
Total income tax expense $ 6,113 $ 11,812 $ 7,090 $ 27,063
------------ ----------- ------------ ------------
Average income tax expense per BOE $ 1.89 $ 4.65 $ 1.11 $ 5.48
Effective tax rate 31.2% 37.0% 28.2% 37.0%
- ---------------------------------------------------------- ------------ ----------- ------------ -------------
Our income tax provisions for the respective three and six month periods
ended June 30, 2002 and 2001 were based on an estimated effective tax rate of
37%. The effective tax rates for the second quarter and first six months of 2002
were lower than 37% due to the recognition of enhanced oil recovery credits
during these periods which lowered our overall effective tax rate. Our effective
tax rate may vary during the remainder of 2002 as changes in oil and natural gas
prices significantly affect our pre-tax operating income and the proportion of
pre-tax income to the amount of enhanced oil recovery credits.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The overall current income tax credit for the first half of 2002 is the
result of a recent tax law change that allowed us to offset 100% of our 2001
alternative minimum taxes with our alternative minimum tax net operating loss
carryforwards. Prior to the law change, we were able to only offset 90% of our
alternative minimum taxes with these carryforwards. This change resulted in a
reclassification of tax expense between current and deferred taxes and did not
impact our overall effective tax rate.
Per BOE Data
The following table summarizes the cash flow, DD&A and results of
operations on a BOE basis for the comparative periods. Each of the individual
components are discussed above.
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------- ---------------------------- --------------------------
Per BOE Data 2002 2001 2002 2001
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Revenue $ 22.00 $ 25.65 $ 19.02 $ 29.06
Gain on settlements of derivative contracts - 0.24 0.41 0.12
Lease operating costs (5.30) (4.89) (5.07) (5.04)
Production taxes and marketing expenses (1.02) (1.00) (0.92) (1.04)
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Production netback 15.68 20.00 13.44 23.10
Operating cash flow from CO2 operations 0.47 0.45 0.45 0.39
General and administrative expenses (1.02) (0.90) (1.01) (1.01)
Net cash interest expense (1.70) (1.60) (1.73) (1.71)
Current income taxes and other - (0.15) 0.06 (0.48)
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Cash flow from operations(1) 13.43 17.80 11.21 20.29
DD&A (7.49) (4.98) (7.35) (5.06)
Deferred income taxes (1.88) (4.49) (1.18) (5.00)
Amortization of derivative contracts and other non-cash
hedging adjustments 0.31 (0.29) 0.33 (0.78)
Other non-cash items (0.20) (0.12) (0.20) (0.11)
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Net income $ 4.17 $ 7.92 $ 2.81 $ 9.34
- -------------------------------------------------------- ------------- ------------- ------------ ------------
(1) Represents cash flow provided by operations, before the changes in assets
and liabilities.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Risk Management
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. We do not hold or issue derivative financial
instruments for trading purposes.
The following table presents the carrying and fair values of our debt,
along with average interest rates. The fair value of our bank debt is considered
to be the same as the carrying value because the interest rate is based on
floating short-term interest rates. The fair value of the subordinated debt is
based on quoted market prices. None of our debt has any triggers or covenants
regarding our debt ratings with rating agencies.
Expected Maturity Dates
- --------------------------------------------- ------------------------------------------------ ----------- -----------
Total Fair
Amounts in Thousands 2002 2003 2004-2007 2008 Value Value
- --------------------------------------------- ------------ ---------- ------------ ----------- ----------- -----------
Variable rate debt:
Bank debt............................... $ - $ 136,000 $ - $ - $ 136,000 $ 136,000
The weighted-average interest rate on the bank debt at June 30, 2002 is 3.67%.
Fixed rate debt:
Subordinated debt....................... $ - $ - $ - $ 200,000 $ 200,000 $ 196,760
The interest rate on the subordinated debt is a fixed rate of 9%.
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. These contracts have historically consisted of price floors, collars
and fixed price swaps. We generally attempt to hedge between 50% and 75% of our
anticipated production each year to provide us with a reasonably certain amount
of cash flow to cover most of our budget without incurring significant debt.
When we make an acquisition, we attempt to hedge 75% to 100% of the forecasted
production for the next year or two following the acquisition in order to help
provide us with a minimum return on our investment. Our hedging activity
includes the purchase of puts or price floors and also instruments like collars
if we think that the ceiling prices are high enough that we are not giving up a
significant portion of the potential upside. For the recent proposed COHO
acquisition, we also used swaps in order to lock-in the prices used in our
economic forecasts which helps protect our rate of return on the acquisition.
All of the mark-to-market valuations used for our financial derivatives are
provided by external sources and are based on prices that are actively quoted.
We manage and control market and counterparty credit risk through established
internal control procedures which are reviewed on an ongoing basis. We attempt
to minimize credit risk exposure to counterparties through formal credit
policies, monitoring procedures, and diversification.
Oil Hedges Historical Data
During 2000, we purchased a $22.00 price floor on our 2001 production
covering 12,800 Bbls/d at an aggregate cost of $1.8 million. This contract
covered approximately 75% of our anticipated 2001 oil production, excluding any
anticipated production from acquisitions. During the first half of 2001, we did
not collect anything on this price floor.
During July 2001, we acquired a $21.00 price floor on 10,000 Bbls/d for
2002 production at an aggregate cost of approximately $4.7 million. This price
floor covered approximately 60% of our then anticipated oil production for 2002.
During the first quarter of 2002, we collected $0.4 million on this price floor,
which was recorded as part of the "Gain on settlements of derivative contracts"
in the Company's Condensed Consolidated Statement of Operations. Nothing was
collected on this contract during the second quarter of 2002.
30
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In May 2002 we acquired collars covering 10,000 Bbls/d during calendar 2003
with a floor price of $20.00 per barrel and a ceiling price of $30.00 per
barrel. Although we have not completed our forecast for 2003, we expect that
these hedges will cover between 40% and 60% of our current expectations for 2003
oil production.
In June 2002 we acquired oil hedges from two different financial
institutions to hedge through 2004 almost 100% of the forecasted proved
developed oil production from the pending COHO acquisition. The oil hedges are
no-cost swaps with an average fixed price of $24.26 per barrel during calendar
2003 and an average fixed price of $22.94 per barrel during calendar 2004. We
also supplemented COHO's 2002 oil hedges that we expect to receive as part of
the COHO asset purchase, by acquiring an oil swap for the fourth quarter of 2002
covering 2,750 Bbls/d at a fixed price of $25.50 per barrel. The existing COHO
hedges that are expected to be included in the acquisition cover 3,750 Bbls/d
for the third quarter of 2002 and 1,250 Bbls/d for the fourth quarter of 2002.
COHO's third quarter hedges have an average floor price of $22.80 and an average
ceiling price of $27.38 per barrel while their fourth quarter hedges have an
average floor price of $22.60 and an average ceiling price of $27.63 per barrel.
Natural Gas Hedges Historical Data
During 2000, we purchased a $2.80 price floor on our 2001 production
covering 37,500 MMBtu/d at an aggregate cost of $0.8 million. This contract
covered approximately 75% of our then anticipated 2001 natural gas production,
excluding any anticipated production from acquisitions. During the first half of
2001, we did not collect anything on this price floor.
At the same time that we acquired Thornwell Field, we purchased price
floors for these predominately natural gas properties that we acquired in the
fourth quarter of 2000. The price floors covered nearly all of the anticipated
proven natural gas production at that time from these properties for 2001 and
2002. These floors cost $2.5 million with varying volumes and price floors each
quarter for 2001 and 2002. During the first half of 2001, we collected $9,000 on
these prices floors, during the first quarter of 2002, we collected $594,000
from these price floors and during the second quarter of 2002, we collected
$12,000. The receipts were recorded as part of the "Gain on settlements of
derivative contracts" in the Company's Condensed Consolidated Statement of
Operations.
For the Matrix properties acquired in July 2001, we attempted to protect
our investment with the purchase of price floors covering nearly all of the
forecasted proven natural gas production through December 2003. We collected
approximately $609,000 on these hedges during the second quarter of 2001. When
Enron filed for bankruptcy during the fourth quarter of 2001 our hedges with
Enron ceased to qualify for hedge accounting treatment as required by Financial
Accounting Standards No. 133, and the accounting treatment changed at that point
in time. This change meant that any changes in the current market value of these
assets must be reflected in our income statement and any remaining accumulated
other comprehensive income (part of equity) left at the time of the accounting
change must be recognized over the original periods the hedging contracts were
to expire. To adjust the Enron hedges down to the current market value, which we
determined to be the amount that we sold the claims for in February 2002, we
took a pre-tax write down of $24.4 million in the fourth quarter of 2001. The
accumulated other comprehensive income previously recorded as part of the
mark-to-market value adjustment each quarter remained to be recognized over 2002
and 2003, the periods during which these hedges would have expired. The result
is that we will have pre-tax income attributable to these Enron hedges during
2002 of approximately $13.4 million and pre-tax income during 2003 of
approximately $5.1 million as we reclassify the balance in accumulated other
comprehensive income relating to these hedges. The three year total pre- tax net
loss will be approximately $5.9 million, which approximates the difference
between the amount collected and paid for the Enron portion of the Matrix price
floors. During the second quarter and first six months of 2002, we recorded
pre-tax income of $3.6 million and $7.2 million, respectively, related to the
Enron hedges in "Amortization of derivative contracts and other non-cash hedging
adjustments" in our Condensed Consolidated Statement of Operations.
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subsequent to the Enron bankruptcy, we purchased additional hedges to
protect against any further deterioration in natural gas prices. These have a
floor price of $2.50 per MMBtu and an average ceiling price of around $4.15 per
MMBtu and cover not only the then anticipated gas production from the Matrix
properties, but a substantial portion of our other natural gas production as
well. Overall, these hedges, which were purchased from four different financial
institutions, cover approximately 75% of our then forecasted total 2002 natural
gas production. We collected additional revenue of $1.6 million during the first
quarter of 2002 from these natural gas hedges which is recorded in "Gain on
settlements of derivative contracts" in our Condensed Consolidated Statement of
Operations. Nothing was collected on these contracts during the second quarter
of 2002.
In February 2002 we acquired no-cost collars from three different financial
institutions covering 70,000 MMBtu/d during calendar 2003 with a floor price of
$2.75 per MMBtu and a weighted average ceiling price of $4.025 per MMBtu.
Although we have not completed our forecast for 2003, we expect that these
hedges will cover between 50% and 75% of our currently anticipated 2003 natural
gas production.
Hedges as of June 30, 2002
The following table lists all of our individual hedges in place as of June
30, 2002.
Crude Oil Contracts:
--------------------
NYMEX Contract Prices Per Bbl
-------------------------------------------------------
Collar Prices Estimated
------------------------- Fair Value at
Type of Contract and Period Bbls/day Swap Price Floor Price Floor Ceiling June 30, 2002
- ------------------------------- ------------ ------------ ------------ ----------- ----------- -----------------
Floor Contracts (thousands)
July 2002 - Dec. 2002 10,000 $ - $ 21.00 $ - $ - $ 496
Swap Contracts
Oct. 2002 - Dec. 2002 2,750 $ 25.50 $ - $ - $ - $ -
Jan. 2003 - Dec. 2003 2,500 24.22 - - - -
Jan. 2003 - Dec. 2003 2,000 24.30 - - - -
Jan. 2004 - Dec. 2004 2,500 22.89 - - - -
Jan. 2004 - Dec. 2004 2,000 23.00 - - - -
Collar Contracts
Jan. 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ 47
Natural Gas Contracts:
- ----------------------
NYMEX Contract Prices Per MMBtu
------------------------------------------------------
Collar Prices Estimated
----------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2002
- ------------------------------- -------------- ------------ -------------- ---------- ----------- -----------------
Floor Contracts (thousands)
July 2002 - Sept. 2002 2,873 $ - $ 3.38 $ - $ - $ 50
Oct. 2002 - Dec. 2002 2,135 - 3.38 - - 59
Collar Contracts
July 2002 - Dec. 2002 40,000 $ - $ - $ 2.50 $ 4.10 $ (788)
July 2002 - Dec. 2002 25,000 - - 2.50 4.20 (766)
July 2002 - Dec. 2002 25,000 - - 2.50 4.17 (502)
Jan. 2003 - Dec. 2003 45,000 - - 2.75 4.00 (6,914)
Jan. 2003 - Dec. 2003 25,000 - - 2.75 4.07 (3,673)
32
At June 30, 2002, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $12.0 million, a decrease of
approximately $35.5 million from the $23.5 million fair value asset recorded as
of December 31, 2001. This change is the result of (i) a decrease in the fair
market value of our hedges due to an increase in oil and natural gas commodity
prices between December 31, 2001 and June 30, 2002, (ii) the settlement received
from our former Enron hedge positions in February 2002, and (iii) the expiration
of certain derivative contracts in the first half of 2002 for which we recorded
amortization expense of $5.1 million.
The balance in accumulated other comprehensive loss of $4.5 million at June
30, 2002, represents the deficit in the fair market value of our contracts as
compared to the cost of our hedges, net of related income taxes, and also
includes the remaining accumulated other comprehensive income relating to the
Enron hedges, as these assets no longer qualify for hedge accounting treatment
due to the Enron bankruptcy. The remaining accumulated other comprehensive
income relating to these Enron hedges will be reclassified in 2002 and 2003,
during the periods that the hedges would have otherwise expired. Of the $4.5
million in accumulated other comprehensive loss as of June 30, 2002, $7.7
million of the deficit relates to current hedging contracts that will expire
within the next 12 months and $2.3 million relates to contracts which expire
subsequent to June 30, 2003. Accumulated other comprehensive loss also includes
$5.5 million related to future income associated with former Enron hedging
contracts that will be reclassified out of accumulated other comprehensive loss
during the next 12 months.
Based on NYMEX natural gas futures prices at June 30, 2002, we would expect
future cash receipts of $3,000 on our natural gas commodity hedges. If natural
gas futures prices were to decline by 10%, the amount we would expect to receive
under our natural gas commodity hedges would increase to $119,000, and if
futures prices were to increase by 10% we would expect to pay $2.8 million.
Based on NYMEX crude oil futures prices at June 30, 2002, we would expect to pay
$1.7 million on our crude oil commodity hedges. If crude oil futures prices were
to decline by 10%, we would expect to receive $7.1 million under our crude oil
commodity contracts, and if crude oil futures prices were to increase by 10%, we
would expect to pay $10.4 million under our crude oil commodity hedges.
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to
property, plant and equipment and to hedging activities, and which remain
unchanged, see our annual report on Form 10-K for the year ended December 31,
2001.
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q ("Quarterly
Report") that are not historical facts, including, but not limited to,
statements found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, acquisition plans and proposals and dispositions, development
activities, cost savings, production efforts and volumes, hydrocarbon reserves,
hydrocarbon prices, liquidity, regulatory matters and competition. Such
forward-looking statements generally are accompanied by words such as "plan,"
"estimate," "budgeted," "expect," "predict," "anticipate," "projected,"
"should," "assume," "believe" or other words that convey the uncertainty of
future events or outcomes. Such forward-looking information is based upon
management's current plans, expectations, estimates and assumptions and is
subject to a number of risks and uncertainties that could significantly affect
current plans, anticipated actions, the timing of such actions and our 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 our oil and natural gas, the uncertainty of
drilling results and reserve estimates, operating hazards,
33
acquisition risks, requirements for capital, general economic conditions,
competition and government regulations, as well as the risks and uncertainties
discussed in this Quarterly Report, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in the
Company's other public reports, filings and public statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- -------------------------------------------------------------------
The information required by Item 3 is set forth under "Market Risk
Management" in Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders
- -----------------------------------------------------------
Denbury's Annual Meeting of Shareholders was held on May 22, 2002 for the
purposes of: 1) the election of nine nominees to serve as Directors of Denbury
for one-year terms to expire at the 2003 Annual Meeting of Shareholders; 2) a
1.6 million share increase in the number of shares issuable under the Company's
Employee Stock Option Plan, and 3) a 500,000 share increase in the number of
shares issuable under the Company's Employee Stock Purchase Plan. At the record
date, April 8, 2002, 53,180,218 shares of common stock were outstanding and
entitled to one vote per share upon all matters submitted at the meeting.
Holders of 47,085,498 shares of common stock, representing 89% of the total
issued and outstanding shares of common stock, were present in person or by
proxy at the meeting to cast their vote.
With respect to the election of directors, the votes were cast as follows:
NOMINEES FOR DIRECTORS FOR WITHHELD
- --------------------------------- ----------------- ------------------
Ronald G. Greene 46,836,800 248,698
David Bonderman 45,532,945 1,552,553
David I. Heather 46,838,760 246,738
David B. Miller 46,841,835 243,663
William S. Price, III 45,533,652 1,551,846
Gareth Roberts 45,527,352 1,558,146
Jeffrey Smith 46,837,135 248,363
Wieland F. Wettstein 46,835,025 250,473
Carrie A. Wheeler 46,832,560 252,938
With respect to the increase in the shares issuable under the Company's Employee
Stock Option Plan, the votes were cast as follows:
FOR AGAINST ABSTENTIONS
- ----------------- ---------------- -------------------
44,229,453 1,198,471 1,657,574
With respect to the increase in the shares issuable under the Company's Employee
Stock Purchase Plan, the votes were cast as follows:
FOR AGAINST ABSTENTIONS
- ----------------- ---------------- -------------------
44,551,441 902,539 1,631,518
34
Item 6. Exhibits and Reports on Form 8-K during the Second Quarter of 2002
- ---------------------------------------------------------------------------
Exhibits:
---------
15* Letter from Independent Accountants as to unaudited interim
financial information.
99.1* Certification of Chief Executive Officer and Chief Financial
Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
* Filed herewith.
Reports on Form 8-K:
--------------------
On May 22, 2002, the Company filed a Current Report on Form 8-K announcing
that it had acquired Genesis Energy L.L.C., which acts as the general partner of
Genesis Energy, L.P.
35
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DENBURY RESOURCES INC.
(Registrant)
By: /s/ Phil Rykhoek
--------------------------------------
Phil Rykhoek
Chief Financial Officer
By: /s/ Mark C. Allen
--------------------------------------
Mark C. Allen
Chief Accounting Officer & Controller
Date: August 13, 2002
36