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 SEPTEMBER 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 OCTOBER 31, 2002
----- -------------------------------
Common Stock, $.001 par value 53,454,558
DENBURY RESOURCES INC.
INDEX
Page
----
Part I. Financial Information
Item 1. Financial Statements
Independent Accountants' Report 3
Condensed Consolidated Balance Sheets at September 30, 2002 (Unaudited)
and December 31, 2001 4
Condensed Consolidated Statements of Operations for the Three and Nine Months
Ended September 30, 2002 and 2001 (Unaudited) 5
Condensed Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 2002 and 2001 (Unaudited) 6
Notes to Condensed Consolidated Financial Statements 7-19
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 20-34
Item 3. Quantitative and Qualitative Disclosures about Market Risk 35
Item 4. Controls and Procedures 35
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 35
Signatures 36
Certifications 37-38
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 September 30,
2002, and the related condensed consolidated statements of operations for the
three and nine month periods ended September 30, 2002 and 2001 and cash flows
for the nine month periods ended September 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
November 5, 2002
3
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
September 30, December 31,
2002 2001
---------------- ---------------
(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 22,924 $ 23,496
Accrued production receivables 31,908 22,823
Trade and other receivables 12,293 32,512
Derivative assets 41 23,458
Deferred tax asset 35,802 989
------------ -----------
Total current assets 102,968 103,278
------------ -----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties (using full cost accounting)
Proved 1,217,172 1,098,263
Unevaluated 51,296 44,521
CO2 properties and equipment 57,317 45,555
Less accumulated depletion and depreciation (586,968) (520,332)
------------ -----------
Net property and equipment 738,817 668,007
------------ -----------
INVESTMENT IN GENESIS ENERGY, INC. 2,191 -
OTHER ASSETS 18,289 18,703
NON-CURRENT DERIVATIVE ASSETS 483 -
------------ -----------
TOTAL ASSETS $ 862,748 $ 789,988
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 33,258 $ 66,491
Oil and gas production payable 14,467 13,447
Derivative liabilities 16,676 -
------------ -----------
Total current liabilities 64,401 79,938
------------ -----------
LONG-TERM LIABILITIES
Long-term debt 369,641 334,769
Provision for site reclamation costs 6,264 4,318
Derivative liabilities 5,918 -
Deferred tax liability 54,505 18,422
Other liabilities 3,085 3,373
------------ -----------
Total long-term liabilities 439,413 360,882
------------ -----------
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;
53,442,188 and 52,956,825 shares issued and outstanding at September
30, 2002 and December 31, 2001, respectively 53 53
Paid-in capital in excess of par 395,049 391,557
Accumulated deficit (25,167) (56,670)
Accumulated other comprehensive income (loss) (11,001) 14,228
------------ -----------
Total stockholders' equity 358,934 349,168
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 862,748 $ 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 Nine Months Ended
September 30, September 30,
--------------------------- -------------------------
2002 2001 2002 2001
------------- ------------- ------------ ------------
REVENUES
Oil, natural gas and related product sales $ 72,153 $ 65,554 $ 194,177 $ 208,992
CO2 sales 2,182 1,455 5,568 3,738
Gain (loss) on settlements of derivative contracts (218) 7,217 2,430 7,835
Interest and other income 407 92 1,229 340
------------- ------------- ------------ ------------
Total revenues 74,524 74,318 203,404 220,905
------------- ------------- ------------ ------------
EXPENSES
Lease operating costs 17,714 14,671 50,266 39,558
Production taxes and marketing expenses 2,969 3,292 8,880 8,432
CO2 operating costs 431 373 960 708
General and administrative 2,692 2,519 8,474 6,924
Interest 6,860 6,330 20,086 15,575
Depletion and depreciation 23,031 22,694 70,162 47,687
Amortization of derivative contracts and other
non-cash hedging adjustments (1,133) 1,969 (3,226) 5,833
Franchise taxes 342 330 1,070 905
------------- ------------- ------------ ------------
Total expenses 52,906 52,178 156,672 125,622
------------- ------------- ------------ ------------
EQUITY IN NET INCOME OF GENESIS ENERGY, INC. 2 - 22 -
------------- ------------- ------------ ------------
INCOME BEFORE INCOME TAXES 21,620 22,140 46,754 95,283
INCOME TAX PROVISION (BENEFIT)
Current income taxes 20 (1,500) (428) 900
Deferred income taxes 8,141 9,692 15,679 34,355
------------- ------------- ------------ ------------
NET INCOME $ 13,459 $ 13,948 $ 31,503 $ 60,028
============= ============= ============ ============
NET INCOME PER COMMON SHARE
Basic $ 0.25 $ 0.27 $ 0.59 $ 1.25
Diluted 0.25 0.26 0.58 1.22
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic 53,354 52,169 53,170 48,127
Diluted 54,562 53,154 54,193 49,244
(See accompanying notes to Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
(Unaudited)
Nine Months Ended
September 30,
----------------------------------
2002 2001
------------- ------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income $ 31,503 $ 60,028
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 70,162 47,687
Amortization of derivative contracts and other non-cash hedging adjustments (3,226) 5,833
Deferred income taxes 15,679 34,355
Amortization of debt issue costs and other 2,006 943
------------- ------------
116,124 148,846
Changes in assets and liabilities:
Accrued production receivable (9,085) 15,613
Trade and other receivables 20,576 (17,187)
Derivative assets and liabilities 8,426 (22,712)
Other assets (228) (1,509)
Accounts payable and accrued liabilities (33,233) 20,276
Oil and gas production payable 1,020 (3,705)
Other liabilities (617) 2,450
------------- ------------
NET CASH PROVIDED BY OPERATIONS 102,983 142,072
------------- ------------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures (76,094) (113,613)
Acquisitions of oil and gas properties (53,242) (93,124)
Investment in Genesis Energy, Inc. (2,169) -
Acquisitions of CO2 assets and capital expenditures (11,393) (44,991)
Increase in restricted cash (621) (2,217)
Proceeds from disposition of oil and gas properties 4,552 -
Net purchases of other assets (853) (1,330)
------------- ------------
NET CASH USED FOR INVESTING ACTIVITIES (139,820) (255,275)
------------- ------------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments (15,000) (79,130)
Bank borrowings 49,130 126,000
Issuance of subordinated debt - 68,652
Issuance of common stock 2,854 2,041
Costs of debt financing (719) (2,916)
------------- ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES 36,265 114,647
------------- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (572) 1,444
Cash and cash equivalents at beginning of period 23,496 22,293
------------- ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 22,924 $ 23,737
============= ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest $ 22,879 $ 15,778
Cash paid (refunded) during the period for income taxes (1,305) 1,776
Common stock issued in Matrix acquisition (non-cash) - 59,195
(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 unaudited condensed consolidated financial statements of
Denbury Resources Inc. and its subsidiaries have been prepared in accordance
with the instructions to Form 10-Q and do not include all of the information and
footnotes required by accounting principles generally accepted in the United
States for complete financial statements. Unless indicated otherwise or the
context requires, the terms "we," "our," "us," "Denbury" or "Company" refers to
Denbury Resources Inc. and its subsidiaries. These financial statements and the
notes thereto should be read in conjunction with our 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 nine month periods ended September 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 our opinion, the accompanying unaudited condensed consolidated
financial statements include all adjustments (of a normal recurring nature)
necessary to present fairly the consolidated financial position of Denbury as of
September 30, 2002 and the consolidated results of its operations for the three
and nine months ended September 30, 2002 and 2001 and its cash flows for the
nine months ended September 30, 2002 and 2001. Certain prior period items have
been reclassified to make the classification consistent with this quarter.
On May 14, 2002, a newly-formed subsidiary of Denbury 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. We are accounting for our ownership and interest in Genesis
Energy, L.P. under the equity method of accounting. See Note 4, "Acquisition of
Genesis Energy, L.L.C.," for further information regarding the acquisition and
summary financial information of 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 nine month periods ended September 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 nine month periods ended September 30, 2002 and 2001(shares in
thousands).
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
-------------- -------------- ------------- ------------
Weighted average common shares - basic 53,354 52,169 53,170 48,127
Potentially dilutive securities:
Stock options 1,208 985 1,023 1,117
-------------- -------------- ------------- ------------
Weighted average common shares - diluted 54,562 53,154 54,193 49,244
============== ============== ============= ============
7
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2002, additional options
outstanding to purchase 1.3 million and 2.1 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 Denbury's common stock during these periods. For the three and nine
months ended September 30, 2001, additional options outstanding to purchase 1.9
million and 1.3 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 Denbury'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. This standard is effective for us 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.
We have 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 us
beginning January 1, 2002 and has not had any impact on our 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.
2. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
September 30, December 31,
2002 2001
--------------- ---------------
(Amounts in thousands)
(Unaudited)
Senior bank loan $ 175,000 $ 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 (5,359) (6,101)
--------------- ---------------
Total long-term debt $ 369,641 $ 334,769
=============== ===============
8
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
In September 2002, we entered into a Third Amended and Restated Credit
Agreement with our banks which extended the maturity of our bank credit facility
from December 2003 to April 2006. In conjunction with the amended credit
agreement, Bank One became the new administrative agent bank and the facility
borrowing base remained at $220 million, leaving a borrowing capacity of
approximately $45 million as of September 30, 2002. There were no other
significant changes to the amended and restated credit agreement. Our bank
credit facility provides for a semi-annual redetermination of the borrowing base
on April 1st and October 1st.
3. ACQUISITION OF COHO PROPERTIES
In August 2002, we acquired COHO Energy Inc.'s Gulf Coast properties
auctioned in the U.S. Bankruptcy Court in Dallas, Texas. Our net purchase price,
adjusted for interim cash flow from the June 1, 2002 effective date, together
with purchase adjustments to date, was $48.2 million and included nine fields,
eight of which are located in Mississippi and one in Texas. Seven of the eight
Mississippi fields and the one Texas field are operated by us. Our initial
estimates indicate the acquisition includes net proven reserves of approximately
14.4 million barrels of oil with current production, net to Denbury, of between
4,000 and 4,500 barrels of oil per day. The Mississippi fields include interests
in the Brookhaven, Laurel, Martinville, Soso and Summerland fields, with such
interests representing operational control with working interests in excess of
90%, plus interests in the smaller Bentonia, Cranfield and Glazier fields. 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 (i.e.
forward sales). The average fixed price for the last three months of 2002 is
$25.50 per barrel, and for 2003 is $24.27 per barrel and for 2004 is $22.94 per
barrel.
4. ACQUISITION OF GENESIS ENERGY, L.L.C.
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 $2.2 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 that we acquired owns a 2% interest in Genesis. We are
accounting for our ownership in Genesis under the equity method of accounting as
we have significant influence over the limited partnership as a result of our
ownership of the general partner interest, but because of the terms of the
partnership agreement, we do not meet the criteria for control which would
require us to consolidate the limited partnership. Our equity in Genesis' net
income for the third quarter of 2002 and year-to-date 2002 was $2,000 and
$22,000, respectively, representing 2% of Genesis' net income for the third
quarter of 2002 and for the period from May 15, 2002 through September 30, 2002.
Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed
the bank debt of Genesis, which had no outstanding borrowings as of September
30, 2002 except for $30.8 million in letters of credit of which $9.0 million
secure purchases from Denbury. There are no guarantees by Denbury or any of its
other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. Denbury's
investment of $2.2 million exceeded our percentage of net equity in the limited
partnership at the time of acquisition by approximately $1.0 million, which
represents goodwill and is not subject to amortization.
Genesis has historically been a purchaser of crude oil from Denbury and
future purchases of our crude oil production by Genesis are anticipated. For the
nine months ended September 30, 2002, we recorded sales to Genesis of $19.6
million and at September 30, 2002, had a production receivable from Genesis of
$4.3 million. For the year ended December 31, 2001, Genesis purchased
approximately 17% of our crude oil production and accounted for 8% of our total
oil and natural gas revenues.
9
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information of Genesis Energy L.P. is as follows (amounts in thousands):
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2002
------------------- --------------------
Revenues $ 216,350 $ 696,358
Cost of sales 211,582 679,930
Other expenses 4,665 12,905
------------------- --------------------
Net income $ 103 $ 3,523
=================== ====================
September 30, December 31,
2002 2001
------------------- --------------------
Current assets $ 84,986 $ 182,100
Non-current assets 43,393 48,013
------------------- --------------------
Total assets $ 128,379 $ 230,113
=================== ====================
Current liabilities $ 92,332 $ 183,689
Non-current liabilities 515 14,415
Partners' capital 35,532 32,009
------------------- --------------------
Total liabilities and
partners' capital $ 128,379 $ 230,113
=================== ====================
5. ACQUISITION OF MATRIX OIL AND GAS, INC.
On July 10, 2001, Denbury 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
$157.4 million, comprised of $98.2 million (63%) in cash and $59.2 million (37%)
in the form of 6.6 million shares of Denbury's common stock, including
post-closing adjustments. The acquired operations of Matrix were reflected in
our financial results beginning July 1, 2001.
The following pro forma information reflects the consolidated results of
operations for the nine months ended September 30, 2001, based upon adjustments
to the historical financial statements of Denbury and the historical financial
statements of Matrix to give effect to the acquisition as if such acquisition
had occurred on January 1, 2001 (in thousands, except per share data):
Nine Months
Ended
September 30,
2001
-----------------
Operating revenues $ 260,195
Net income 64,019
Income per common share:
Basic $ 1.21
Diluted 1.19
10
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6. COMPREHENSIVE INCOME
The following tables present comprehensive income for the three and nine month periods ended September 30, 2002.
Three Months Ended
(Amounts in thousands) September 30, 2002
-----------------------------------
Accumulated other comprehensive loss - June 30, 2002 $ (4,488)
Net income $ 13,459
Other comprehensive loss - net of tax
Reclassification adjustments related to derivative contracts (1,993)
Amortization of derivative contracts 1,457
Change in fair value of outstanding hedging positions (5,977)
---------------
Total other comprehensive loss (6,513) (6,513)
--------------- --------------
Comprehensive income $ 6,946
===============
Accumulated other comprehensive loss - September 30, 2002 $ (11,001)
==============
Nine Months Ended
(Amounts in thousands) September 30, 2002
-----------------------------------
Accumulated other comprehensive income - December 31, 2001 $ 14,228
Net income $ 31,503
Other comprehensive loss - net of tax
Reclassification adjustments related to derivative contracts (6,539)
Amortization of derivative contracts 4,684
Change in fair value of outstanding hedging positions (23,374)
---------------
Total other comprehensive loss (25,229) (25,229)
--------------- --------------
Comprehensive income $ 6,274
===============
Accumulated other comprehensive loss - September 30, 2002 $ (11,001)
==============
11
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following tables present comprehensive income for the three and nine month periods ended September 30, 2001.
Three Months Ended
(Amounts in thousands) September 30, 2001
-----------------------------------
Accumulated other comprehensive income - June 30, 2001 $ 9,769
Net income $ 13,948
Other comprehensive income - net of tax
Reclassification adjustments related to derivative contracts (78)
Change in fair value of outstanding hedging positions 8,281
---------------
Total other comprehensive income 8,203 8,203
--------------- --------------
Comprehensive income $ 22,151
===============
Accumulated other comprehensive income - September 30, 2001 $ 17,972
==============
Nine Months Ended
(Amounts in thousands) September 30, 2001
-----------------------------------
Accumulated other comprehensive income - December 31, 2000 $ -
Net income $ 60,028
Other comprehensive income - net of tax
Cumulative effect of change in accounting principle - January 1, 2001 1,012
Reclassification adjustments related to derivative contracts (934)
Change in fair value of outstanding hedging positions 17,894
---------------
Total other comprehensive income 17,972 17,972
--------------- --------------
Comprehensive income $ 78,000
===============
Accumulated other comprehensive income - September 30, 2001 $ 17,972
==============
7. PRODUCT PRICE HEDGING CONTRACTS
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. These hedge contracts are purchased to either protect our 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 our financial
derivatives are provided by external sources and are based on prices that are
actively quoted. We attempt to manage and control market and counterparty credit
risk through established internal control procedures which are reviewed on an
ongoing basis. We also minimize our credit risk exposure to counterparties
through formal credit policies, monitoring procedures, and diversification.
On January 1, 2001, we 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.
12
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Upon adoption on January 1, 2001, we recorded a $1.6 million increase in
assets for the fair value of our price 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 fair value of our derivative contracts decreased by
$4.1 million. We recognized this loss as a $3.1 million loss in "Amortization of
derivative contracts and other non-cash hedging adjustments" in our 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 third 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 third quarter of 2001 we have
been amortizing our derivative contract premiums over the periods during which
the contracts expire. During the third quarter and first nine months of 2002,
this resulted in the amortization of $2.3 million and $7.4 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 $3.4 million and $10.7 million
for the three and nine months ended September 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, we purchased a $22.00 per barrel 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 nine
months of 2001, we did not collect anything on this price floor.
During July 2001, we acquired a $21.00 per barrel 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 $462,000 on
this price floor, which was recorded in "Gain (loss) on settlements of
derivative contracts" in our Condensed Consolidated Statement of Operations.
Nothing was collected on this contract during the second or third quarters of
2002.
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.
In June 2002, we acquired oil hedges from two different financial
institutions to hedge almost 100% of the forecasted proved developed oil
production from the then pending COHO acquisition for 2003 and 2004. The oil
hedges are no- cost swaps with an average fixed price of $24.27 per barrel
during calendar 2003 and an average fixed price of $22.94 per barrel during
calendar 2004. In addition, we supplemented COHO's 2002 oil hedges that we
received 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 we received as part of the acquisition
cover 1,250 Bbls/d for the fourth quarter of 2002 and have an average floor
price of $22.60 and an average ceiling price of $27.63 per barrel.
In September 2002, we acquired oil hedges from three different financial
institutions to hedge 2,000 Bbls/d for 2003 at a fixed price (i.e. swap) of
$25.70 per barrel and 5,000 Bbls/d for 2004 at an average fixed price (i.e.
swap) of $23.04 per barrel. In the aggregate, we have oil hedges in place to
cover between 75% and 85% of our currently anticipated 2003 oil production and
between 40% and 50% of our currently anticipated 2004 oil production.
13
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Natural Gas Hedges Historical Data
During 2000, we purchased a $2.80 per MMBtu 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 nine months of 2001 we collected $430,000 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 nine months of 2001 and 2002, we
collected $917,000 and $646,000, respectively, on these prices floors. During
the third quarter of 2001 and 2002, we collected $908,000 and $40,000,
respectively, from these price floors.
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 $5.9 million on these hedges during the third 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 SFAS
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 third quarter and first nine months of 2002, we recorded
pre-tax income of $3.4 million and $10.7 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.
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 (loss)
on settlements of derivative contracts" in our Condensed Consolidated Statement
of Operations. Nothing was paid or received on these contracts during the second
or third quarters of 2002.
In February 2002, we acquired no-cost collars from three different
financial institutions covering 70,000 MMBtu/d for calendar year 2003 with a
floor price of $2.75 per MMBtu and a weighted average ceiling price of $4.025
per MMBtu.
In September 2002, we acquired natural gas hedges for 2003 and 2004 from
three different financial institutions. The hedges for 2003 consist of a fixed
price (i.e. swap) of $3.905 for 10,000 MMBtu/d and a no-cost collar covering
30,000 MMBtu/d for 2004 with a floor price of $3.50 and a ceiling price of
$4.45. In the aggregate, we have natural gas hedges to cover between 65% and 75%
of our currently anticipated 2003 natural gas production and between 20% and 30%
of our currently anticipated 2004 natural gas production.
14
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table lists all of the Company's individual hedges in place as of September 30, 2002.
CRUDE OIL CONTRACTS:
- -------------------
NYMEX Contract Prices Per Bbl
-------------------------------------------------------
Collar Prices Estimated
------------------------- Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling September 30,
- ------------------------------- ------------ ------------ ------------ ----------- ----------- -----------------
Floor Contracts (thousands)
Oct. 2002 - Dec. 2002 10,000 $ - $ 21.00 $ - $ - $ 17
Collar Contracts
Oct. 2002 - Dec. 2002 1,250 $ - $ - $ 22.60 $ 27.63 $ (334)
Jan. 2003 - Dec. 2003 10,000 - - 20.00 30.00 (1,759)
Swap Contracts
Oct. 2002 - Dec. 2002 2,750 $ 25.50 $ - $ - $ - $ (1,136)
Jan. 2003 - Dec. 2003 2,500 24.25 - - - (1,506)
Jan. 2003 - Dec. 2003 2,000 24.30 - - - (1,170)
Jan. 2003 - Dec. 2003 2,000 25.70 - - - (112)
Jan. 2004 - Dec. 2004 2,500 22.89 - - - (276)
Jan. 2004 - Dec. 2004 4,500 23.00 - - - (323)
Jan. 2004 - Dec. 2004 2,500 23.08 - - - (107)
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 September 30,
- ------------------------------- ------------ ------------ ------------ ----------- ----------- -----------------
Floor Contracts (thousands)
Oct. 2002 - Dec. 2002 2,135 $ - $ 3.38 $ - $ - $ 5
Collar Contracts
Oct. 2002 - Dec. 2002 40,000 $ - $ - $ 2.50 $ 4.10 $ (972)
Oct. 2002 - Dec. 2002 25,000 - - 2.50 4.20 (820)
Oct. 2002 - Dec. 2002 25,000 - - 2.50 4.17 (549)
Jan. 2003 - Dec. 2003 45,000 - - 2.75 4.00 (8,044)
Jan. 2003 - Dec. 2003 25,000 - - 2.75 4.07 (4,189)
Jan. 2004 - Dec. 2004 30,000 - - 3.50 4.45 (203)
Swap Contracts
Jan. 2003 - Dec. 2003 10,000 $ 3.905 $ - $ - $ - $ (592)
At September 30, 2002, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $22.1 million, a decrease of
approximately $45.6 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 September 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 nine months of 2002 for
which we recorded amortization expense of $7.4 million.
The balance in accumulated other comprehensive loss of $11.0 million at
September 30, 2002, represents the deficit in the fair market value of our
derivative contracts as compared to the cost of our hedges, net of income taxes,
and also
15
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 $11.0
million in accumulated other comprehensive loss as of September 30, 2002, $11.9
million of the deficit relates to current hedging contracts that will expire
within the next 12 months and $3.9 million relates to contracts which expire
subsequent to September 30, 2003. Accumulated other comprehensive loss also
includes $4.2 million and $602,000 related to future income associated with the
former Enron hedging contracts that will be reclassified out of accumulated
other comprehensive loss during the next 12 months and subsequent to September
30, 2003, respectively.
8. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of August 2001, all of our subordinated debt securities were fully and
unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries.
Condensed consolidating financial information for Denbury Resources Inc. and its
significant subsidiaries as of September 30, 2002 and December 31, 2001 and for
the three and nine months ended September 30, 2002 and 2001 is as follows:
Condensed Consolidating Balance Sheets
September 30, 2002 (Unaudited)
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- ------------- --------------
ASSETS
Current assets..................................$ 83,323 $ 19,645 $ - $ 102,968
Property and equipment.......................... 530,107 208,710 - 738,817
Investment in subsidiaries (equity method)...... 167,819 2,191 (167,819) 2,191
Other assets.................................... 15,327 3,445 - 18,772
-------------- ------------- ------------- --------------
Total assets...............................$ 796,576 $ 233,991 $ (167,819) $ 862,748
============== ============= ============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities.............................$ 56,957 $ 7,444 $ - $ 64,401
Long-term liabilities........................... 380,685 58,728 - 439,413
Stockholders' equity............................ 358,934 167,819 (167,819) 358,934
-------------- ------------- ------------- --------------
Total liabilities and stockholders' equity.$ 796,576 $ 233,991 $ (167,819) $ 862,748
============== ============= ============= ==============
16
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
============== ============= ============== ==============
Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2002 (Unaudited)
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- -------------- --------------
Revenues..................................... $ 61,264 $ 13,260 $ - $ 74,524
Expenses..................................... 41,381 11,525 - 52,906
-------------- ------------- -------------- --------------
Income before the following: 19,883 1,735 - 21,618
Equity in net earnings of subsidiaries.. 1,016 2 (1,016) 2
-------------- ------------- -------------- --------------
Income (loss) before income taxes............ 20,899 1,737 (1,016) 21,620
Income tax provision......................... 7,440 721 - 8,161
-------------- ------------- -------------- --------------
Net income (loss)............................ $ 13,459 $ 1,016 $ (1,016) $ 13,459
============== ============= ============== ==============
Three Months Ended September 30, 2001 (Unaudited)
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------- ------------- --------------
Revenues..................................... $ 61,191 $ 13,127 $ - $ 74,318
Expenses..................................... 42,931 9,247 - 52,178
--------------- ------------- ------------- --------------
Income before the following: 18,260 3,880 - 22,140
Equity in net earnings of subsidiaries.. 2,804 - (2,804) -
--------------- ------------- ------------- --------------
Income (loss) before income taxes............ 21,064 3,880 (2,804) 22,140
Income tax provision......................... 7,116 1,076 - 8,192
--------------- ------------- ------------- --------------
Net income (loss)............................ $ 13,948 $ 2,804 $ (2,804) $ 13,948
=============== ============= ============= ==============
17
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Nine Months Ended September 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 163,713 $ 39,691 $ - $ 203,404
Expenses..................................... 120,254 36,418 - 156,672
--------------- -------------- -------------- --------------
Income before the following: 43,459 3,273 - 46,732
Equity in net earnings of subsidiaries.. 1,966 22 (1,966) 22
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 45,425 3,295 (1,966) 46,754
Income tax provision......................... 13,922 1,329 - 15,251
--------------- -------------- -------------- --------------
Net income (loss)............................$ 31,503 $ 1,966 $ (1,966) $ 31,503
=============== ============== ============== ==============
Nine Months Ended September 30, 2001 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 208,142 $ 12,763 $ - $ 220,905
Expenses..................................... 116,426 9,196 - 125,622
--------------- -------------- -------------- --------------
Income before the following: 91,716 3,567 - 95,283
Equity in net earnings of subsidiaries.. 2,491 - (2,491) -
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 94,207 3,567 (2,491) 95,283
Income tax provision......................... 34,179 1,076 - 35,255
--------------- -------------- -------------- --------------
Net income (loss)............................$ 60,028 $ 2,491 $ (2,491) $ 60,028
=============== ============== ============== ==============
Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Cash flow from operations....................$ 97,878 $ 5,105 $ - $ 102,983
Cash flow from investing activities.......... (130,690) (9,130) - (139,820)
Cash flow from financing activities.......... 36,265 - - 36,265
--------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... 3,453 (4,025) - (572)
Cash, beginning of period.................... 17,052 6,444 - 23,496
--------------- -------------- -------------- --------------
Cash, end of period..........................$ 20,505 $ 2,419 $ - $ 22,924
=============== ============== ============== ==============
18
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Nine Months Ended September 30, 2001 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 127,566 $ 14,506 $ - $ 142,072
Cash flow from investing activities.......... (249,293) (5,982) - (255,275)
Cash flow from financing activities.......... 114,647 - - 114,647
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... (7,080) 8,524 - 1,444
Cash, beginning of period.................... 22,286 7 - 22,293
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 15,206 $ 8,531 $ - $ 23,737
================= ============== ============== ==============
19
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
that we acquire in our core areas through a combination of exploitation,
drilling and proven engineering extraction processes, including secondary
(waterflooding) and tertiary (carbon dioxide or CO2 injection) recovery
techniques.
RECENT EVENTS
ACQUISITION OF CERTAIN COHO PROPERTIES: In August 2002, we acquired COHO
Energy Inc.'s Gulf Coast properties auctioned in the U.S. Bankruptcy Court in
Dallas, Texas. Our net purchase price, adjusted for interim cash flow from the
June 1, 2002 effective date, together with purchase adjustments to date, was
$48.2 million and included nine fields, eight of which are located in
Mississippi and one in Texas. Seven of the eight Mississippi fields and the one
Texas field are operated by us. Our initial estimates indicate the acquisition
includes net proven reserves of approximately 14.4 million barrels of oil with
current production, net to us, of between 4,000 and 4,500 barrels of oil per
day. The Mississippi fields include interests in the Brookhaven, Laurel,
Martinville, Soso and Summerland fields, with such interests representing
operational control with working interests in excess of 90%, plus interests in
the smaller Bentonia, Cranfield and Glazier fields. 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 (i.e. forward sales). The average
fixed price for the last three months of 2002 is $25.50 per barrel, and for 2003
is $24.27 per barrel and for 2004 is $22.94 per barrel.
We are attempting to sell Laurel, Bentonia and Glazier fields, along with
some minor properties we have owned for several years before year-end 2002,
assuming that, in our opinion, the bids we receive for the properties are
adequate. The estimated aggregate proved reserves of the fields that may be sold
is approximately 8.0 million barrels, with current production of approximately
2,300 BOE/d. We currently estimate that these sales will produce net proceeds of
up to $45 million, depending on the level of interest, commodity prices at the
time, and the bids that we obtain. We plan to use any proceeds that we obtain
from property sales to reduce our bank debt.
We have been able to substantially improve the pricing (relative to NYMEX)
for the crude oil sold from the COHO properties since its acquisition. Our sales
prices for October 2002 production from these properties increased by
approximately $3.40 per barrel over the prices that COHO was receiving per
barrel earlier in the year (relative to NYMEX). This translates into a 50%
increase in the PV10 Value of the acquisition, using constant prices and the
futures price strip as of early September 2002. This additional value was
possible due to our prominence in the area (we are the largest oil and natural
gas producer in Mississippi), coupled with the strategic benefits of acquiring
the general partner of Genesis Energy, L.P., which provides us an alternative
market for our production because of their pipeline in the area.
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 $2.2 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. Genesis was a strategic acquisition for us because of a crude
oil pipeline they own in Mississippi near several of our significant oil fields.
We believe that Genesis may be in the position to serve as a future financier
and developer of our gathering systems, CO2 and crude oil pipelines and other
midstream assets.
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We are accounting for our investment in Genesis under the equity method of
accounting, which increased our net income for the third quarter and first nine
months of 2002 by $2,000 and $22,000, respectively. We have included in the
footnotes to the consolidated financial statements summarized financial
information of Genesis (see Note 4 to the consolidated financial statements).
Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed
the bank debt of Genesis, which as of September 30, 2002 had no outstanding
borrowings except for $30.8 million in letters of credit of which $9.0 million
secure purchases from Denbury. There are no guarantees by Denbury or any of its
other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
Capital Resources and Liquidity
During the first nine months of 2002, we spent $76.1 million on oil and
natural gas property expenditures, $11.4 million on CO2 capital investments, and
approximately $53.2 million of oil and natural gas property acquisitions, the
largest being the acquisition of properties from COHO Energy, Inc. (see
"Acquisition of certain COHO properties"). Our cash flow from operations (before
changes in assets and liabilities) for the same nine month period totaled $116.1
million. As such, cash flow was sufficient to fund the oil and natural gas and
CO2 property expenditures and also funded $8.1 million of the acquisitions and
approximately $20.5 million to increase our working capital since December 31,
2001 (excluding derivative assets and liabilities and deferred tax assets). The
$45.1 million balance of the acquisitions was funded by a net increase of $34.1
million in our bank debt, proceeds from property sales and other net sources of
working capital.
We anticipate that our capital spending, excluding any possible
acquisitions, during both the fourth quarter of 2002 and for the year will be
equal to or less than our cash flow generated from operations, as has been our
policy since 1999. For the year, we currently have budgeted $113 million of new
development and exploratory projects for 2002, plus a carry over of
approximately $6 million of projects from 2001. Based on current projections,
using futures prices in place as of the first part of November 2002, this
spending level is expected to be as much as $40 million to $50 million below our
forecasted cash flow, depending 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 for 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.
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 small acquisitions that are near our CO2 pipeline in Western Mississippi
and Northeastern Louisiana and individual fields in the Gulf of Mexico. Although
we now control most of the fields along our CO2 pipeline, there are a few
remaining fields with potential, plus we are continuing to acquire additional
interests in the fields that we do own. We have targeted the acquisition of
offshore blocks, which generally consist of one or two fields, where we see
additional potential based on our review of 3D seismic or other geologic and
geophysical data. Although we are continuing to look at acquisitions in our
other core areas, including larger acquisitions, this is a lower priority for us
than has been the case historically, given our good inventory of projects
in-house and our goal to reduce our debt level over the next several months. Any
acquisitions that we make will likely be funded with either our excess cash flow
or bank debt.
In September 2002, we extended the maturity of our bank line from December
2003 to April 2006. The bank borrowing base was left unchanged at $220 million
and generally the same banks remained in the line, although Bank One became the
new administrative agent bank. Our bank borrowing base is set by our banks at
their sole discretion based on various factors, some of which are out of our
control. As of November 7, 2002, we had $175 million of bank debt outstanding,
leaving us $45 million of current bank line availability. The next borrowing
base review by the banks will be April 1, 2003. We currently do not anticipate
any significant change in the borrowing base at the next redetermination, 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 we acquired from COHO, as we
anticipate that we will be able to reduce our debt levels during
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the next several months, providing us with additional availability on our
existing borrowing base. We plan to do this with funds from proposed property
sales (see "Acquisition of certain COHO properties" above) 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. Although subject to semi-annual
reaffirmation, our bank debt is not due until April 2006, 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 obligations for
development and exploratory expenditures arising from purchase agreements or
other transactions common to our industry, none of which have changed materially
since December 31, 2001. Our industry related commitments generally relate to
projects that will occur during the subsequent year and are part of our annual
budget process which we can scale up or down based on commodity prices,
available capital, etc. Our capital spending obligations total approximately
$14.2 million over the next five years, of which no obligations remain in 2002
and $2.5 million is required to be spent in 2003. At September 30, 2002, we had
a total of $370,000 outstanding in letters of credit. We do not have any
material transactions with related parties other than sales of production to
Genesis Energy, L.P. as discussed in Note 4 to the consolidated financial
statements.
Long-term contracts require us to deliver CO2 to our industrial CO2
customers. Based upon the current level of deliveries, we estimate that we may
be obligated to deliver up to 310 Bcf of CO2 to these customers over the next 18
years; however, our commitments could be reduced to approximately 130 Bcf under
certain conditions. Given the size of our proven CO2 reserves (approximately 800
Bcf) and our current production capabilities, we are confident that we can meet
these delivery obligations.
We have oil price floors, collars and swaps that cover 50% to 60% of our
currently expected 2002 oil production, 75% to 85% of our currently anticipated
2003 oil production and 40% to 50% of our currently anticipated 2004 oil
production. We also have natural gas floors, collars and swaps covering 80% to
85% of our currently expected 2002 natural gas production, 65% to 75% of our
currently anticipated 2003 natural gas production and 20% to 30% of our
currently anticipated 2004 natural gas production. Included in those production
estimates are hedges for nearly 100% of the forecasted proved developed
production from the COHO acquisition through 2004 (see also Note 7 to the
consolidated financial statements 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
and some represent current and future obligations based on current oil and
natural gas future prices, but they do offer significant protection should
commodity prices drop in the future.
SOURCES AND USES OF FUNDS
During the first nine months of 2002, we spent approximately $76.1 million
on oil and natural gas development and exploration expenditures and $53.2
million on acquisitions, of which $48.2 million related to the COHO acquisition.
The oil and gas exploration and development expenditures included $50.9 million
spent on drilling, $14.0 million spent on geological, geophysical and acreage
expenditures and $11.2 million spent on workover costs. We also spent $11.4
million on CO2 acquisition and development expenditures during the first nine
months of 2002. All of these expenditures other than the acquisitions were
funded with cash flow from operations.
During the first nine months of 2001, we spent approximately $113.6 million
on oil and gas development and exploration expenditures and approximately $93.1
million on oil and gas property acquisitions, net of purchase price adjustments.
In addition, we issued 6.6 million shares of our common stock with a value of
$59.2 million as part of the Matrix acquisition. The oil and gas exploration and
development expenditures included $78.4 million spent on drilling,
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$13.1 million on geological, geophysical and acreage expenditures and $22.1
million on workover costs. Also during the first nine months of 2001, we spent
approximately $555,000 on CO2 development expenditures and $44.4 million on CO2
acquisitions. These expenditures were funded by cash flow from operations and
bank debt.
RESULTS OF OPERATIONS
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, remaining around that level through the first part of
2002. Late in the first quarter of 2002, commodity prices began to increase,
averaging approximately $26.25 per Bbl of oil and $3.37 per Mcf of natural gas
for the second quarter of 2002. NYMEX oil prices continued to rise in the third
quarter of 2002, averaging approximately $28.25, although natural gas prices
declined slightly during the quarter, averaging approximately $3.26 per Mcf. On
a per BOE basis, our net realized commodity prices were virtually unchanged
between the second and third quarters of 2002, but were 9% higher than our third
quarter of 2001 average price per BOE. As more fully described under
"Production" below, production levels were relatively unchanged between the
respective third quarters and between the second and third quarters of 2002. In
summary, in comparing the respective third quarters, (i) production was almost
the same, (ii) commodity prices were slightly higher in 2002, (iii) the third
quarter of 2001 had significantly more hedging gains, and (iv) our operating
expenses were higher in the third quarter of 2002 with the additional CO2
tertiary floods and the addition of the COHO properties for one month. The net
result was slightly lower net income and cash flow from operations in the third
quarter of 2002 than in the third quarter of 2001. For the nine months ended
September 30, 2002, operating results were significantly less than the
comparable prior year nine month period due primarily to the substantially lower
results for the first quarter of 2002 as a result of the sharp decrease in
commodity prices, partly offset by higher overall production levels. The
operating results for the comparative second and third quarters of 2001 and 2002
were not as divergent, as commodity prices generally increased during 2002
relative to those in the first quarter of 2002, whereas commodity prices
generally decreased in 2001 relative to those in the first quarter of 2001. Our
net income, net income per common share and cash flow from operations were as
follows:
Three Months Ended Nine Months Ended
September 30, September 30,
- -------------------------------------------------- ------------------------------ -----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 2002 2001 2002 2001
- -------------------------------------------------- ------------- --------------- ------------- --------------
Net income $ 13,459 $ 13,948 $ 31,503 $ 60,028
Net income per common share:
Basic $ 0.25 $ 0.27 $ 0.59 $ 1.25
Diluted 0.25 0.26 0.58 1.22
Cash flow from operations (1) $ 44,177 $ 48,670 $ 116,124 $ 148,846
- -------------------------------------------------- ------------- --------------- ------------- --------------
(1) Represents cash flow provided by operations, before changes in assets and
liabilities.
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------- -------------------------- -------------------------
2002 2001 2002 2001
- ------------------------------------------------------------- ------------- ------------ ------------- -----------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 18,930 16,877 18,201 16,536
Mcf 99,452 109,406 103,581 80,268
BOE(1) 35,506 35,112 35,465 29,914
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 42,372 $ 34,442 $ 107,608 $ 104,198
Natural gas sales 29,781 31,112 86,569 104,794
Gain (loss) on settlements of derivative contracts (218) 7,217 2,430 7,835
------------- ------------ ------------- -----------
Total oil and natural gas revenues $ 71,935 $ 72,771 $ 196,607 $ 216,827
============= ============ ============= ===========
Lease operating costs $ 17,714 $ 14,671 $ 50,266 $ 39,558
Production taxes and marketing expenses 2,969 3,292 8,880 8,432
------------- ------------ ------------- -----------
Total production expenses $ 20,683 $ 17,963 $ 59,146 $ 47,990
============= ============ ============= ===========
CO2 sales to industrial customers $ 2,182 $ 1,455 $ 5,568 $ 3,738
CO2 operating costs 431 373 960 708
------------- ------------ ------------- -----------
CO2 operating margin $ 1,751 $ 1,082 $ 4,608 $ 3,030
============= ============ ============= ===========
UNIT PRICES-INCLUDING IMPACT OF HEDGES
Oil price per barrel ("Bbl") $ 24.18 $ 22.18 $ 21.70 $ 23.08
Gas price per thousand cubic feet ("Mcf") 3.26 3.81 3.14 5.14
UNIT PRICES-EXCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 24.33 $ 22.18 $ 21.66 $ 23.08
Gas price per Mcf 3.25 3.09 3.06 4.78
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE(1):
Oil and natural gas revenues $ 22.02 $ 22.53 $ 20.31 $ 26.55
============= ============ ============= ===========
Oil and gas lease operating costs $ 5.43 $ 4.54 $ 5.19 $ 4.85
Oil and gas production taxes and marketing expenses 0.91 1.02 0.92 1.03
------------- ------------ ------------- -----------
Total oil and gas production expenses $ 6.34 $ 5.56 $ 6.11 $ 5.88
============================================================= ============= ============ ============= ===========
(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 third quarter of 2002 averaged 35,506
BOE/d, just slightly higher than the third quarter of 2001 average of 35,112
BOE/d and almost the same as the second quarter of 2002 average of 35,526 BOE/d.
The properties from the COHO acquisition which closed in August 2002 added
approximately 1,230 BOE/d to the third quarter of 2002 average production, but
this increase was offset by the losses in production due to Tropical Storm
Isidore. Although it is difficult to measure the exact impact of that storm, our
offshore production, which is the area most affected by the storm, declined by
1,366 BOE/d between the second and third quarters of 2002, most of which relates
to shut-in production caused by the storm. The storm also caused other indirect
declines in production both onshore and offshore by delaying various projects.
The fourth quarter of 2002 production will also be affected, as Tropical Storm
Isidore was followed by Hurricane Lili in early October, a stronger storm which
damaged one of our offshore platforms. Assuming that repairs are completed as
scheduled, we estimate that we will lose approximately 1,500 BOE/d in the fourth
quarter of 2002 directly related to Hurricane Lili.
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
To summarize our production by area, production for our properties in
Eastern Mississippi was relatively flat from the second quarter to third quarter
of 2002, excluding the aforementioned increases from the COHO properties. When
comparing the respective third quarters, production in this area was down year
over year due to general production declines at most of our significant fields.
Offshore production was down from the second quarter to third quarter in 2002,
as discussed above, primarily due to Tropical Storm Isidore. Production was also
down when comparing the respective third quarters, although to a lesser degree,
as production has generally increased offshore during the last year. Production
from our CO2 flood properties was up year over year, but down from the second to
third quarters as more fully discussed below. Production from our onshore
Louisiana area was up from the second to third quarter of 2002, but down on a
year over year basis. The recent increases in production onshore Louisiana were
primarily a result of recent drilling activity at Thornwell Field (see more
detail below). Production by area for each of the quarters is listed in the
following table.
Average Daily Production (BOE/d)
----------------------------------------------------------------------------------
Third Fourth First Second Third
Quarter Quarter Quarter Quarter Quarter
Operating Area 2001 2001 2002 2002 2002
- ------------------------------ ---------------- ---------------- --------------- --------------- ---------------
Eastern Mississippi 13,174 12,801 12,423 12,124 13,232
CO2 Flood Properties 2,437 3,268 3,839 4,278 3,895
Onshore Louisiana 8,893 9,335 8,405 7,717 8,224
Offshore Gulf of Mexico 10,426 9,273 10,550 11,229 9,863
Other 182 279 144 178 292
---------------- ---------------- --------------- --------------- ---------------
Total Company 35,112 34,956 35,361 35,526 35,506
============================== ================ ================ =============== =============== ===============
The production from our CO2 flood properties, Little Creek and Mallalieu
Fields, averaged 3,895 BOE/d during the third quarter of 2002, compared to 2,437
BOE/d during the third quarter of 2001, both higher than the approximate 2,000
BOE/d level as of the first quarter of 2001. Third quarter 2002 production on
these properties declined slightly from the second quarter of 2002 average of
4,278 BOE/d due to a temporary lack of deliverability of CO2 and facility
maintenance work performed at Little Creek Field during the quarter which
required that the field be shut-in for a few days. During the third quarter of
2002 we added additional compression equipment for our CO2 production and
commenced the drilling of an additional CO2 well which is expected to commence
production in late November or early December. By year-end, we expect to be able
to increase our CO2 production from the third quarter of 2002 average of 112
MMcf/d to around 160 MMcf/d (September 2002 averaged 121 MMcf/d with the
additional compression). We plan to commence the drilling of another CO2 well
immediately following the completion of the current one, with two to three more
wells tentatively scheduled for 2003. The anticipated incremental CO2 production
will be available to increase the CO2 injected per day at Little Creek and
Mallalieu, with the expectation that oil production from these fields will
increase during the fourth quarter of 2002 and throughout 2003 as a result of
the higher injection volumes of CO2. On a monthly basis during the third quarter
of 2002, oil production was lowest during August, but had begun to respond by
September to the additional CO2 production resulting from the additional
compression early in the third quarter.
Production at Little Creek Field, including West Little Creek Field,
increased from 2,318 BOE/d in the third quarter of 2001 to 3,222 BOE/d in the
third quarter of 2002 in response to additional phases of CO2 injection. This
compares to an average of 3,701 BOE/d in the second quarter of 2002. Mallalieu
Field, another tertiary flood project that we purchased in April 2001, began to
respond during 2002 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 670 Bbls/d for the third quarter of 2002,
up from the second quarter of 2002 average of 572 BOE/d. The response and other
development work at this field is ahead of expectations, contributing to the
shortfall in CO2 deliverability discussed above.
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We purchased two other potentially significant CO2 flood properties along
our CO2 pipeline, Brookhaven Field, which is part of the COHO acquisition that
closed in late August (see "Recent Events" above), and McComb Field which closed
during September at a cost of approximately $2.0 million. In addition, we are
continuing to acquire leases on three other oil fields along our CO2 pipeline,
and to fine-tune our long-term development plan for these fields. We anticipate
that as part of this plan, we will spend in the neighborhood of $50 million per
year for the next several years on these properties that we now control, which
should result in a general increase in the oil production from these properties
each year for the next five to seven years.
Our production for all of 2002 has been close to 50/50 oil and natural gas,
with production during the third quarter of 2002 weighted a little more toward
oil due to the loss of natural gas production in the Gulf of Mexico as a result
of Tropical Storm Isidore. In comparison, the production during the first nine
months of 2001 was approximately 55% 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 which closed in late August is
virtually all oil production, which will cause the fourth quarter of 2002 ratio
to become more weighted towards oil, although a portion of this package is
expected to be sold late in the year.
Production rates at other significant fields during the third quarter of
2002 included an average of 4,170 BOE/d at Thornwell Field, a 5% decrease from
production levels in the third quarter of 2001, but a 20% increase from
production levels in the second 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, and other factors. Overall, the
Thornwell acquisition in October of 2000 has performed well, as we recovered our
acquisition cost within the first year of ownership. Production at Thornwell
increased in the third quarter with the recent completion of two new wells.
Production at our Heidelberg Field averaged 7,472 BOE/d during the third
quarter of 2002, a 5% decrease from production levels in the third quarter of
2001, but a slight increase from production levels in the second 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 had also begun to decline as a result of
our reduced natural gas drilling activity there in late 2001 and early 2002.
However, as a result of higher natural gas prices, we have recently drilled four
natural gas wells at Heidelberg, which increased the average natural gas
production at Heidelberg by approximately a million cubic feet of natural gas
per day in the third quarter.
OIL AND NATURAL GAS REVENUES: Excluding the gain or loss from settlements
of derivative contracts, oil and natural gas revenues for the third quarter of
2002 increased $6.6 million, or 10%, from revenues in the comparable quarter of
2001, although they were down $14.8 million, or 7%, when comparing the first
nine months of 2001 and 2002. In general, the unusually high natural gas prices
early in 2001 and relatively low natural gas price in early 2002 were the
primary reasons for the significant decrease in revenue during the first nine
months of 2002 when compared to the prior year period, as production was higher
during the 2002 nine month period. However, for the comparable third quarters,
commodity prices were slightly higher during the 2002 period for both oil and
natural gas, causing the 10% increase in oil and natural gas revenue (see a
discussion of overall commodity prices in the first paragraph of "Results of
Operations" above). For the first nine months of 2002, the decline in commodity
prices reduced revenues by $53.6 million, or 25%, from levels in the comparable
period in 2001 and lower cash receipts from derivative contracts reduced
revenues by $5.4 million, or 2%, from levels in the comparable period of 2001.
This decrease was offset in part by an increase in production volumes which
increased revenues by $38.8 million, or 18%. When comparing the respective third
quarters, the production volumes were almost the same, while commodity prices
for both oil and natural gas were slightly higher, which increased revenues by
$5.9 million, or 8%, from levels in the comparable period in 2001. This increase
was offset by reduced cash receipts from our derivative contracts, which reduced
revenues by $7.4 million, or 10% of the change in oil and natural gas revenues
between the comparative periods. During the third quarter of 2001, most of the
cash collections on our derivative contracts related to the natural gas price
floors at $4.25 per MMBtu which had been purchased as part of the Matrix
acquisition.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Our realized natural gas prices (excluding hedges) for the third quarter
and of 2002 averaged $3.25 per Mcf, a 5% increase from the average prices of
$3.09 per Mcf during the comparable period of 2001. For the comparative nine
month periods, our realized natural gas prices (excluding hedges) averaged $3.06
per Mcf in 2002, a 36% decrease from the average prices of $4.78 per Mcf during
the comparable period of 2001. Oil prices had similar trends, as our realized
oil prices (excluding hedges) for the third quarter of 2002 averaged $24.33 per
Bbl, resulting in a 10% increase from the average price of $22.18 per Bbl during
the comparable period of 2001. Conversely, for the comparable nine months
periods, our average realized oil price (excluding hedges) for the 2002 period
averaged $21.66 per Bbl, a 6% decrease from the $23.08 per Bbl for the
comparable period of 2001.
During the third quarter of 2002, our average oil price received was
approximately $3.93 per barrel less than the average NYMEX oil price, which is
better than our NYMEX oil price differentials over the last few years, which
have generally averaged between $4.00 to $5.00 per barrel. The improved net oil
price resulted from continued favorable movement of certain oil indices,
relative to the NYMEX prices, which was also significant to the second quarter
of 2002 net realized oil prices, during which we experienced our lowest
historical price differential of $3.30. 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 at least somewhat to more normal historical
averages, which would reduce our net average oil price in the future relative to
the NYMEX price.
We collected $2.4 million on our commodity hedges in the first nine months
of 2002 (virtually all in the first quarter), increasing our average realized
natural gas price by $0.08 per Mcf and our average realized oil price by $0.04
per Bbl for the nine month period. For the first nine months of 2001 we
collected $7.8 million on our natural gas hedges (principally in the third
quarter) which increased our average realized natural gas price by $0.36 per Mcf
for the first nine months of 2001.
CO2 OPERATIONS: We received net operating cash flow from our sales of CO2
to third parties of $1.8 million for the third quarter of 2002 and $4.6 million
for the first nine months of 2002 as compared to $1.1 million for the third
quarter of 2001 and $3.0 million for the first nine months of 2001. These sales
have gradually increased since our acquisition of these properties in February
of 2001. During the third quarter of 2002, we used approximately 43% of the CO2
that we produced for our tertiary recovery operations, sold approximately 46% to
third parties for industrial use, and delivered the balance to a third party
pursuant to a delivery commitment. Our average production for the third quarter
of 2002 was approximately 112 MMcf/d, slightly higher than the 106 MMcf/d
produced during the second quarter of 2002.
PRODUCTION EXPENSES: Our oil and natural gas lease operating expenses
increased 20% and 7% on a per BOE basis between the respective third quarters
and first nine months of 2002 and 2001. The increases were primarily due to
higher than usual workover expenses, principally offshore on the Matrix
properties in the second quarter of 2002, and increased operating expenses on
the properties acquired from COHO. The facilities maintenance work performed at
Little Creek and workovers performed at that field also contributed to the
increase in operating expense per BOE. Lease operating expenses increased on a
gross basis by $3.0 million, or 21%, between the respective third quarters and
by $10.7 million, or 27%, between the respective nine month periods, primarily
as a result of the factors previously mentioned.
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating expenses increased slightly in our Eastern Mississippi properties
from $6.14 per BOE in the third quarter of 2001 to $6.32 per BOE for the
comparable quarter in 2002, primarily due to the addition of the COHO properties
for one month. Operating expenses for the COHO properties averaged $9.04 per BOE
and are expected to be unusually high during the first six to twelve months of
ownership. Offshore, operating expenses were $4.86 per BOE for the third quarter
of 2002, about the same as the average for the last three quarters, but higher
than in the third quarter of 2001 ($2.78 per BOE). The higher operating expenses
generally correlate with the increased level of activity after the Matrix
acquisition, which also resulted in the corresponding higher production levels.
Operating expenses were also affected in the third quarter of 2002 by the lost
production as a result of Tropical Storm Isidore. Operating expenses at Little
Creek Field were $10.03 per BOE in the third quarter of 2002, less than the
$10.94 per BOE for the comparable period in 2001, but higher than in the prior
two quarters of 2002, (both below $9.00 per BOE). The higher cost per BOE was
due to the aforementioned facility maintenance, workover expenses and lower
production due to these factors, and the temporarily limited supply of CO2.
Our CO2 average operating cost was approximately $0.14 per thousand cubic
feet, higher than the prior several quarters due to the incremental cost of
compression equipment beginning in the third quarter of 2002 and non-recurring
maintenance work performed on the facilities during the third quarter of 2002.
We allocate the operating expenses of our CO2 field and pipeline between the
sales to commercial users and the CO2 used for our own account. The estimated
total cost per thousand cubic feet of CO2 for us is approximately $0.20, after
inclusion of the depreciation and amortization expense, still less than the
$0.25 per thousand cubic feet before we acquired the properties in February
2001.
Production taxes and marketing expenses on a per BOE basis decreased 11%
between the respective third quarters and first nine months of 2002 and 2001.
The decrease in the third quarter of 2002 was primarily due to a reduction in
the Louisiana gas severance tax rate effective July 1, 2002. The decrease
between the respective nine month periods is due primarily to lower commodity
prices and the decrease in the Louisiana gas severance tax rate, partially
offset by an increase in marketing and transportation expenses due to the
acquisition of the Matrix properties in July 2001 and the increases in
production thereon.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 6% on a per BOE basis
between the respective third quarters and 3% on a per BOE basis for the
respective nine month periods, and increased on a gross basis as set forth
below:
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------- --------------------------------- --------------------------------
2002 2001 2002 2001
- ------------------------------------------- --------------- --------------- -------------- ---------------
NET G&A EXPENSE (THOUSANDS)
Gross G&A expense $ 9,691 $ 8,875 $ 28,671 $ 23,818
State franchise taxes 342 330 1,070 905
Operator overhead charges (5,708) (5,438) (16,256) (14,117)
Capitalized exploration costs (1,291) (918) (3,941) (2,777)
=============== =============== ============== ===============
Net G&A expense $ 3,034 $ 2,849 $ 9,544 $ 7,829
--------------- --------------- -------------- ---------------
Average G&A expense per BOE $ 0.93 $ 0.88 $ 0.99 $ 0.96
Employees as of September 30 345 319 345 319
=========================================== =============== =============== ============== ===============
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gross G&A expense increased $816,000, or 9%, between the third quarters of
2001 and 2002 and increased $4.9 million, or 20%, between the respective nine
month periods. The largest components of these increases were salaries, bonus
accruals, and other related employee costs, which accounted for approximately
$4.1 million of the increase for the respective nine month periods. The increase
in employee costs is due to salary increases and employee related additions
resulting from our growth, the Matrix acquisition in July 2001 and the COHO
acquisition in August 2002. 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 5% between the
respective third quarters of 2001 and 2002 and by 15% between the respective
nine month periods. 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 our smaller
capital budget. Capitalized exploration costs increased between the comparable
periods in 2001 and 2002 as a result of the increase in gross G&A expense and
the additional technical personnel added as part of the Matrix and COHO
acquisitions. The net effect of the increase in gross G&A expense, operator
overhead charges and capitalized exploration costs was a 6% increase in net G&A
expense between the third quarters of 2001 and 2002 and a 22% increase in net
G&A expense between the respective nine month periods.
On a per BOE basis, G&A expense increased 6% in the third quarter of 2002
as compared to the third 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, and the lower than originally anticipated production
due to Tropical Storm Isidore. On a per BOE basis, G&A expense was 3% higher in
the 2002 nine month period than the comparable period of 2001.
Interest and Financing Expenses
Three Months Ended Nine Months Ended
September 30, September 30,
- ----------------------------------------------------- ----------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2002 2001 2002 2001
- ----------------------------------------------------- -------------- ------------- ------------ ------------
Interest expense $ 6,860 $ 6,330 $ 20,086 $ 15,575
Non-cash interest expense (659) (344) (1,959) (892)
-------------- ------------- ------------ ------------
Cash interest expense 6,201 5,986 18,127 14,683
Interest and other income (407) (92) (1,229) (340)
-------------- ------------- ------------ ------------
Net cash interest expense $ 5,794 $ 5,894 $ 16,898 $ 14,343
============== ============= ============ ============
Average net cash interest expense per BOE $ 1.77 $ 1.82 $ 1.75 $ 1.76
Average debt outstanding $ 351,087 $ 307,479 $ 345,395 $ 242,561
===================================================== ============== ============= ============ ============
Interest expense in the third quarter and first nine months of 2002
increased from interest expense in the comparable prior year periods primarily
due to (i) higher average outstanding debt balances during 2002 following the
CO2 and Matrix acquisitions in February 2001 and July 2001, respectively, and
the COHO acquisition in August 2002, 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 and 2002 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) $13.2 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, repaid $10.0 million during the
second quarter with our excess cash flow, borrowed $44 million in August 2002 to
partially fund the COHO
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
acquisition and repaid $5.0 million in September 2002 with excess cash flow,
leaving us with $375 million of total debt outstanding as of September 30, 2002
(excluding the discount).
Net cash interest expense per BOE decreased 3% between the respective third
quarters and 1% between the respective nine month periods, due to the increase
in interest and other income in 2002 and a higher percentage of interest expense
relating to non-cash costs following the issue of subordinated debt at a
discount in August 2001.
Depletion, Depreciation and Site Restoration
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------------------------- ----------------------------- -----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2002 2001 2002 2001
- --------------------------------------------------- ------------- ------------- ------------- --------------
Depletion and depreciation $ 21,376 $ 20,990 $ 64,975 $ 44,287
Depreciation of CO2 assets 521 519 1,660 1,220
Site restoration provision 702 819 2,265 1,154
Depreciation of other fixed assets 432 366 1,262 1,026
------------- ------------- ------------- --------------
Total DD&A $ 23,031 $ 22,694 $ 70,162 $ 47,687
============= ============= ============= ==============
DD&A per BOE:
Oil and natural gas properties $ 6.76 $ 6.75 $ 6.95 $ 5.56
CO2 assets and other fixed assets 0.29 0.28 0.30 0.28
------------- ------------- ------------- --------------
Total DD&A cost per BOE $ 7.05 $ 7.03 $ 7.25 $ 5.84
=================================================== ============= ============= ============= ==============
Our depletion, depreciation and amortization ("DD&A") rate on a BOE basis
increased from $5.84 per BOE for the first nine months of 2001 to $7.25 per BOE
for the first nine months of 2002. The primary reason for the increase was the
acquisition of Matrix Oil & Gas, Inc. in July 2001. The DD&A rate also increased
slightly in the first half of 2002 to an average rate of $7.35 per BOE due
primarily to the additional capital expenditures made during the first half of
2002 on tertiary recovery properties, without a corresponding increase to
reserves, and to a slight increase in the estimates for the future development
costs relating to these tertiary floods. However, with the addition of the
properties acquired in the COHO acquisition, the DD&A rate dropped by $0.30 per
BOE to $7.05 for the third quarter of 2002 to reflect the low cost per barrel of
the properties acquired in the COHO acquisition. During the third quarter of
2002, we acquired two fields which we believe have significant potential from
tertiary recovery (i.e. CO2 flooding) based on the recovery factors to date at
Little Creek and Mallalieu Fields. One of the fields, Brookhaven Field, was part
of the COHO acquisition and the other, McComb Field, was acquired in a separate
transaction. We have not yet determined what proved reserves, if any, will be
assigned to these fields at year-end. As such, it is possible that our DD&A rate
could change significantly in the fourth quarter of 2002 pending the
determination of the proved reserves at these two fields and other minor
tertiary recovery properties.
30
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
Three Months Ended Nine Months Ended
September 30, September 30,
- ---------------------------------------------------------- ------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS AND TAX RATES 2002 2001 2002 2001
- ---------------------------------------------------------- ------------ ----------- ------------ ------------
Current income tax expense (benefit) $ 20 $ (1,500) $ (428) $ 900
Deferred income tax expense 8,141 9,692 15,679 34,355
------------ ----------- ------------ ------------
Total income tax expense $ 8,161 $ 8,192 $ 15,251 $ 35,255
============ =========== ============ ============
Average income tax expense per BOE $ 2.50 $ 2.54 $ 1.58 $ 4.32
Effective tax rate 37.7% 37.0% 32.6% 37.0%
========================================================== ============ =========== ============ =============
Our income tax provisions through June 30, 2002 were based on an estimated
effective tax rate of 37%. In the third quarter of 2002, we determined that an
effective rate of 38% would be more appropriate and adjusted our provision for
the year accordingly, therefore resulting in a higher effective tax rate in the
third quarter. The effective tax rate for the third quarter and first nine
months of 2002 was lower than 38% due to the recognition of enhanced oil
recovery credits 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. In addition, if
commodity prices remain high, we may utilize the remaining alternative minimum
tax net operating loss carryforwards by the end of 2002, requiring us to pay
alternative minimum taxes in 2003.
The overall current income tax credit for the first nine months of 2002 is
the result of a 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.
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Per BOE Data
The following table summarizes the cash flow, DD&A and results of operations on a per BOE basis for the
comparative periods. Each of the individual components are discussed above.
Three Months Ended Nine Months Ended
September 30, September 30,
- -------------------------------------------------------- ---------------------------- --------------------------
Per BOE Data 2002 2001 2002 2001
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Revenue $ 22.09 $ 20.29 $ 20.06 $ 25.59
Gain (loss) on settlements of derivative contracts (0.07) 2.23 0.25 0.96
Lease operating costs (5.43) (4.54) (5.19) (4.85)
Production taxes and marketing expenses (0.91) (1.02) (0.92) (1.03)
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Production netback 15.68 16.96 14.20 20.67
Operating cash flow from CO2 operations 0.54 0.34 0.48 0.37
General and administrative expenses (0.93) (0.88) (0.99) (0.96)
Net cash interest expense (1.77) (1.82) (1.75) (1.76)
Current income taxes and other - 0.47 0.05 (0.10)
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Cash flow from operations(1) 13.52 15.07 11.99 18.22
DD&A (7.05) (7.03) (7.25) (5.84)
Deferred income taxes (2.49) (3.00) (1.62) (4.21)
Amortization of derivative contracts and other non-cash
hedging adjustments 0.35 (0.61) 0.35 (0.71)
Other non-cash items (0.21) (0.11) (0.22) (0.11)
- -------------------------------------------------------- ------------- ------------- ------------ ------------
Net income $ 4.12 $ 4.32 $ 3.25 $ 7.35
======================================================== ============= ============= ============ ============
(1) Represents cash flow provided by operations, before the changes in assets and liabilities.
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 2002-2005 2006 2007 2008 Value Value
- -------------------------------------- ------------ ----------- ------------ ----------- ----------- -----------
Variable rate debt:
Bank debt........................ $ - $ 175,000 $ - $ - $ 175,000 $ 175,000
The weighted-average interest rate on the bank debt at September 30, 2002 is 3.61%.
Fixed rate debt:
Subordinated debt................ $ - $ - $ - $ 200,000 $ 200,000 $ 199,860
The interest rate on the subordinated debt is a fixed rate of 9%.
32
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 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.
At September 30, 2002, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $22.1 million, a decrease of
approximately $45.6 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 September 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 nine months of 2002 for
which we recorded amortization expense of $7.4 million. Information regarding
our current hedging positions and historical hedging results is included in Note
7 to the consolidated financial statements.
Based on NYMEX natural gas futures prices at September 30, 2002, we would
expect to make future cash payments of $3.4 million 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
$1.9 million, and if futures prices were to increase by 10% we would expect to
pay $16.6 million. Based on NYMEX crude oil futures prices at September 30,
2002, we would expect to pay $6.3 million on our crude oil commodity hedges. If
crude oil futures prices were to decline by 10%, we would expect to receive $9.6
million under our crude oil commodity contracts, and if crude oil futures prices
were to increase by 10%, we would expect to pay $23.4 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
33
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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,
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.
34
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.
ITEM 4. CONTROLS AND PROCEDURES
- -------------------------------
(a) Evaluation of Disclosure Controls and Procedures
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in
Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934
(the "Exchange Act') as of a date within 90 days before the filing of this
report. Based on that evaluation, they have concluded that such disclosure
controls and procedures are effective in alerting them on a timely basis to
material information relating to the Company required under the Exchange
Act to be disclosed in this quarterly report.
(b) Changes in Internal Controls
There were no significant changes in the Company's internal controls
that could significantly affect such controls subsequent to the date of
their evaluation.
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K DURING THE THIRD QUARTER OF 2002
- ---------------------------------------------------------------------------
EXHIBITS:
--------
10* Third Amended and Restated Credit Agreement dated as of September 12, 2002.
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:
-------------------
None.
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
Sr. Vice President and Chief Financial Officer
By: /s/ Mark C. Allen
-------------------------------------------------
Mark C. Allen
Vice President and Chief Accounting Officer
Date: November 11, 2002
36
CERTIFICATIONS
--------------
I, Gareth Roberts, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Denbury
Resources Inc. (the "registrant");
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data and
have identified for the registrant's auditors any material weaknesses
in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
November 11, 2002 /s/ Gareth Roberts
-----------------------------------------
Gareth Roberts
President and Chief Executive Officer
37
I, Phil Rykhoek, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Denbury
Resources Inc. (the "registrant");
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data and
have identified for the registrant's auditors any material weaknesses
in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
November 11, 2002 /s/ Phil Rykhoek
----------------------------------------------
Phil Rykhoek
Sr. Vice President and Chief Financial Officer
38