UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
--------------------------------
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No__
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
CLASS OUTSTANDING AT JULY 31, 2003
----- ----------------------------
Common Stock, $.001 par value 54,016,047
DENBURY RESOURCES INC.
INDEX
Page
----
Part I. Financial Information
- ------------------------------
Item 1. Financial Statements
Independent Accountants' Report 3
Consolidated Balance Sheets at June 30, 2003 (Unaudited)
and December 31, 2002 4
Consolidated Statements of Operations for the Three and Six Months
Ended June 30, 2003 and 2002 (Unaudited) 5
Consolidated Statements of Cash Flows for the Six Months
Ended June 30, 2003 and 2002 (Unaudited) 6
Consolidated Statements of Comprehensive Income (Loss) for
the Six Months Ended June 30, 2003 and 2002 (Unaudited) 7
Notes to Consolidated Financial Statements 8-18
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 19-33
Item 3. Quantitative and Qualitative Disclosures about Market Risk 34
Item 4. Controls and Procedures 34
Part II. Other Information
---------------------------
Item 4. Submission of Matters to a Vote of Security Holders 34
Item 6. Exhibits and Reports on Form 8-K 35
Signatures 36
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
- -----------------------------
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Directors of Denbury Resources Inc.:
We have reviewed the accompanying condensed consolidated balance sheet of
Denbury Resources Inc. and subsidiaries (the "Company") as of June 30, 2003, and
the related condensed consolidated statements of operations for the three-month
and six-month periods ended June 30, 2003 and 2002, and of cash flows and
comprehensive income (loss) for the six-month periods then ended. 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, 2002 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 March 3,
2003, 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, 2002 is fairly stated,
in all material respects, in relation to the consolidated balance sheet from
which it has been derived.
As discussed in Note 3 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations," effective January 1, 2003.
/s/ Deloitte & Touche LLP
Dallas, Texas
August 7, 2003
3
DENBURY RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
(Unaudited)
June 30, December 31,
2003 2002
--------------- ---------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 19,348 $ 23,940
Accrued production receivable 35,886 34,458
Related party accrued production receivable - Genesis 4,279 3,334
Trade and other receivables 19,990 16,846
Other current assets 5,534 -
Deferred tax asset 31,642 49,886
------------ -----------
Total current assets 116,679 128,464
------------ -----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties (using full cost accounting)
Proved 1,331,593 1,245,896
Unevaluated 47,701 45,736
CO2 properties and equipment 74,808 62,370
Less accumulated depletion and depreciation (650,441) (609,917)
------------ -----------
Net property and equipment 803,661 744,085
------------ -----------
INVESTMENT IN GENESIS 2,237 2,224
OTHER ASSETS 22,108 20,519
------------ -----------
TOTAL ASSETS $ 944,685 $ 895,292
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 53,360 $ 49,281
Oil and gas production payable 21,048 17,309
Derivative liabilities 45,377 29,289
------------ -----------
Total current liabilities 119,785 95,879
------------ -----------
LONG-TERM LIABILITIES
Long-term debt 333,106 344,889
Asset retirement liabilities 40,185 6,845
Derivative liabilities 13,063 6,281
Deferred tax liability 54,571 71,663
Other 2,762 2,938
------------ -----------
Total long-term liabilities 443,687 432,616
------------ -----------
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;
53,973,381 and 53,539,329 shares issued and outstanding at June 30, 2003
and December 31, 2002, respectively 54 54
Paid-in capital in excess of par 399,709 395,906
Retained earnings (accumulated deficit) 16,319 (9,875)
Accumulated other comprehensive loss (34,869) (19,288)
------------ -----------
Total stockholders' equity 381,213 366,797
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 944,685 $ 895,292
============ ===========
(See accompanying Notes to Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- -------------------------
2003 2002 2003 2002
------------- ------------- ------------ ------------
REVENUES
Oil, natural gas and related product sales
Unrelated parties $ 83,575 $ 67,600 $ 182,886 $ 118,510
Related party - Genesis 11,177 3,514 23,590 3,514
CO2 sales 2,445 1,896 4,634 3,386
Gain (loss) on settlements of derivative contracts (13,356) 12 (41,041) 2,648
Interest and other income 347 411 551 822
----------- ----------- --------- ----------
Total revenues 84,188 73,433 170,620 128,880
----------- ----------- --------- ----------
EXPENSES
Lease operating expenses 23,048 17,124 45,450 32,552
Production taxes and marketing expenses 3,467 3,297 7,363 5,911
CO2 operating expenses 534 362 851 529
General and administrative expenses 3,376 3,294 7,167 6,510
Interest 6,227 6,572 12,688 13,226
Loss on early retirement of debt 17,629 - 17,629 -
Depletion and depreciation 23,130 24,205 46,683 47,131
Amortization of derivative contracts and other
non-cash hedging adjustments (751) (1,012) (2,261) (2,093)
----------- ----------- --------- ----------
Total expenses 76,660 53,842 135,570 103,766
----------- ----------- --------- ----------
EQUITY IN NET INCOME OF GENESIS 35 20 51 20
----------- ----------- --------- ----------
INCOME BEFORE INCOME TAXES 7,563 19,611 35,101 25,134
INCOME TAX PROVISION (BENEFIT)
Current income taxes (1,093) 33 1,637 (448)
Deferred income taxes 3,527 6,080 9,882 7,538
----------- ----------- --------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 5,129 13,498 23,582 18,044
----------- ----------- --------- ----------
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE,
NET OF INCOME TAXES OF $1,600 - - 2,612 -
----------- ----------- --------- ----------
NET INCOME $ 5,129 $ 13,498 $ 26,194 $ 18,044
=========== =========== ========= ==========
NET INCOME PER COMMON SHARE - BASIC
Income before cumulative effect of change in
accounting principle $ 0.10 $ 0.25 $ 0.44 $ 0.34
Cumulative effect of change in accounting principle - - 0.05 -
----------- ----------- --------- ----------
Net income per common share - basic $ 0.10 $ 0.25 $ 0.49 $ 0.34
=========== =========== ========= ==========
NET INCOME PER COMMON SHARE - DILUTED
Income before cumulative effect of change in
accounting principle $ 0.09 $ 0.25 $ 0.42 $ 0.33
Cumulative effect of change in accounting principle - - 0.05 -
----------- ----------- --------- ----------
Net income per common share - diluted $ 0.09 $ 0.25 $ 0.47 $ 0.33
=========== =========== ========= ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic 53,815 53,158 53,728 53,077
Diluted 55,337 54,301 55,186 54,024
(See accompanying Notes to Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
(Unaudited)
Six Months Ended
June 30,
-----------------------------
2003 2002
--------- ---------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income $ 26,194 $ 18,044
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 46,683 47,131
Amortization of derivative contracts and other non-cash hedging adjustments (2,261) (2,093)
Deferred income taxes 9,882 7,538
Loss on early retirement of debt 17,629 -
Amortization of debt issue costs and other 840 1,327
Cumulative effect of change in accounting principle (2,612) -
Changes in assets and liabilities:
Accrued production receivable (2,373) (6,066)
Trade and other receivables (3,144) 18,616
Derivative assets - 7,836
Other assets 5 (210)
Accounts payable and accrued liabilities 2,214 (33,267)
Oil and gas production payable 3,739 (38)
Other liabilities (745) (214)
--------- ---------
NET CASH PROVIDED BY OPERATIONS 96,051 58,604
--------- ---------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures (70,709) (49,650)
Acquisitions of oil and gas properties (9,624) (2,268)
Investment in Genesis - (2,040)
Acquisitions of CO2 assets and capital expenditures (13,373) (5,934)
Proceeds from oil and gas property sales 28,154 4,552
Increase in restricted cash (356) (3,543)
Net purchases of other assets (6,973) (315)
--------- ---------
NET CASH USED FOR INVESTING ACTIVITIES (72,881) (59,198)
--------- ---------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments (125,000) (10,000)
Bank borrowings 85,000 5,130
Repayment of subordinated debt obligations, including redemption premium (209,000) -
Issuance of subordinated debt, net of discount 223,054 -
Issuance of common stock 2,970 2,143
Debt issuance costs (4,786) -
--------- ---------
NET CASH USED FOR FINANCING ACTIVITIES (27,762) (2,727)
--------- ---------
NET DECREASE IN CASH AND CASH EQUIVALENTS (4,592) (3,321)
Cash and cash equivalents at beginning of period 23,940 23,496
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 19,348 $ 20,175
========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest $ 13,371 $ 12,120
Cash paid (refunded) during the period for income taxes 184 (1,305)
(See accompanying Notes to Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
(Unaudited)
Six Months Ended
June 30,
-------------------------------
2003 2002
------------- -------------
Net income $ 26,194 $ 18,044
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts (14,179) (17,397)
Amortization of derivative contracts 366 3,227
Reclassification adjustments related to derivative contracts (1,768) (4,546)
------------- -------------
COMPREHENSIVE INCOME (LOSS) $ 10,613 $ (672)
============= =============
(See accompanying Notes to Consolidated Financial Statements)
7
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
Interim Financial Statements
The accompanying unaudited 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" refer 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, 2002. Any capitalized terms used but not defined
in these Notes to Consolidated Financial Statements have the same meaning given
to them in the Form 10-K.
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
consolidated financial statements include all adjustments (of a normal recurring
nature) necessary to present fairly the consolidated financial position of
Denbury as of June 30, 2003 and the consolidated results of its operations and
cash flows for the three and six month periods ended June 30, 2003 and 2002.
Certain prior period items have been reclassified to make the classification
consistent with this quarter.
2. NEW ACCOUNTING STANDARDS
See Note 3 regarding our change in accounting related to our adoption of
Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for
Asset Retirement Obligations."
In November 2002, the Financial Accounting Standards Board ("FASB") issued
Interpretaton ("FIN") No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness by
Others." FIN No. 45 requires that a guarantor must recognize, at the inception
of the guarantee, a liability for the fair value of the obligation that it has
undertaken in issuing a guarantee. FIN No. 45 also addresses the disclosure
requirements that a guarantor must include in its financial statements for
guarantees issued. The initial recognition and measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. We have made all relevant disclosures
regarding our guarantees.
On January 1, 2003, we adopted the provisions of SFAS No. 145, "Rescission
of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." SFAS No. 145 changes the method of reporting gains or
losses on the early extinguishment of debt. Prior to SFAS No. 145, gains or
losses on the early extinguishment of debt were required to be classified in a
company's statement of operations as an extraordinary item, net of the related
income tax effect. SFAS No. 145 considers the use of early debt extinguishment
to generally be a risk management strategy and states that its effects should be
reflected as income or expense from continuing operations, except in rare cases
where the extinguishment of debt could be considered unusual or infrequent and
would therefore be classified as an extraordinary item. In April 2003, we
retired our $200 million of Senior Subordinated Notes Due 2008, and recorded a
$17.6 million loss, before income taxes, on the early retirement of this debt
(see Note 7 for further information regarding this debt retirement).
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires that a
liability be recognized for exit and disposal costs only when the liability has
been incurred and when it can be measured at fair value. The statement is
effective for exit and disposal activities that are initiated after December 31,
2002. We adopted this statement in the first quarter of 2003 and it has not had
any effect on our financial statements.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies certain accounting and reporting for derivative
8
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
instruments. This statement is effective for contracts entered into or modified
after June 30, 2003. We will adopt this statement in the third quarter of 2003
and it should not have any impact on our financial statements.
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," became effective July 1, 2001 and January 1, 2002,
respectively. It is our understanding that the Securities and Exchange
Commission has raised questions as to the proper application by registrants in
the oil and gas industry of the provisions of SFAS No. 141 and SFAS No. 142 and
that the FASB and representatives from the SEC are currently in discussions
regarding this issue. In question is whether the acquisition of contractual
mineral interests, including both proved and undeveloped, should be classified
separately as "intangible assets" on the balance sheet apart from other oil and
gas property costs. Currently, Denbury, and virtually all other companies in the
oil and gas industry, have historically included purchased contractual mineral
rights in oil and gas properties on the balance sheet. Until we receive further
guidance regarding this issue, we will continue to include mineral interests as
oil and gas properties on our balance sheet for mineral interests acquired
subsequent to June 30, 2001. Based on the limited guidance pertaining to this
issue, we have not calculated the potential balance sheet reclassification at
this time. The provisions of SFAS No. 141 and 142 impact only the balance sheet
and associated footnote disclosure, and any reclassifications, if necessary,
would not impact the Company's results of operations or cash flows.
3. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting
for Asset Retirement Obligations." In general, our future asset retirement
obligations relate to future costs associated with plugging and abandonment of
our oil and natural gas wells, dismantling our offshore production platforms,
and removal of equipment and facilities from leased acreage and returning such
land to its original condition. 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, discounted to its present value using our credit adjusted
risk-free interest rate, and a corresponding amount capitalized by increasing
the carrying amount of the related long-lived asset. The liability is accreted
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Prior to the adoption of this new standard, we recognized a
provision for our asset retirement obligations each period as part of our
depletion and depreciation calculation, based on the unit-of-production method.
The adoption of SFAS No. 143 on January 1, 2003, required us to record (i)
a $41.0 million liability for our future asset retirement obligations (an
increase of $34.1 million in our liability for asset retirement obligations that
we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and
natural gas properties, (iii) a $3.9 million decrease in accumulated
depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect
adjustment of a change in accounting principle, net of taxes.
9
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following pro forma data summarizes Denbury's net income and net income
per common share as if we had applied the provisions of SFAS No. 143 in prior
periods, and as if we had removed the first quarter 2003 cumulative effect
adjustment for the adoption of SFAS No. 143:
Three Months Ended Six Months Ended
June 30, June 30, Year Ended December 31,
--------------------- -------------------- ------------------------------
2003 2002 2003 2002 2002 2001 2000
---------- ---------- ---------- --------- --------- --------- ---------
NET INCOME: (THOUSANDS)
Net income, as reported ............... $ 5,129 $ 13,498 $ 26,194 $ 18,044 $ 46,795 $ 56,550 $ 142,227
Pro forma adjustments to reflect
retroactive adoption of SFAS 143.. - 130 (2,612) (125) 473 503 306
---------- ---------- ---------- --------- --------- --------- ---------
Pro forma net income................ $ 5,129 $ 13,628 $ 23,582 $ 17,919 $ 47,268 $ 57,053 $ 142,533
========== ========== ========== ========= ========= ========= =========
NET INCOME PER COMMON SHARE:
As reported:
Basic........................... $ 0.10 $ 0.25 $ 0.49 $ 0.34 $ 0.88 $ 1.15 $ 3.10
Diluted......................... 0.09 0.25 0.47 0.33 0.86 1.12 3.07
Pro forma:
Basic.......................... $ 0.10 $ 0.26 $ 0.44 $ 0.34 $ 0.89 $ 1.16 $ 3.11
Diluted......................... 0.09 0.25 0.42 0.33 0.87 1.13 3.08
The following table summarizes the changes in our asset retirement
obligations for the six months ended June 30, 2003.
Six Months Ended
June 30, 2003
--------------------------
(in thousands)
Beginning asset retirement obligation, as of December 31, 2002.. $ 6,845
Cumulative effect adjustment for SFAS 143, January 1, 2003....... 34,110
Liabilities incurred during period............................... 909
Liabilities settled during period................................ (1,318)
Accretion expense................................................ 1,504
---------------------
Ending asset retirement obligation............................... $ 42,050
=====================
At June 30, 2003, $1.9 million of our asset retirement obligation was
classified in "Accounts payable and accrued liabilities" under current
liabilities in our Consolidated Balance Sheets. We have escrow accounts that are
legally restricted for certain of our asset retirement obligations. The balances
of these escrow accounts were $9.0 million at June 30, 2003, and $8.7 million at
December 31, 2002 and are included in "Other assets" in our Consolidated Balance
Sheets. If we had adopted SFAS No. 143 as of January 1, 2002, we estimate that
our asset retirement obligations at that date would have been $34.1 million,
based on the same assumptions used in our calculation of our obligations at
January 1, 2003.
4. NET INCOME PER COMMON SHARE
Basic net income per common share is computed by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
Diluted net income per common share is calculated in the same manner, but also
considers the impact on net income and common shares for the potential dilution
from stock options and any other convertible securities outstanding. For the
three and six month periods ended June 30, 2003 and 2002, there were no
adjustments to net income for purposes of calculating diluted net income per
common share.
10
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the weighted average common shares used in
the basic and diluted net income per common share calculations for the three and
six month periods ended June 30, 2003 and 2002.
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- -----------------------------
2003 2002 2003 2002
-------------- ------------- -------------- ------------
(in thousands) (in thousands)
Weighted average common shares - basic 53,815 53,158 53,728 53,077
Potentially dilutive securities:
Stock options 1,522 1,143 1,458 947
-------------- ------------- -------------- ------------
Weighted average common shares - diluted 55,337 54,301 55,186 54,024
============== ============= ============== ============
For the three months ended June 30, 2003 and 2002, common stock options to
purchase approximately 1.0 million and 1.7 million shares of common stock, and
for the six months ended June 30, 2003 and 2002, common stock options to
purchase approximately 1.0 million and 2.3 million shares of common stock,
respectively, were outstanding but excluded from the diluted net income per
common share calculations. Common stock options with exercise prices in excess
of our average market stock price during the respective periods are excluded
from the diluted net income per common share calculation, as their impact would
be anti-dilutive to our calculation.
5. SALE OF LAUREL FIELD
In February 2003, we sold Laurel Field, acquired in the COHO acquisition in
August 2002, for approximately $26.1 million and other consideration which
included an interest in Atchafalaya Bay Field (where we already owned an
interest) and seismic over that area. At December 31, 2002, Laurel Field had
approximately 7.4 MMBbls of proved reserves.
6. STOCK-BASED COMPENSATION
We issue stock options to all of our employees under our stock option plan,
which we account for utilizing the recognition and measurement principles of
Accounting Principles Board Opinion 25, "Accounting for Stock Issued to
Employees," and its related interpretations. Under these principles, we do not
recognize any stock-based employee compensation for stock option grants, as long
as the exercise price is equal to the underlying common stock on the date of
grant. The following table illustrates the effect on net income and net income
per common share if we had applied the fair value recognition and measurement
provisions of SFAS No. 123, "Accounting for Stock- Based Compensation," in
accounting for our stock option plan.
11
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
NET INCOME: (THOUSANDS)
Net Income, as reported ..................................$ 5,129 $ 13,498 $ 26,194 $ 18,044
Less: stock-based compensation expense applying fair
value based method, net of related tax effects... 869 651 1,634 1,359
------------ ------------ ------------ ------------
Pro forma net income...................................$ 4,260 $ 12,847 $ 24,560 $ 16,685
============ ============ ============ ============
NET INCOME PER COMMON SHARE:
As reported:
Basic..................................................$ 0.10 $ 0.25 $ 0.49 $ 0.34
Diluted................................................ 0.09 0.25 0.47 0.33
Pro forma:
Basic..................................................$ 0.08 $ 0.24 $ 0.46 $ 0.31
Diluted................................................ 0.08 0.24 0.45 0.31
7. INDEBTEDNESS
June 30, December 31,
2003 2002
--------------- ---------------
(Amounts in thousands)
(Unaudited)
9% Senior Subordinated Notes Due 2008...................................$ - $ 125,000
9% Series B Senior Subordinated Notes Due 2008.......................... - 75,000
7.5% Senior Subordinated Notes Due 2013................................. 225,000 -
Senior bank loan........................................................ 110,000 150,000
Discount on Senior Subordinated Notes.................................. (1,894) (5,111)
--------------- ---------------
Total debt..........................................................$ 333,106 $ 344,889
=============== ===============
Issuance of 7.5% Senior Subordinated Notes Due 2013
On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes
Due 2013 in a Rule 144A private offering. The notes were priced at 99.135% of
par and we used most of our $218.4 million of net proceeds from the offering,
after underwriting and issuance costs to retire our existing $200 million of 9%
Senior Subordinated Notes Due 2008, including the Series B notes, (see
"Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes)"
below).
The notes mature on April 1, 2013 and interest on the notes is payable each
April 1 and October 1, commencing October 1, 2003. We may redeem the notes at
our option beginning April 1, 2008 at the following redemption prices: 103.75%
after April 1, 2008, 102.5% after April 1, 2009, 101.25% after April 1, 2010,
and at 100% after April 1, 2011 and thereafter. In addition, prior to April 1,
2006, we may redeem up to 35% of the notes at a redemption price of 107.5% with
net cash proceeds from a stock offering. The indenture under which the notes
were issued is essentially the same as the indenture covering our previously
outstanding 9% notes. The indenture contains certain restrictions on our ability
to incur additional debt, pay dividends on our common stock, make investments,
create liens on our assets, engage in transactions with our affiliates, transfer
or sell assets and to consolidate or merge substantially all of our assets. The
notes are not subject to any sinking fund requirements.
12
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Redemption of 9% Senior Subordinated Notes Due 2008 (Including Series B Notes)
On March 18, 2003, we issued the required 30-day notice to call our
existing $200 million of 9% Senior Subordinated Notes Due 2008. On April 16,
2003, we redeemed the $200 million of notes at an aggregate cost of $209.0
million, including a $9.0 million call premium. As a result of this early
redemption, we recorded a before tax charge to earnings in the second quarter of
2003 of $17.6 million, which includes the $9.0 million call premium and the
write-off of the remaining discount and debt issuance costs associated with
these notes.
Senior Bank Loan
Our bank borrowing base was reaffirmed at $220 million as part of an
amendment to our credit agreement completed in early May 2003. In addition, the
amendment modified the hedging provisions to increase the amount of production
we can hedge to a maximum of 85% of our forecasted production from our proved
reserves for the current year, 70% of the forecasted production for the
subsequent year, 55% of the forecasted production for the third year and 40% of
the forecasted production for the fourth year. The amendment also permits us to
borrow up to $20 million in a bond issue from a Mississippi governmental
authority, resulting in the exemption from or reduction of sales and ad valorem
taxes on CO2 facilities we build in the next two years in Mississippi. This bond
funding arrangement was completed in May 2003. Any borrowings in this bond
issuance will be purchased by the banks in our credit facility, will be part of
our outstanding borrowings under our credit line and will accrue interest and be
repaid on the same basis as our bank line. In early August 2003, our bank
agreement was amended again to increase the percentage of our oil production
that may be hedged for the remainder of 2003, from 85% to 90%.
At June 30, 2003, we had $110.0 million outstanding under our bank credit
facility, leaving us approximately $110.0 million of borrowing capacity. We also
had letters of credit outstanding in the amount of $820,000 at June 30, 2003.
8. RELATED PARTY TRANSACTIONS - GENESIS
Through certain of our subsidiaries, since May 14, 2002 we have been the
general partner of Genesis Energy, L.P. ("Genesis"), a publicly traded master
limited partnership. Our subsidiary general partner has a 2% interest in
Genesis. Genesis has two primary lines of business: crude oil gathering and
marketing, and pipeline transportation, primarily in Mississippi, Texas, Alabama
and Florida.
We account for our 2% ownership in Genesis under the equity method, as we
have significant influence over the limited partnership; however, our control is
limited under the general partnership agreement and therefore we do not
consolidate Genesis. Our equity in Genesis' net income for the three and six
month periods ended June 30, 2003 was $35,000 and $51,000, respectively. For the
first six months of 2003, Genesis has paid Denbury $60,000 for directors' fees
for the services of the four Denbury officers that serve on the board of
directors of the general partner of Genesis, and $38,000 of distributions.
Genesis Energy, Inc., the general partner of which we indirectly own 100%, has
guaranteed the bank debt of Genesis, which was $6.0 million as of June 30, 2003,
and also included $26.4 million in letters of credit, of which $8.2 million are
for Denbury's benefit to 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.
Genesis has historically been a purchaser of our crude oil and we
anticipate future purchases of our crude oil production by Genesis. For the six
month period ended June 30, 2003, we recorded sales to Genesis of $23.6 million
and at June 30, 2003, had a production receivable from Genesis of $4.3 million.
Sales to Genesis for the period May 14, 2002 to June 30, 2002 were $3.5 million.
13
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information of Genesis Energy, L.P. is as follows (amounts in thousands):
Three Months Six Months
Ended Ended
June 30, 2003 June 30, 2003
-------------------- --------------------
Revenues.................................. $ 219,949 $ 481,831
Cost of sales............................. 214,090 470,717
Other expenses............................ 3,969 8,345
-------------------- --------------------
Net income................................ $ 1,890 $ 2,769
==================== ====================
June 30, December 31,
2003 2002
-------------------- --------------------
Current assets............................ $ 85,417 $ 92,097
Non-current assets........................ 46,714 45,440
-------------------- --------------------
Total assets.............................. $ 132,131 $ 137,537
==================== ====================
Current liabilities....................... $ 87,946 $ 96,220
Non-current liabilities................... 6,000 5,500
Partners' capital......................... 38,185 35,817
-------------------- --------------------
Total liabilities and partners' capital... $ 132,131 $ 137,537
==================== ====================
9. 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. We do not hold or issue derivative financial instruments for trading
purposes. 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 budgeted exploration and development
expenditures without incurring significant debt. When we make an acquisition, we
attempt to hedge a large percentage, up to 100%, of the forecasted production
for the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. 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.
The following is a summary of the net gain (loss) representing cash receipts
and payments on our hedge settlements:
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------ -----------------------------------------
2003 2002 2003 2002
----------------- ----------------- ------------------ -------------------
(in thousands)
Oil hedge contracts $ (2,633) $ - $ (11,371) $ 462
Gas hedge contracts (10,723) 12 (29,670) 2,186
----------------- ----------------- ------------------ -------------------
Net gain (loss) $ (13,356) $ 12 $ (41,041) $ 2,648
================= ================= ================== ===================
14
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Some of our derivative contracts require us to pay a premium which we
amortize over the contract periods. This expense is included in "Amortization of
derivative contracts and other non-cash hedging adjustments" in our Consolidated
Statements of Operations. For the six months ended June 30, 2003 and 2002, we
recorded premium amortization expense of $591,000 and $5.1 million,
respectively. Also, for the six months ended June 30, 2003, we reclassified $2.7
million related to our former Enron hedges (discussed below) out of accumulated
other comprehensive income into income and recorded a gain from hedge
ineffectiveness of $138,000 which is also included in "Amortization of
derivative contracts and other non-cash hedging adjustments."
HEDGING CONTRACTS AT JUNE 30, 2003
CRUDE OIL CONTRACTS:
- -------------------
NYMEX Contract Prices Per Bbl
---------------------------------------------------------
Collar Prices
-------------------------- Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling June 30, 2003
- -------------------------------- ------------ ------------ ------------- ------------ ----------- ------------------
Collar Contracts (in thousands)
July 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ (1,800)
Swap Contracts
July 2003 - Dec. 2003 2,500 24.25 - - - (2,149)
July 2003 - Dec. 2003 2,000 24.30 - - - (1,701)
July 2003 - Dec. 2003 2,000 25.70 - - - (1,187)
Jan. 2004 - Dec. 2004 2,500 22.89 - - - (2,660)
Jan. 2004 - Dec. 2004 4,500 23.00 - - - (4,608)
Jan. 2004 - Dec. 2004 2,500 23.08 - - - (2,488)
NATURAL GAS CONTRACTS:
- ---------------------
NYMEX Contract Prices Per MMBtu
----------------------------------------------------------
Collar Prices
-------------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2003
- -------------------------------- ----------- ------------ ------------ ------------ ------------ -----------------
Collar Contracts (in thousands)
July 2003 - Dec. 2003 45,000 $ - $ - $ 2.75 $ 4.00 $ (13,168)
July 2003 - Dec. 2003 25,000 - - 2.75 4.07 (7,017)
Jan. 2004 - Dec. 2004 30,000 - - 3.50 4.45 (10,834)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.87 (2,580)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.82 (2,642)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (2,556)
Swap Contracts
July 2003 - Dec. 2003 10,000 3.905 - - - (3,050)
At June 30, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of $58.4 million. To the extent our hedges are
considered effective, this fair value liability, net of income taxes, is
included in "Accumulated other comprehensive loss" reported under Stockholders'
equity in our Consolidated Balance Sheets. The balance in accumulated other
comprehensive loss of $34.9 million at June 30, 2003, 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 includes the remaining accumulated other
comprehensive income of $1.4 million relating to the Enron hedges that ceased to
qualify for hedge accounting treatment when Enron filed for bankruptcy. This
$1.4 million relating to the former Enron hedges will be reclassified out of
accumulated other comprehensive income during the remainder of 2003, over the
periods that the hedges would have otherwise expired. Of the $34.9 million in
accumulated other comprehensive loss as of June 30, 2003, $28.1 million relates
to current hedging contracts that will expire within the next 12 months.
15
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of August 2001, all of the Company's subordinated debt securities were
fully and unconditionally guaranteed by Denbury Resources Inc.'s significant
subsidiaries. Condensed consolidating financial information for Denbury
Resources Inc. and its significant subsidiaries as of June 30, 2003 and December
31, 2002 and for the three and six months ended June 30, 2003 and 2002 is as
follows:
Condensed Consolidating Balance Sheets
June 30, 2003 (Unaudited)
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- ------------- --------------
ASSETS
Current assets..................................$ 77,948 $ 38,731 $ - $ 116,679
Property and equipment.......................... 531,629 272,032 - 803,661
Investment in subsidiaries (equity method)...... 217,128 2,237 (217,128) 2,237
Other assets.................................... 18,203 3,905 - 22,108
-------------- ------------- ------------- --------------
Total assets...............................$ 844,908 $ 316,905 $ (217,128) $ 944,685
============== ============= ============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities.............................$ 105,144 $ 14,641 $ - $ 119,785
Long-term liabilities........................... 358,551 85,136 - 443,687
Stockholders' equity............................ 381,213 217,128 (217,128) 381,213
-------------- ------------- ------------- --------------
Total liabilities and stockholders' equity.$ 844,908 $ 316,905 $ (217,128) $ 944,685
============== ============= ============= ==============
December 31, 2002
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- -------------- --------------
ASSETS
Current assets..................................$ 111,063 $ 17,401 $ - $ 128,464
Property and equipment.......................... 528,754 215,331 - 744,085
Investment in subsidiaries (equity method)...... 169,309 2,224 (169,309) 2,224
Other assets.................................... 16,881 3,638 - 20,519
-------------- ------------- -------------- --------------
Total assets...............................$ 826,007 $ 238,594 $ (169,309) $ 895,292
============== ============= ============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities.............................$ 87,101 $ 8,778 $ - $ 95,879
Long-term liabilities........................... 372,109 60,507 - 432,616
Stockholders' equity............................ 366,797 169,309 (169,309) 366,797
-------------- ------------- -------------- --------------
Total liabilities and stockholders' equity.$ 826,007 $ 238,594 $ (169,309) $ 895,292
============== ============= ============== ==============
16
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2003 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 58,565 $ 25,623 $ - $ 84,188
Expenses..................................... 62,583 14,077 - 76,660
--------------- -------------- -------------- --------------
Income (loss) before the following: (4,018) 11,546 - 7,528
Equity in net earnings of subsidiaries.. 7,939 35 (7,939) 35
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 3,921 11,581 (7,939) 7,563
Income tax provision (benefit)............... (1,208) 3,642 - 2,434
--------------- -------------- -------------- --------------
Net income (loss)............................$ 5,129 $ 7,939 $ (7,939) $ 5,129
=============== ============== ============== ==============
Three Months Ended June 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 57,116 $ 16,317 $ - $ 73,433
Expenses..................................... 40,456 13,386 - 53,842
--------------- -------------- -------------- --------------
Income before the following: 16,660 2,931 - 19,591
Equity in net earnings of subsidiaries.. 1,842 20 (1,842) 20
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 18,502 2,951 (1,842) 19,611
Income tax provision......................... 5,004 1,109 - 6,113
--------------- -------------- -------------- --------------
Net income (loss)............................$ 13,498 $ 1,842 $ (1,842) $ 13,498
=============== ============== ============== ==============
Six Months Ended June 30, 2003 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 115,850 $ 54,770 $ - $ 170,620
Expenses..................................... 106,903 28,667 - 135,570
--------------- -------------- -------------- --------------
Income before the following: 8,947 26,103 - 35,050
Equity in net earnings of subsidiaries.. 16,434 51 (16,434) 51
--------------- -------------- -------------- --------------
Income (loss) before income taxes and
cumulative effect of a change in accounting
principal.................................. 25,381 26,154 (16,434) 35,101
Income tax provision......................... 3,168 8,351 - 11,519
--------------- -------------- -------------- --------------
Net income before cumulative effect of a
change in accounting principal............. 22,213 17,803 (16,434) 23,582
Cumulative effect of a change in accounting
principal, net of income taxes............. 3,981 (1,369) - 2,612
--------------- -------------- -------------- --------------
Net income (loss)............................$ 26,194 $ 16,434 $ (16,434) $ 26,194
=============== ============== ============== ==============
17
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Six Months Ended June 30, 2002 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- --------------- --------------
Revenues.....................................$ 102,449 $ 26,431 $ - $ 128,880
Expenses..................................... 78,873 24,893 - 103,766
--------------- -------------- --------------- --------------
Income before the following: 23,576 1,538 - 25,114
Equity in net earnings of subsidiaries.... 950 20 (950) 20
--------------- -------------- --------------- --------------
Income before income taxes................... 24,526 1,558 (950) 25,134
Income tax provision......................... 6,482 608 - 7,090
--------------- -------------- --------------- --------------
Net income (loss)............................$ 18,044 $ 950 $ (950) $ 18,044
=============== ============== =============== ==============
Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2003 (Unaudited)
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 72,219 $ 23,832 $ - $ 96,051
Cash flow from investing activities.......... (49,561) (23,320) - (72,881)
Cash flow from financing activities.......... (27,762) - - (27,762)
----------------- -------------- -------------- --------------
Net increase (decrease) in cash.............. (5,104) 512 - (4,592)
Cash, beginning of period.................... 20,281 3,659 - 23,940
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 15,177 $ 4,171 $ - $ 19,348
================= ============== ============== ==============
Six Months Ended June 30, 2002 (Unaudited)
-------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- ---------------
Cash flow from operations....................$ 50,742 $ 7,862 $ - $ 58,604
Cash flow from investing activities.......... (54,424) (4,774) - (59,198)
Cash flow from financing activities.......... (2,727) - - (2,727)
----------------- -------------- -------------- ---------------
Net increase (decrease) in cash.............. (6,409) 3,088 - (3,321)
Cash, beginning of period.................... 17,052 6,444 - 23,496
----------------- -------------- -------------- ---------------
Cash, end of period..........................$ 10,643 $ 9,532 $ - $ 20,175
================= ============== ============== ===============
18
DENBURY RESOURCES INC.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
- --------------------------------------------------------------------------------
You should read the following in conjunction with our financial statements
contained herein and our Form 10-K for the year ended December 31, 2002, 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.
We are a growing independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi, hold key operating acreage
onshore Louisiana and have a growing presence in the offshore Gulf of Mexico
areas. Our goal is to increase the value of acquired properties through a
combination of exploitation, drilling, and proven engineering extraction
processes. Our corporate headquarters are in Dallas, Texas, and we have three
primary field offices located in Houma and Covington, Louisiana, and Laurel,
Mississippi.
Debt Refinancing
In late March 2003, we issued $225 million of 7.5% Senior Subordinated
Notes due 2013 to refinance our $200 million of then existing 9% Senior
Subordinated Notes due 2008. The subordinated debt was refinanced to take
advantage of the currently attractive interest rates and to extend the maturity
of our long-term debt an additional five years. We estimate that we will save
approximately $2.6 million per year in interest expense as a result of this
refinancing. The total cost of the refinancing was approximately $15.6 million,
consisting of the debt issue discount, underwriters commission and other
expenses totaling approximately $6.6 million, and a $9.0 million call premium to
retire the old notes. The old notes were not retired until April 16, 2003, at
the end of the required thirty day notice period to call the old notes. We had a
pre-tax charge to earnings in the second quarter of 2003 of approximately $17.6
million from the early retirement of the old 9% notes, made up of the $9.0
million call premium and the write-off of unamortized discount of $4.8 million
and debt issue costs of $3.8 million. The proceeds from the new issue were used
to retire the old 9% subordinated notes in April 2003.
CAPITAL RESOURCES AND LIQUIDITY
During the first six months of 2003, we spent $70.7 million on oil and
natural gas exploration and development expenditures, $13.4 million on CO2
capital investments and acquisitions, and approximately $9.6 million on oil and
natural gas property acquisitions, for total capital expenditures of
approximately $93.7 million. In addition, during the first half of 2003 we
incurred approximately $15.6 million of costs for the subordinated debt
refinancing (see "Debt Refinancing" above). We sold Laurel Field, effective as
of January 31, 2003, for net cash proceeds of $26.1 million plus other
additional consideration, and sold other minor properties, resulting in
aggregate sales proceeds during the first six months of $28.2 million. Laurel
Field had been acquired as part of the acquisition of properties from COHO in
August 2002 and had approximately 7.4 MMBbls of proven reserves as of December
31, 2002. The $81.1 million of net total expenditures (including the $15.6
million of debt refinancing costs) was funded by $96.1 million of cash flow from
operations, with the excess cash flow used to reduce our total debt by
approximately $15.0 million. At June 30, 2003, we had $335 million of total debt
outstanding, consisting of $225 million of recently issued 7.5% subordinated
notes and $110 million of bank debt.
One of our financial goals is to limit our leverage. We generally measure
leverage by a debt-to-cash flow ratio, cash flow being defined as cash flow from
operations. Our target is a debt-to-cash flow ratio of 2 to 1 or less, using a
moderate price deck. In today's commodity price environment, we interpret that
to be oil prices around $25.00 per Bbl and natural gas prices around $3.50 per
Mcf. Based on these price assumptions and anticipated production levels, we
anticipate reaching our targeted debt-to-cash flow ratio during 2003 if our
total debt is reduced to $300 million. Since our last significant acquisition in
the third quarter of 2002, we have used a portion of our cash flow from
operations and proceeds from property sales to reduce our bank debt. We repaid
approximately $25 million during the fourth quarter of 2002, approximately $15
million during the first half of 2003, and had $15.6 million not been used to
pay for costs of our
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
subordinated debt refinancing, that amount would have also been used to reduce
debt during the first half of 2003. Even with the incremental debt from the
refinancing, we expect to achieve our debt goal of $300 million during the
latter part of 2003 through the application of excess cash flow from operations,
assuming that commodity prices do not decrease significantly. We may also
accomplish our goal in part with cash generated by the potential sale of a
portion of our CO2 reserves and a portion of the associated industrial contracts
to Genesis Energy, L.P. during the latter part of 2003. We, along with Genesis,
are still investigating the feasibility and requirements of a potential
transaction, which if consummated could generate between $15 million and $30
million of cash for us.
Our bank borrowing base was reaffirmed at $220 million as part of an
amendment to our credit agreement completed in early May 2003. The May amendment
also modified the hedging provisions to increase the amount of production we can
hedge to a maximum of 85% of our forecasted production from our proved reserves
for the current year (as defined in the amendment and which may include up to 18
months), 70% of the forecasted production for the subsequent year, 55% of the
forecasted production for the third year and 40% of the forecasted production
for the fourth year. The amendment also allowed us to borrow up to $20 million
in a bond issue from a Mississippi governmental authority, resulting in the
exemption or reduction of sales and ad valorem taxes on CO2 facilities we build
during the next two years in Mississippi. This bond funding arrangement was
completed in May 2003. Any borrowings in this bond issue will be purchased by
the banks in our credit facility, will be part of our outstanding borrowings
under our credit line and will accrue interest and be repaid on the same basis
as our bank line. In early August 2003, our bank agreement was amended again to
increase the percentage of our oil production that may be hedged for the
remainder of 2003, from 85% to 90%.
Our next bank borrowing base redetermination will be as of October 1st,
based on June 30, 2003 assets. We do not anticipate any significant changes to
our borrowing base at this next review, although we cannot be certain, as there
are several subjective aspects to the borrowing base determination.
We anticipate that our capital spending during 2003, excluding any possible
acquisitions, will be equal to or less than our cash flow generated from
operations, a goal we have met each year since 1999. Our 2003 budget was
recently increased by $5.0 million, and is currently approximately $143 million,
including approximately $7.7 million of projects carried over from 2002 and
excluding acquisitions. Based on current projections, using futures prices in
place as of the first part of August 2003, this exploration and development
spending level is expected to be as much as $40 million to $50 million below our
2003 forecasted cash flow. Initially, we plan to use any excess funds generated
from operations to pay down debt or to fund, in whole or in part, our current
year acquisitions. We may also consider further increasing our budget if it
appears certain that we can reach our $300 million debt target by year-end. We
review our capital expenditure budget every quarter and make adjustments as
necessary to reflect changes in commodity prices and successes or failures in
our drilling program. As a result, since 1999, we have been able to keep our
capital spending (excluding acquisitions) at levels equal to or below 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. Our primary focus to
date in 2003 has been the purchase of incremental interest in fields that we
already own. We are also continuing to pursue small acquisitions that are near
our CO2 pipeline in Western Mississippi and Southern Louisiana, plus individual
fields in the Gulf of Mexico. Although we now control most of the fields along
our CO2 pipeline, there are a few remaining smaller fields with potential that
we do not control. Also, 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 review acquisitions in our other core areas,
including larger acquisitions, this activity is a lower priority for us in 2003
than has been the case historically, given our substantial inventory of projects
in-house and our goal of reducing our debt level. Any acquisitions that we make
will likely be funded with either our excess cash flow or bank debt.
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Commitments and Obligations
Our 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. In addition, in order to recover our undeveloped proved reserves,
we must also fund the associated future development costs as forecasted in the
proved reserve reports. Further, one of our subsidiaries, the general partner of
Genesis Energy, L.P., has guaranteed the bank debt of Genesis (which as of June
30, 2003, consisted of $6.0 million of debt and $26.4 million in letters of
credit, $8.2 million of which are for Denbury's benefit) and we have delivery
obligations to deliver CO2 to our industrial customers. In August 2003, we
expect to close on a lease financing of certain equipment at our tertiary
recycling facility at Mallalieu Field, with a total present value of
approximately $6.0 million (the June 30, 2003 balance of $5.5 million was
classified as "Other current assets" in the balance sheet). Lease payments will
be approximately $900,000 per year for the next seven years, with an option to
prepay the lease after six years. Our hedging obligations are discussed in Note
9 to the Consolidated Financial Statements. Otherwise, neither the amounts nor
the terms of any other commitment or contingent obligation has changed
significantly from the year-end 2002 amounts reflected in our 2002 Form 10-K
filed in March 2003. The significant changes to our debt obligations, which are
recorded on our balance sheet, are discussed above under "Debt Refinancing" and
Capital Resources and Liquidity. Please refer to Management's Discussion and
Analysis of Financial Condition and Results of Operations contained in our 2002
Form 10-K for further information regarding our commitments and obligations.
RESULTS OF OPERATIONS
CO2 Operations
During late July and early August 2003, we upgraded our CO2 facility at
Jackson Dome, increasing the CO2 processing capacity of our facility by
approximately 50%, from around 200 MMcf/d to approximately 300 MMcf/d. This
upgrade was performed several months ahead of our original schedule to handle
the higher than expected production volumes from our CO2 wells drilled during
late 2002 and early 2003. At the same time, we increased the size of our CO2
processing facility at Mallalieu Field, increasing the amount of CO2 that we can
recycle at that field from approximately 28 MMcf/d to approximately 108 MMcf/d.
During July, we completed our third CO2 well drilled during the last twelve
months, the Barksdale, which coupled with the upgraded Jackson Dome facility,
increases our CO2 production capabilities to approximately 220 MMcf/d,
approximately double the production capacity of one year ago. Since our CO2
wells have been performing at higher production rates than originally
anticipated, the third CO2 well originally scheduled for 2003 has been postponed
until very late in the year, or perhaps even early in 2004. Based on our
inventory of potential tertiary recovery projects, we will need to drill
additional CO2 wells in 2004 and beyond to further increase our CO2 production
capacity to an estimated target rate of 350 MMcf/d in order to develop the oil
fields along our CO2 pipeline as planned, or perhaps to potentially even higher
levels if we expand our tertiary operations to other parts of the region.
Although we believe that our plans and projections are reasonable and
achievable, there could be unforeseen delays or problems in the future which
could delay our overall tertiary development program. We believe that such
delays, if any, should only be temporary. As of December 31, 2002, based on a
report prepared by DeGolyer and MacNaughton, we estimate that we have
approximately 1.6 trillion cubic feet of usable CO2 reserves.
Oil production from our CO2 tertiary recovery activities increased 4% over
first quarter 2003 levels to 4,522 Bbls/d in the second quarter of 2003,
representing approximately 24% of our total corporate oil production during the
second quarter. This increase occurred in spite of a leak in a newly installed
CO2 pipeline during the second quarter which forced us to significantly curtail
our CO2 production and corresponding injections for approximately ten days. Our
experience has indicated that any time that our CO2 production and associated
injections are curtailed, there is a corresponding drop in our oil production
from these projects. While second quarter tertiary oil production was higher
than comparable production in the first quarter, it was less than originally
anticipated, primarily due to curtailed CO2 production and injections as a
result of the pipeline leak. While our CO2 production capability is ahead of
schedule, as noted in the first
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
paragraph of this section, the required expansion of our CO2 facility will have
a negative impact on our CO2 injections during the third quarter of 2003. The
expansion required a complete shutdown of the facility for approximately one
week, thereby reducing our CO2 injections. While the operation was a success and
helps us expand our program in the future, the temporary shutdown is expected to
have a negative short-term effect on our tertiary oil production, and as such,
we do not expect our average daily tertiary oil production to increase during
the third quarter of 2003. This effect is expected to be temporary and we expect
tertiary oil production to resume its escalation during the fourth quarter of
2003.
We spent approximately $0.14 per Mcf to produce our CO2 during the second
quarter of 2003, slightly higher than the 2002 average of $0.13 per Mcf,
primarily due to higher royalty expenses, as certain of our royalty payments
increase if the price of oil increases beyond a certain threshold, but less than
first quarter 2003 CO2 costs of $0.16 per Mcf, primarily due to the recent
higher production rates. The higher cost per Mcf of CO2 during 2003 contributed
to a corresponding increase in the operating costs of our tertiary projects, as
did electricity and other expenses, as we continue to inject and recycle higher
volumes of CO2 each quarter. For the second quarter of 2003, our operating costs
for our tertiary properties averaged $10.69 per BOE, higher than our 2002
average of $10.05 per BOE. Our tertiary recovery fields are expected to average
between $9 and $10 per BOE in operating expenses over the life of the field,
although the cost per BOE is usually higher at the beginning of each operation
as there is a time lag between the initial injection of the CO2 into the
reservoir and the response of increased oil production. This compares to a cost
of around $5 per BOE for a more traditional oil property without secondary or
tertiary operations.
Operating Results
Our operating results for the first six months and second quarter of 2003,
excluding the loss on early retirement of debt in the second quarter of 2003
relating to the subordinated debt refinancing, were slightly better than our
results for the comparable periods of the prior year, primarily due to the
higher commodity prices, particularly natural gas, partially offset by higher
overall expenses. During the first quarter of 2003, we implemented SFAS No. 143,
"Accounting for Asset Retirement Obligations," as more fully discussed below
under "Depletion, Depreciation and Amortization" and Note 3 to the Consolidated
Financial Statements. The adoption of SFAS No. 143 is recorded as a cumulative
effect adjustment of a change in accounting principle, net of income taxes, in
our Consolidated Statements of Operations and is listed below on both a gross
dollar and per share basis.
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------- --------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 2003 2002 2003 2002
- -------------------------------------------------------- ------------ ------------- ------------- ------------
Income before cumulative effect of change in
accounting principle $ 5,129 $ 13,498 $ 23,582 $ 18,044
Cumulative effect of change in accounting principal,
net of income tax expense of $1,600 - - 2,612 -
------------ ------------- ------------- ------------
Net income $ 5,129 $ 13,498 $ 26,194 $ 18,044
============ ============= ============= ============
Net income per common share - basic:
Income before cumulative effect of change in
accounting principle $ 0.10 $ 0.25 $ 0.44 $ 0.34
Cumulative effect of change in accounting principle - - 0.05 -
------------ ------------- ------------- ------------
Net income per common share - basic $ 0.10 $ 0.25 $ 0.49 $ 0.34
============ ============= ============= ============
Net income per common share - diluted:
Income before cumulative effect of change in
accounting principle $ 0.09 $ 0.25 $ 0.42 $ 0.33
Cumulative effect of change in accounting principle - - 0.05 -
------------ ------------- ------------- ------------
Net income per common share - diluted $ 0.09 $ 0.25 $ 0.47 $ 0.33
============ ============= ============= ============
RECONCILIATION OF GAAP AND NON-GAAP MEASURES
Adjusted cash flow from operations (see below) $ 48,989 $ 43,423 $ 96,355 $ 71,947
Net change in assets and liabilities relating to operations 11,553 3,149 (304) (13,343)
------------ ------------- ------------- ------------
Cash flow from operations (1) $ 60,542 $ 46,572 $ 96,051 $ 58,604
============ ============= ============= ============
(1) Net cash flow provided by operations as per the Consolidated Statements of
Cash Flows.
Adjusted cash flow from operations is a non-GAAP measure that represents
cash flow provided by operations before changes in assets and liabilities, as
summarized from our Consolidated Statements of Cash Flows. In our discussion of
cash flow from operations herein, we have elected to discuss the two primary
components of cash flow provided by operations.
Adjusted cash flow from operations measures the cash flow earned or
incurred from operating activities without regard to the collection or payment
of associated receivables or payables. We believe that this is important to
consider separately, as we believe it can often be a better way to discuss
changes in operating trends in our business caused by changes in production,
prices, operating costs, and so forth, without regard to whether the earned or
incurred item was collected or paid during that period. We also use this measure
because the collection of our receivables or payment of our obligations
generally have not been a significant issue for our business, but merely a
timing issue from one period to the next, with fluctuations generally caused by
significant changes in commodity prices or significant changes in drilling
activity.
The net change in assets and liabilities relating to operations is also
important, as it does require or provide additional cash for use in our
business; however, we prefer to discuss its effect separately. For instance, as
noted above, during the second quarter of 2003 we generated approximately $11.6
million of cash by reducing our net working capital. This reduction primarily
relates to the collection in April of unusually high dollar amounts of accrued
production receivables at March
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
31, 2003, due to high natural gas prices for March production of approximately
$9.28 per MMBtu. Similarly, we used a significant amount of cash flow from
operations in the first half of 2002 to fund a $13.3 million increase in working
capital, primarily relating to a significant reduction of our payables and
accrued liabilities in early 2002 following a high level of drilling and
exploitation activity late in 2001. While both are components of the GAAP
measure, we believe that it makes sense to discuss them independently.
Certain of our operating results and statistics for the comparative first
six months and second quarters of 2003 and 2002 are included in the following
table.
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------------------------------------------- -------------------------
2003 2002 2003 2002
- --------------------------------------------------------------------------- ------------ ------------- -----------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 18,957 17,921 19,259 17,831
Mcf 96,558 105,634 97,857 105,680
BOE(1) 35,050 35,526 35,569 35,444
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 43,922 $ 37,404 $ 96,135 $ 65,237
Natural gas sales 50,830 33,710 110,341 56,787
Gain (loss) on settlements of derivative contracts (13,356) 12 (41,041) 2,648
------------- ------------ ------------- -----------
Total oil and natural gas revenues $ 81,396 $ 71,126 $ 165,435 $ 124,672
============= ============ ============= ===========
Lease operating expenses $ 23,048 $ 17,124 $ 45,450 $ 32,552
Production taxes and marketing expenses 3,466 3,297 7,362 5,911
------------- ------------ ------------- -----------
Total production expenses $ 26,514 $ 20,421 $ 52,812 $ 38,463
============= ============ ============= ===========
CO2 sales to industrial customers $ 2,445 $ 1,896 $ 4,634 $ 3,386
CO2 operating costs 534 362 851 529
------------- ------------ ------------- -----------
CO2 operating margin $ 1,911 $ 1,534 $ 3,783 $ 2,857
============= ============ ============= ===========
UNIT PRICES-INCLUDING IMPACT OF HEDGES
Oil price per barrel ("Bbl") $ 23.93 $ 22.94 $ 24.32 $ 20.36
Gas price per thousand cubic feet ("Mcf") 4.56 3.51 4.55 3.08
UNIT PRICES-EXCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 25.46 $ 22.94 $ 27.58 $ 20.21
Gas price per Mcf 5.78 3.51 6.23 2.97
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1):
Oil and natural gas revenues (before hedging) $ 29.71 $ 22.00 $ 32.07 $ 19.02
============= ============ ============= ===========
Oil and gas lease operating costs $ 7.23 $ 5.30 $ 7.06 $ 5.07
Oil and gas production taxes and marketing expenses 1.08 1.02 1.15 0.92
------------- ------------ ------------- -----------
Total oil and gas production expenses $ 8.31 $ 6.32 $ 8.21 $ 5.99
- ------------------------------------------------------------- ============= ============ ============= ===========
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PRODUCTION: Production by area for each of the quarters of 2002 and the
first and second quarters of 2003 is listed in the following table.
Average Daily Production (BOE/d)
-------------------------------------------------------------------- -------------
First Second Third Fourth First Second
Quarter Quarter Quarter Quarter Quarter Quarter
Operating Area 2002 2002 2002 2002 2003 2003
- --------------------------------- ----------- ------------ ------------ ------------- ------------- -------------
Mississippi - non-CO2 floods 12,423 12,124 13,232 15,703 14,537 13,600
Mississippi - CO2 floods 3,839 4,278 3,895 3,863 4,345 4,522
Onshore Louisiana 8,405 7,717 8,224 7,859 8,509 8,231
Offshore Gulf of Mexico 10,550 11,229 9,863 8,287 8,544 8,537
Other 144 178 292 182 158 160
----------- ------------ ------------ ------------- ------------- -------------
Total Company 35,361 35,526 35,506 35,894 36,093 35,050
- --------------------------------- =========== ============ ============ ============= ============= =============
When comparing production in the first half and second quarters of 2002 and
2003, the COHO acquisition in August of 2002 (Mississippi - non-CO2 flood
properties) was the single biggest source of production growth, adding 2,127
BOE/d to the second quarter of 2003 average production rate, net of the
acquisition property (Laurel Field) sold in January 2003 (see paragraph below).
We also benefited from a 375 BOE/d (9%) increase and 244 BOE/d (6%) increase in
our tertiary recovery projects when comparing the respective first six months
and second quarters of 2002 and 2003, respectively. Almost completely offsetting
these increases were general production declines from normal depletion, coupled
with less than expected production increases from first half 2003 exploration
and development results and unexpected delays offshore and temporary CO2
curtailments (see CO2 Operations above. The net result was that overall
production was almost the same when comparing the respective periods in 2002 and
2003.
During the first quarter of 2003, we sold Laurel Field, a Mississippi
non-CO2 flood property that had average production of between 1,500 and 1,700
BOE/d since we acquired it in August 2002. The field was sold effective January
31, 2003, causing a decrease in our first quarter 2003 production, as compared
to the fourth quarter of 2002, by approximately 1,100 BOE/d, and reducing second
quarter 2003 production by the full 1,500 to 1,700 BOE/d. Production in our
first and second quarters of 2003 was also negatively affected by mechanical
failures in two of our onshore Louisiana natural gas wells, reducing production
by approximately 500 BOE/d in the first quarter and approximately 400 BOE/d in
the second quarter. While both of these wells are currently producing, one well,
the Leon Hebert Heirs, is still producing only at approximately 75% of its
original rate, or about 200 BOE/d less than its average historical rate. We plan
to leave the well at this reduced rate for a period of time in order to minimize
the possibility of additional problems.
Early in the third quarter, we drilled an exploratory discovery well at
North Lirette Field, the Exxon Fee #1, which is currently producing at
approximately 7.5 MMcf/d, net to us. We have preliminarily estimated that this
initial discovery well developed between 10 and 15 Bcf of new proved reserves,
net to us. We are currently drilling a second well to test further potential in
this area, which is expected to be completed in late third quarter or early
fourth quarter of 2003. The preliminary estimates of reserves and production
from this discovery initially appear to more than make up for our less than
expected exploration results during the first half of the year.
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Five offshore wells scheduled for the first seven months of 2003 have been
delayed while waiting for partner approvals and clearance of other logistical
issues. We have up to six wells scheduled for the last five months of 2003,
although due to the timing, these wells will not have a meaningful production
impact in 2003. The net effect of these schedule changes was minor to the second
quarter production, but is expected to impact originally forecasted third and
fourth quarter production by approximately 800 and 900 BOE/d, respectively. The
installation of production facilities at North Padre Island, the Company's
year-end 2002 discovery, is still on schedule, and this field is expected to
commence production during the fourth quarter.
With regard to specific fields, production increased at Heidelberg Field, a
Mississippi non-CO2 flood property and our single largest field, from 7,458
BOE/d in the second quarter of 2002 to 7,612 BOE/d in the second quarter of
2003, as a result of incremental natural gas production from several wells
drilled at Heidelberg during the last twelve months. During the second quarter
of 2003, natural gas production averaged 10.4 MMcf/d, making Heidelberg Field
our second largest natural gas field (as measured by current quarter
production). Production at Thornwell Field averaged 2,820 BOE/d (mostly natural
gas) during the second quarter of 2003, down from 3,479 BOE/d during the
comparable quarter of 2002. Most of the production at Thornwell Field is
short-lived natural gas production that fluctuates with drilling activity.
During 2003, we have drilled three wells at Thornwell Field area, one of which
was unsuccessful. We are continuing development and exploration activities at
Thornwell Field in 2003, although at a lower level than in 2002.
Our production for the second quarter of 2003 was weighted slightly towards
oil (54%), primarily due to the mechanical problems with two onshore Louisiana
natural gas wells, less than expected results in natural gas wells drilled or
re-worked during the first six months of 2003, and delays in drilling offshore,
all as discussed above. Due to the these issues, it appears that we will remain
weighted slightly towards oil throughout 2003, unless we make any acquisitions
that are predominately oil or predominantly natural gas.
OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues, net of hedge
receipts and payments, for the second quarter of 2003 increased $10.3 million,
or 14%, from the comparable quarter of 2002, but decreased when comparing the
second quarter of 2003 with the first quarter of 2003. The increase in oil and
natural gas revenues when comparing the two second quarters was primarily due to
the increase in commodity prices, which increased these revenues by $24.6
million, or 34%, from levels in the prior year quarter. This increase was
partially offset by a slight decrease in production volumes, which decreased
these revenues by $0.9 million, or 1%. In addition, significant losses on the
settlements of derivative contracts reduced these revenues by $13.4 million, or
19%, when comparing the two second quarters.
Oil and natural gas revenues, net of hedge receipts and payments, for the
first half of 2003 increased $40.8 million, or 33%, from the comparable first
half of 2002, also primarily due to the increase in commodity prices, which
increased revenues by $84.0 million, or 67%, from levels in the first half of
2002. Production volumes were almost identical between the respective first six
months, causing only a slight increase in revenue of $400,000. These increases
were partially offset by significant losses on the settlements of derivative
contracts, which reduced revenues by $43.6 million, or 35%, when comparing the
two respective first halves.
Our realized natural gas prices (excluding hedges) for the second quarter
and first half of 2003 averaged $5.78 per Mcf and $6.23 per Mcf respectively, a
65% and 110% increase from the average of $3.51 per Mcf and $2.97 per Mcf
realized during the second quarter and first half of 2002. Our realized oil
prices (excluding hedges) for the second quarter and first half of 2003 averaged
$25.46 per Bbl and $27.58 per Bbl, respectively, an 11% and 36% increase from
the $22.94 per Bbl and $20.21 per Bbl average realized in the second quarter and
first half of 2002. Under our hedges, we paid out a sizable portion of our
increase in revenues due to commodity prices, with the payment of $13.4 million
on our hedges in the second quarter of 2003 and $41.0 million in the first half
of 2003, as compared to collections of $12,000 on our commodity hedges in the
second quarter of 2002 and $2.6 million in the first half of 2002.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
During 2002, we received an average discount to NYMEX prices on our oil
production of approximately $3.73 per Bbl, ranging from $3.30 to $4.25 per Bbl
on a quarterly basis. During 2003, the first quarter discount was $4.22 per Bbl
while the discount during the second quarter improved to $3.47 per Bbl, one of
the lowest discounts we have experienced in our recent corporate history. This
is similar to the trend in 2002, during which the lowest discount for the year
was during the second quarter. Although this has had little impact to date on
our year-over-year comparisons, it does have a significant impact on our cash
flow from quarter to quarter, as it directly impacts our net realized oil price.
While this discount is difficult to predict, as it fluctuates due to several
different market factors, we do not anticipate that it will remain at the second
quarter level for the rest of 2003. Long term, we expect our average discount to
gradually improve from our historically high levels, as a larger percentage of
our oil production will come from our tertiary recovery operations, which
produce a light, sweet oil that receives a price that approximates NYMEX prices.
On a weighted average net price per BOE, we received $7.71 and $13.05 per
BOE more for our production (excluding hedges) in the second quarter and first
half of 2003, respectively, than in the comparable periods of 2002. However, we
paid out approximately $4.19 per BOE and $6.37 per BOE on our oil and natural
gas hedges in the same 2003 periods, respectively, as compared to minor cash
receipts in the prior year quarter and $0.41 per BOE of receipts in the prior
year first half, reducing our net realized price increase to approximately $3.52
per BOE between the respective second quarters and approximately $6.27 per BOE
between the respective first six months.
PRODUCTION EXPENSES: Lease operating expenses increased to $7.23 per BOE
and $7.06 per BOE in the second quarter and first half of 2003, respectively,
from $5.30 per BOE and $5.07 per BOE in the comparable periods of 2002, both of
which were also higher than our fourth quarter 2002 average of $6.34 per BOE.
The costs of the two workovers relating to mechanical failures at two onshore
Louisiana gas wells discussed above, totaling approximately $850,000 in the
first quarter and $2.0 million in the second quarter of 2003, were the biggest
source of the increase, although continued high expenses on the properties
acquired from COHO, continued expansion of CO2 tertiary projects (which
typically have a higher than average cost per BOE), along with higher lease fuel
costs caused by high natural gas prices, also contributed to the higher than
historical level of operating costs. We anticipate that our lease operating
expenses on a per BOE basis will be lower during the last half of the year,
assuming a return to normal operating parameters.
Production taxes and marketing expenses also increased to $1.08 per BOE and
$1.15 per BOE in the second quarter and first half of 2003, respectively, from
$1.02 per BOE and $0.92 per BOE in the comparable periods of 2002, primarily due
to higher commodity prices.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 4% and 10% on a per
BOE basis between the respective second quarters and respective first six
months, as set forth below:
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------------- --------------------------------- --------------------------------
2003 2002 2003 2002
- ------------------------------------------- --------------- --------------- -------------- ---------------
NET G&A EXPENSE (THOUSANDS)
Gross G&A expenses $ 10,971 $ 9,471 $ 22,403 $ 18,980
State franchise taxes 358 361 721 728
Operator overhead charges (6,508) (5,345) (13,023) (10,548)
Capitalized exploration costs (1,445) (1,193) (2,934) (2,650)
--------------- --------------- -------------- ---------------
Net G&A expense $ 3,376 $ 3,294 $ 7,167 $ 6,510
=============== =============== ============== ===============
Average G&A expense per BOE $ 1.06 $ 1.02 $ 1.11 $ 1.01
Employees as of June 30 369 332 369 332
- ------------------------------------------- --------------- -------------- -------------- ---------------
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gross G&A expenses increased $1.5 million and $3.4 million, or 16% and 18%,
between the second quarters and first six months of 2002 and 2003, respectively.
The largest components of this increase relate to expenses associated with the
recent sale of stock by the Texas Pacific Group in the first quarter of 2003,
higher year-end expenses than in the prior year for engineering fees and audit
fees, incremental expenses associated with the requirements of the
Sarbanes-Oxley Act and an overall increase in personnel and associated expenses.
The increase in gross G&A is offset in part by an increase in operator overhead
recovery charges and capitalized exploration costs in 2003. 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 from
our recent acquisitions and drilling activity during the past year, the amount
we recovered as operator overhead charges increased by 22% and 23% between the
respective second quarters and first six months of 2002 and 2003, respectively.
Capitalized exploration costs increased slightly between the comparable periods
in 2002 and 2003, along with the increase in employees, employee related costs
and certain administrative overhead costs. The net effect of the increase in
gross G&A expenses, operator overhead charges and capitalized exploration costs
was a 2% and 10% increase in net G&A expense between the respective second
quarters and first six months. On a per BOE basis, G&A expenses increased 4% and
10% in the second quarter and first half of 2003 as compared to the comparable
periods of 2002.
Interest and Financing Expenses
Three Months Ended Six Months Ended
June 30, June 30,
- ----------------------------------------------------- ----------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002 2003 2002
- ----------------------------------------------------- -------------- ------------- ------------ ------------
Interest expense $ 6,227 $ 6,572 $ 12,688 $ 13,226
Non-cash interest expense (296) (650) (799) (1,301)
-------------- ------------- ------------ ------------
Cash interest expense 5,931 5,922 11,889 11,925
Interest and other income (347) (411) (551) (822)
-------------- ------------- ------------ ------------
Net cash interest expense $ 5,584 $ 5,511 $ 11,338 $ 11,103
============== ============= ============ ============
Average net cash interest expense per BOE $ 1.75 $ 1.70 $ 1.76 $ 1.73
Average interest rate (1) 6.5% 6.9% 6.6% 7.0%
Average debt outstanding $ 367,747 $ 342,593 $ 359,696 $ 342,502
- ----------------------------------------------------- -------------- ------------- ------------ ------------
(1) Includes commitment fees but excludes amortization of debt issue costs.
Interest expense for the second quarter of 2003 decreased from levels in
the comparable prior year period primarily due to (i) lower overall interest
rates, in part due to the refinancing of our subordinated debt (see "Debt
Refinancing" above), as our average outstanding debt balance was 7% higher in
the second quarter of 2003, and (ii) reduced debt issue cost amortization
resulting from the complete amortization of costs associated with the original
maturity of our bank credit line in December 2002. The primary reason for the
higher average debt levels in the second quarter of 2003 was that both issues of
subordinated debt were outstanding for 16 days during the quarter due to the
mechanics of the required 30 day notice to call the old notes.
Partially offsetting the interest expense savings was a slight decrease in
our interest and other income in the second quarter of 2003. We expect a further
decrease in interest expense as a result of the refinancing of our subordinated
debt, which is expected to save approximately $2.6 million per year in interest
expense. This decrease will not be fully recognized until the third quarter of
2003, as the old subordinated debt was not retired until April 16, 2003.
Interest expense decreased between the respective six month periods for similar
reasons, although the decrease was not as substantial on a percentage basis as
in the comparable second quarters, as the subordinated debt refinancing was not
completed until April 16, 2003.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depletion, Depreciation and Amortization
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------- ----------------------------- -----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002 2003 2002
- ---------------------------------------------------- ------------- ------------- ------------- --------------
Depletion and depreciation $ 21,449 $ 22,383 $ 43,429 $ 43,599
Depreciation of CO2 assets 592 613 1,030 1,139
Accretion of discount on asset retirement
obligations 684 - 1,503 -
Site restoration provision - 789 - 1,563
Depreciation of other fixed assets 405 420 721 830
------------- ------------- ------------- --------------
Total DD&A $ 23,130 $ 24,205 $ 46,683 $ 47,131
============= ============= ============= ==============
DD&A per BOE:
Oil and natural gas properties $ 6.94 $ 7.17 $ 6.98 $ 7.04
CO2 assets and other fixed assets 0.31 0.32 0.27 0.31
------------- ------------- ------------- --------------
Total DD&A cost per BOE $ 7.25 $ 7.49 $ 7.25 $ 7.35
- --------------------------------------------------- ============= ============= ============= ==============
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis was almost the same in the second quarters and first six months of
2003 and 2002, and similar to the average rate per BOE during 2002. Our DD&A
rate is evaluated each quarter and is adjusted to our best estimate of projected
reserves at year-end, and estimated production and capital expenditures for the
full year 2003. Based on the ultimate outcome of these factors, we adjust our
DD&A computation for the full year in the fourth quarter. Although, as
previously stated, our exploration results in the first six months of 2003 were
not as good as expected; however, we have had recent success in a new discovery
at Lirette Field and we have up to an additional five exploratory wells planned
for the remainder of 2003. Also, we are in the process of expanding our tertiary
recovery properties and expect that we will be able to add additional reserves
by year-end. Based on our current estimates related to these items, we have left
our DD&A rate unchanged from the first quarter of 2003. However, depending on
the outcome of these estimates and other factors that could change before
year-end 2003, our DD&A rate could change significantly in the last half of
2003.
Effective January 1, 2003, we adopted Statement of Financial Accounting
Standards ("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, discounted to its
present value using our credit adjusted risk-free interest rate, and that the
corresponding amount be capitalized by increasing the carrying amount of the
related long-lived asset. The liability is accreted 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, the
difference is recorded to the full cost pool, unless significant. The adoption
of this statement resulted in a $2.6 million benefit to net income during the
first quarter of 2003 and was recorded as a cumulative effect of a change in
accounting principle in our Consolidated Statements of Operations. As part of
the adoption, we ceased accruing for site reclamation costs, as had been our
practice in the past, and recorded a $41.0 million liability representing the
estimated present value of our retirement obligations, with a $34.4 million
increase to oil and natural gas properties. On an undiscounted basis, we
estimated that our retirement obligations as of January 1, 2003 to be $81.8
million, with an estimated salvage value of $43.3 million, also on an
undiscounted basis. DD&A is calculated on the increase to oil and natural gas
properties, net of estimated salvage value. We also include the accretion of
discount on the asset retirement obligation in our DD&A expense.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------------- ------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS AND TAX RATES 2003 2002 2003 2002
- ---------------------------------------------------------- ------------ ----------- ------------ ------------
Current income tax expense (benefit) $ (1,093) $ 33 $ 1,637 $ (448)
Deferred income tax expense 3,527 6,080 9,882 7,538
------------ ----------- ------------ ------------
Total income tax expense $ 2,434 $ 6,113 $ 11,519 $ 7,090
============ =========== ============ ============
Average income tax expense per BOE $ 0.76 $ 1.89 $ 1.79 $ 1.11
Effective tax rate 32.2% 31.2% 32.8% 28.2%
- ---------------------------------------------------------- ------------ ----------- ------------ ------------
Our income tax provision for the second quarter and first half of 2002 was
based on an estimated effective tax rate of 37%, although we increased this
effective rate to 38% in the third quarter of 2002. The net effective tax rate
was lower than the statutory rates, primarily due to the recognition of enhanced
oil recovery credits which lowered our overall tax expense. During 2002, we
utilized alternative minimum tax loss carryfowards, virtually eliminating our
current tax expense. The current income tax credit in the first six months of
2002 was 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 offset only 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. As of January 1, 2003, we had utilized
virtually all of the alternative minimum tax carryforwards and thus recognized
current income tax expense for the projected alternative minimum taxes that are
expected to be incurred during 2003. We recognized a current income tax credit
of $1.1 million in the 2003 second quarter due to a downward revision in our
2003 forecast of taxable income.
30
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 Six Months Ended
June 30, June 30,
---------------------------- --------------------------
Per BOE Data 2003 2002 2003 2002
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Revenue $ 29.71 $ 22.00 $ 32.07 $ 19.02
Gain (loss) on settlements of derivative contracts (4.19) - (6.37) 0.41
Lease operating expenses (7.23) (5.30) (7.06) (5.07)
Production taxes and marketing expenses (1.08) (1.02) (1.15) (0.92)
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Production netback 17.21 15.68 17.49 13.44
Operating cash flow from CO2 operations 0.60 0.47 0.59 0.45
General and administrative expenses (1.06) (1.02) (1.11) (1.01)
Net cash interest expense (1.75) (1.70) (1.76) (1.73)
Current income taxes and other 0.36 - (0.24) 0.06
Changes in assets and liabilities 3.62 0.98 (0.05) (2.08)
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Cash flow from operations 18.98 14.41 14.92 9.13
DD&A (7.25) (7.49) (7.25) (7.35)
Deferred income taxes (1.11) (1.88) (1.54) (1.18)
Amortization of derivative contracts and other non-cash
hedging adjustments 0.24 0.31 0.35 0.33
Early retirement of subordinated debt (5.53) - (2.74) -
Cumulative effect of a change in accounting principle - - 0.41 -
Changes in assets and liabilities and other non-cash items (3.72) (1.18) (0.08) 1.88
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Net income $ 1.61 $ 4.17 $ 4.07 $ 2.81
- ---------------------------------------------------------- ============= ============= ============ ============
NEW ACCOUNTING STANDARDS
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies certain accounting and reporting for derivative instruments. This
statement is effective for contracts entered into or modified after June 30,
2003. We will adopt this statement in the third quarter of 2003 and it should
not have any impact on our financial statements.
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," became effective July 1, 2001 and January 1, 2002,
respectively. It is our understanding that the Securities and Exchange
Commission has raised questions as to the proper application by registrants in
the oil and gas industry of the provisions of SFAS No. 141 and SFAS No. 142 and
that the FASB and representatives from the SEC are currently in discussions
regarding this issue. In question is whether the acquisition of contractual
mineral interests, including both proved and undeveloped, should be classified
separately as "intangible assets" on the balance sheet apart from other oil and
gas property costs. Currently, Denbury, and virtually all other companies in the
oil and gas industry, have historically included purchased contractual mineral
rights in oil and gas properties on the balance sheet. Until we receive further
guidance regarding this issue, we will continue to include mineral interests as
oil and gas properties on our balance sheet for mineral interests acquired
subsequent to June 30, 2001. Based on the limited guidance pertaining to this
issue, we have not calculated the potential balance sheet reclassification at
this time. The provisions of SFAS No. 141 and 142 impact only the balance sheet
and associated footnote disclosure, and any reclassifications, if necessary,
would not impact the Company's results of operations or cash flows.
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MARKET RISK MANAGEMENT
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. 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
- ---------------------------------------- ------------------------------------------------ ----------- -----------
Carrying Fair
Amounts in Thousands 2003-2005 2006 2007 Thereafter Value Value
- ---------------------------------------- ----------- ----------- ------------ ----------- ----------- -----------
Variable rate debt:
Bank debt.......................... $ - $110,000 $ - $ - $110,000 $110,000
The weighted-average interest rate on the bank debt at June 30, 2003 was 3.0%.
Fixed rate debt:
7.5% subordinated debt, net of
discount, due 2013............... $ - $ - $ - $225,000 $223,106 $232,875
The interest rate on the subordinated debt is a fixed rate of 7.5%.
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. 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 budgeted exploration and development
expenditures without incurring significant debt. When we make an acquisition, we
attempt to hedge a large percentage, up to 100%, of the forecasted production
for the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. Our recent hedging activity
has been predominately through the purchase of collars, although for the recent
COHO acquisition, we also used swaps in order to lock in the prices used in our
economic forecasts. 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 counter party credit risk
through established internal control procedures which are reviewed on an ongoing
basis. We attempt to minimize credit risk exposure to counter parties through
formal credit policies, monitoring procedures, and diversification.
At June 30, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $58.4 million, an increase of
approximately $22.8 million from the $35.6 million fair value liability recorded
as of December 31, 2002. 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, 2002 and June 30, 2003, and (ii) the expiration of
certain derivative contracts during 2003 for which we recorded amortization
expense of $591,000. Information regarding our current hedging positions is
included in Note 9 to the Consolidated Financial Statements.
Based on NYMEX natural gas futures prices at June 30, 2003, we would expect
to make future cash payments of $40.4 million on our natural gas commodity
hedges. If natural gas futures prices were to decline by 10%, the amount we
would expect to pay under our natural gas commodity hedges would decrease to
$20.9 million, and if futures prices were to increase by 10% we would expect to
pay $61.9 million. Based on NYMEX crude oil futures prices at June 30, 2003, we
would expect to pay $15.4 million on our crude oil commodity hedges. If crude
oil futures prices were to decline by 10%, we would expect to pay $2.9 million,
and if crude oil futures prices were to increase by 10%, we would expect to pay
$31.5 million under our crude oil commodity hedges.
32
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to
property, plant and equipment, depletion and depreciation, oil and natural gas
reserves and hedging activities, and which remain unchanged, see our annual
report on Form 10-K for the year ended December 31, 2002.
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, CO2 production and deliverability, liquidity, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "estimate," "budgeted," "expect,"
"predict," "anticipate," "projected," "should," "assume," "believe" or other
words that convey the uncertainty of future events or outcomes. Such
forward-looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and our financial condition and results of
operations. As a consequence, actual results may differ materially from
expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for our oil and natural gas, the uncertainty of
drilling results and reserve estimates, operating hazards, 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.
33
DENBURY RESOURCES INC.
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
- --------------------------------
Denbury maintains disclosure controls and procedures designed to ensure
that information required to be disclosed in our filings under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commission's rules and
forms. Our chief executive officer and chief financial officer have evaluated
our disclosure controls and procedures as of the end of the period covered by
this Quarterly Report on Form 10-Q and have determined that such disclosure
controls and procedures are effective in all material respects.
There have been no significant changes in internal controls over financial
reporting during the period covered by this Quarterly Report on Form 10-Q that
have materially affected, or are reasonably likely to materially affect,
Denbury's internal controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------------------------------------------------------------
Denbury's Annual Meeting of Shareholders was held on May 20, 2003 for the
purposes of: (1) electing nine Directors of Denbury for one-year terms to expire
at the 2004 Annual Meeting of Shareholders, and (2) increasing the number of
shares issuable under the Company's Employee Stock Option Plan by 850,000
shares. At the record date, April 4, 2003, 53,741,052 shares of common stock
were outstanding and entitled to one vote per share upon all matters submitted
at the meeting. Holders of 43,976,489 shares of common stock, representing
approximately 82% of the total issued and outstanding shares of common stock,
were present in person or by proxy at the meeting to cast their vote.
With respect to the election of directors, all nine director nominees were
re-elected. The votes were cast as follows:
NOMINEES FOR DIRECTORS FOR AGAINST
- ---------------------- ----------------- ------------------
Ronald G. Greene 43,260,167 716,322
David Bonderman 35,093,388 8,883,101
David I. Heather 43,260,167 716,322
David B. Miller 43,260,167 716,322
William S. Price, III 43,260,167 716,322
Gareth Roberts 36,934,925 7,041,564
Jeffrey Smith 43,260,167 716,322
Wieland F. Wettstein 43,260,167 716,322
Carrie A. Wheeler 43,260,167 716,322
The proposed increase in the shares issuable under the Company's Employee
Stock Option Plan was also approved. The votes were cast as follows:
FOR AGAINST ABSTENTIONS
- ----------------- ---------------- -------------------
39,975,053 3,491,562 509,874
34
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K DURING THE SECOND QUARTER OF 2003
- ---------------------------------------------------------------------------
EXHIBITS:
--------
4(a) Indenture for $225 million of 7-1/2% Senior Subordinated
Notes Due 2013 among Denbury Resources Inc., certain of its
subsidiaries and JPMorgan Chase Bank as trustee, dated
March 25, 2003 (incorporated by reference to Exhibit 4(a)
to our Registration Statement No. 333-105233 on Form S-4,
dated May 14, 2003).
10(a) Denbury Resources Inc. Amended and Restated Stock Option
Plan (incorporated by reference to Exhibit 99 of our
Registration Statement No. 333-106253 on Form S-8, dated
June 18, 2003).
10(b)* Second Amendment to Third Amended and Restated Credit Agreement.
15* Letter from Independent Accountants as to unaudited interim financial information.
31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
* Filed herewith.
REPORTS ON FORM 8-K:
-------------------
On May 1, 2003, we filed a Form 8-K which included our press release on our
first quarter 2003 earnings.
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: August 12, 2003
36