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 MARCH 31, 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 APRIL 30, 2003
----- -----------------------------
Common Stock, $.001 par value 53,754,702
DENBURY RESOURCES INC.
INDEX
Page
----
Part I. Financial Information
- ------------------------------
Item 1. Financial Statements
Independent Accountants' Report 3
Consolidated Balance Sheets at March 31, 2003 (Unaudited)
and December 31, 2002 4
Consolidated Statements of Operations for the Three Months
Ended March 31, 2003 and 2002 (Unaudited) 5
Consolidated Statements of Cash Flows for the Three Months
Ended March 31, 2003 and 2002 (Unaudited) 6
Consolidated Statements of Comprehensive Income (Loss) for
the Three Months Ended March 31, 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 19-31
Item 3. Quantitative and Qualitative Disclosures about Market Risk 32
Item 4. Controls and Procedures 32
Part II. Other Information
- ---------------------------
Item 6. Exhibits and Reports on Form 8-K 32
Signatures 33
Certifications 34-35
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 consolidated balance sheet of Denbury
Resources Inc. and subsidiaries (the "Company") as of March 31, 2003, and the
related consolidated statements of operations, cash flows and comprehensive
income (loss) for the three month periods ended March 31, 2003 and 2002. 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
May 13, 2003
3
DENBURY RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
(Unaudited)
March 31, December 31,
2003 2002
--------------- ---------------
ASSETS
Current assets
Cash and cash equivalents $ 161,170 $ 23,940
Accrued production receivables 48,042 34,458
Related party accrued production receivable - Genesis 5,615 3,334
Trade and other receivables 18,413 16,846
Deferred tax asset 44,529 49,886
------------ -----------
Total current assets 277,769 128,464
------------ -----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties (using full cost accounting)
Proved 1,288,413 1,245,896
Unevaluated 47,517 45,736
CO2 properties and equipment 68,827 62,370
Less accumulated depletion and depreciation (628,399) (609,917)
------------ -----------
Net property and equipment 776,358 744,085
------------ -----------
INVESTMENT IN GENESIS 2,241 2,224
OTHER ASSETS 25,709 20,519
------------ -----------
TOTAL ASSETS $ 1,082,077 $ 895,292
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 53,388 $ 49,281
Oil and gas production payable 21,179 17,309
Derivative liabilities 40,112 29,289
Current subordinated debt 200,000 -
------------ -----------
Total current liabilities 314,679 95,879
------------ -----------
LONG-TERM LIABILITIES
Long-term debt 268,193 344,889
Asset retirement liabilities 38,790 6,845
Derivative liabilities 9,602 6,281
Deferred tax liability 67,979 71,663
Other 2,990 2,938
------------ -----------
Total long-term liabilities 387,554 432,616
------------ -----------
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;
53,741,052 and 53,539,329 shares issued and outstanding at March 31,
2003 and December 31, 2002, respectively 54 54
Paid-in capital in excess of par 397,593 395,906
Retained earnings (accumulated deficit) 11,190 (9,875)
Accumulated other comprehensive loss (28,993) (19,288)
------------ -----------
Total stockholders' equity 379,844 366,797
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,082,077 $ 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
March 31,
------------------------------------------
2003 2002
------------------ -----------------
REVENUES
Oil, natural gas and related product sales
Unrelated parties $ 99,311 $ 50,910
Related party - Genesis 12,413 -
CO2 sales 2,189 1,490
Gain (loss) on settlements of derivative contracts (27,685) 2,636
Interest and other income 204 411
------------------ -----------------
Total revenues 86,432 55,447
------------------ -----------------
EXPENSES
Lease operating expenses 22,402 15,428
Production taxes and marketing expenses 3,896 2,614
CO2 operating expenses 317 167
General and administrative expenses 3,791 3,216
Interest 6,461 6,654
Depletion and depreciation 23,553 22,926
Amortization of derivative contracts and other
non-cash hedging adjustments (1,510) (1,081)
------------------ -----------------
Total expenses 58,910 49,924
------------------ -----------------
EQUITY IN NET INCOME OF GENESIS 16 -
------------------ -----------------
INCOME BEFORE INCOME TAXES 27,538 5,523
INCOME TAX PROVISION (BENEFIT)
Current income taxes 2,730 (481)
Deferred income taxes 6,355 1,458
------------------ -----------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE 18,453 4,546
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF
INCOME TAXES OF $1,600 2,612 -
------------------ -----------------
NET INCOME $ 21,065 $ 4,546
================== =================
NET INCOME PER COMMON SHARE - BASIC
Income before cumulative effect of change in accounting
principle $ 0.34 $ 0.09
Cumulative effect of change in accounting principle 0.05 -
------------------ -----------------
Net income per common share - basic $ 0.39 $ 0.09
================== =================
NET INCOME PER COMMON SHARE - DILUTED
Income before cumulative effect of change in accounting
principle $ 0.33 $ 0.08
Cumulative effect of change in accounting principle 0.05 -
------------------ -----------------
Net income per common share - diluted $ 0.38 $ 0.08
================== =================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic 53,639 52,994
Diluted 55,049 53,724
(See accompanying Notes to Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
(Unaudited)
Three Months Ended
March 31,
----------------------------------
2003 2002
------------- ------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income $ 21,065 $ 4,546
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 23,553 22,926
Amortization of derivative contracts and other non-cash hedging adjustments (1,510) (1,081)
Deferred income taxes 6,355 1,458
Amortization of debt issue costs and other 515 675
Cumulative effect of change in accounting principle (2,612) -
Changes in assets and liabilities:
Accrued production receivable (15,865) (1,391)
Trade and other receivables (1,233) 14,424
Derivative assets - 9,028
Other assets (330) 732
Accounts payable and accrued liabilities 1,653 (37,688)
Oil and gas production payable 3,870 (1,357)
Other liabilities 48 (240)
------------- ------------
NET CASH PROVIDED BY OPERATIONS 35,509 12,032
------------- ------------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures (32,668) (24,192)
Acquisitions of oil and gas properties (3,693) (2,084)
Acquisitions of CO2 assets and capital expenditures (6,904) (335)
Proceeds from oil and gas property sales 26,366 -
Increase in restricted cash (146) (149)
Net purchases of other assets (1,094) (369)
------------- ------------
NET CASH USED FOR INVESTING ACTIVITIES (18,139) (27,129)
------------- ------------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments (110,000) -
Bank borrowings 10,000 5,130
Issuance of subordinated debt 223,057 -
Issuance of common stock 1,325 842
Costs of debt financing (4,522) (2)
------------- ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES 119,860 5,970
------------- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 137,230 (9,127)
Cash and cash equivalents at beginning of period 23,940 23,496
------------- ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 161,170 $ 14,369
============= ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest $ 10,260 $ 10,654
Cash paid (refunded) during the period for income taxes - (849)
(See accompanying Notes to Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
(Unaudited)
Three Months Ended
March 31,
----------------------------------
2003 2002
------------- ------------
Net income $ 21,065 $ 4,546
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts (8,769) (12,226)
Amortization of derivative contracts 182 (1,620)
Reclassification adjustments related to derivative contracts (1,118) (2,301)
------------- ------------
Comprehensive income (loss) $ 11,360 $ (11,601)
============= ============
(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" refers to
Denbury Resources Inc. and its subsidiaries. These financial statements and the
notes thereto should be read in conjunction with our Annual Report on Form 10-K
for the year ended December 31, 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 March 31, 2003 and the consolidated results of its operations and
cash flows for the three month periods ended March 31, 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."
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. The adoption of this
statement on January 1, 2003 had no impact on the Company's financial statements
for any of the periods presented. However, in April 2003, we early retired our
$200 million of Senior Subordinated Notes Due 2008, and in the second quarter of
2003 we expect to record a $17.7 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 did not have
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 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. We are
currently evaluating the provisions of this statement to determine its impact,
if any, on our financial statements.
8
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Decmeber 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.
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 of 2003 cumulative effect
adjustment for the adoption of SFAS No. 143:
THREE MONTHS ENDED YEAR ENDED
MARCH 31, DECEMBER 31,
----------------------- ----------------------------------
2003 2002 2002 2001 2000
----------- ---------- ---------- ---------- ----------
NET INCOME: (THOUSANDS)
Net income, as reported ................... $ 21,065 $ 4,546 $ 46,795 $ 56,550 $142,227
Pro forma adjustments to reflect retroactive
adoption of SFAS 143................... (2,612) (248) 473 503 306
--------- -------- -------- -------- --------
Pro forma net income....................... $ 18,453 $ 4,298 $ 47,268 $ 57,053 $142,533
========= ======== ======== ======== ========
NET INCOME PER COMMON SHARE:
As reported:
Basic.................................. $ 0.39 $ 0.09 $ 0.88 $ 1.15 $ 3.10
Diluted................................ 0.38 0.08 0.86 1.12 3.07
Pro forma:
Basic.................................. $ 0.34 $ 0.08 $ 0.89 $ 1.16 $ 3.11
Diluted................................ 0.34 0.08 0.87 1.13 3.08
9
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the changes in our asset retirement
obligations for the three months ended March 31, 2003.
Three Months Ended
March 31, 2003
----------------------
(in thousands)
Beginning asset retirement obligation, as of 12/31/2002..... $ 6,845
Cumulative effect adjustment for SFAS 143, 1/1/2003......... 34,109
Liabilities incurred during period.......................... 91
Liabilities settled during period........................... (928)
Accretion expense........................................... 820
----------------------
Ending asset retirement obligation.......................... $ 40,937
======================
At March 31, 2003, $2.1 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 $8.8 million at March 31, 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 month periods ended March 31, 2003 and 2002, there were no adjustments to
net income for purposes of calculating diluted net income per common share. The
following is a reconciliation of the weighted average common shares used in the
basic and diluted net income per common share calculations for the three month
periods ended March 31, 2003 and 2002.
Three Months Ended
March 31,
--------------------------
2003 2002
------------ ------------
(shares in thousands)
Weighted average common shares - basic........ 53,639 52,994
Potentially dilutive securities:
Stock options............................ 1,410 730
------------ ------------
Weighted average common shares - diluted...... 55,049 53,724
============ ============
For the three months ended March 31, 2003 and 2002, common stock options to
purchase approximately 1.9 million and 2.4 million shares of common stock,
respectively, were outstanding but excluded from the diluted net income per
common share calculations, as the exercise prices of the options exceeded the
average market price of the Company's common stock during these periods and
would be anti-dilutive to the calculations.
5. SALE OF LAUREL FIELD
In February 2003, we sold Laurel Field, acquired in the COHO acquisition in
August 2002, for approximately $26.2 million and other consideration which
included an interest in Atchafalaya Bay Field (where we already owned
10
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
THREE MONTHS ENDED
MARCH 31,
--------------------------
2003 2002
------------ -----------
NET INCOME: (THOUSANDS)
Net Income, as reported ...................................... $ 21,065 $ 4,546
Less: stock-based compensation expense applying fair value
based method, net of related tax effects.................. 558 728
------------ -----------
Pro forma net income.......................................... $ 20,507 $ 3,818
============ ===========
NET INCOME PER COMMON SHARE:
As reported:
Basic..................................................... $ 0.39 $ 0.09
Diluted................................................... 0.38 0.08
Pro forma:
Basic..................................................... $ 0.38 $ 0.07
Diluted................................................... 0.38 0.07
7. INDEBTEDNESS
March 31, December 31,
2003 2002
--------------- ---------------
(Amounts in thousands)
(Unaudited)
9% Senior Subordinated Notes Due 2008......................................... $ 125,000 $ 125,000
9% Series B Senior Subordinated Notes Due 2008................................ 75,000 75,000
7.5% Senior Subordinated Notes Due 2013....................................... 225,000 -
Senior bank loan.............................................................. 50,000 150,000
Debt discount................................................................. (6,807) (5,111)
--------------- ---------------
Total debt................................................................ $ 468,193 $ 344,889
--------------- ---------------
Debt classified as short-term................................................. 200,000 -
--------------- ---------------
Long-term debt................................................................ $ 268,193 $ 344,889
=============== ===============
11
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. We issued the notes to refinance our
existing $200 million of 9% Senior Subordinated Notes Due 2008, including the
Series B notes. The notes were priced at 99.135% of par and our net proceeds
from the offering were approximately $218.5 million after underwriting and
issuance costs. A portion of the proceeds from the notes were temporarily used
to reduce our bank debt; however, the proceeds were ultimately used to retire
our existing $200 million of 9% Senior Subordinated Notes Due 2008, including
the Series B notes, in April 2003 (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 the 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.
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. Accordingly, we
have classified the $200 million of notes as a current liability at March 31,
2003. 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 estimate that we will have a before tax charge to
earnings in the second quarter of 2003 of approximately $17.7 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 recently reaffirmed at $220 million as part of
an amendment to our credit agreement completed in early May. 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 or reduction of sales and ad valorem taxes
on CO2 facilities we build in the next two years in Mississippi. We anticipate
entering into such bond funding arrangements 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.
At March 31, 2003, we had $50.0 million outstanding under our bank credit
facility, leaving us approximately $170.0 million of borrowing capacity. We also
had letters of credit outstanding in the amount of $730,000 at March 31, 2003.
12
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 month
period ended March 31, 2003 was $16,000. Genesis Energy, Inc., the general
partner of which we indirectly own 100%, has guaranteed the bank debt of
Genesis, which was $3.5 million as of March 31, 2003, and also included $30.0
million in letters of credit, of which $9.7 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
three month period ended March 31, 2003, we recorded sales to Genesis of $12.4
million and at March 31, 2003, had a production receivable from Genesis of $5.6
million.
Summarized financial information of Genesis Energy, L.P. is as follows
(amounts in thousands):
Three Months
Ended
March 31, 2003
-------------------
Revenues.................................. $ 261,882
Cost of sales............................. 256,627
Other expenses............................ 4,376
-------------------
Net income ............................ $ 879
===================
March 31, 2003
-------------------
Current assets............................ $ 97,170
Non-current assets........................ 46,423
-------------------
Total assets........................... $ 143,593
===================
Current liabilities....................... $ 103,358
Non-current liabilities................... 4,015
Partners' capital......................... 36,220
-------------------
Total liabilities and partners' capital $ 143,593
===================
13
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
March 31,
------------------------------------
2003 2002
---------------- ----------------
(Amounts in thousands)
Oil hedge contracts $ (8,738) $ 462
Gas hedge contracts (18,947) 2,174
---------------- ----------------
Net gain (loss) $ (27,685) $ 2,636
================ ================
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 three months ended March 31, 2003 and 2002, we
recorded premium amortization expense of $294,000 and $2.6 million,
respectively. Also, for the three months ended March 31, 2003, we reclassified
$1.3 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 $459,000 which is also included in "Amortization of
derivative contracts and other non-cash hedging adjustments."
Hedging Contracts at March 31, 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 March 31, 2003
- ---------------------------------- ------------- ------------- -------------- ------------ ------------ --------------
Collar Contracts
April 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ (2,539)
Swap Contracts
April 2003 - Dec. 2003 2,500 24.25 - - - (2,247)
April 2003 - Dec. 2003 2,000 24.30 - - - (1,770)
April 2003 - Dec. 2003 2,000 25.70 - - - (1,004)
Jan. 2004 - Dec. 2004 2,500 22.89 - - - (1,709)
Jan. 2004 - Dec. 2004 4,500 23.00 - - - (2,898)
Jan. 2004 - Dec. 2004 2,500 23.08 - - - (1,538)
14
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 March 31, 2003
- -------------------------------- ------------- ------------- ------------ ------------ ------------ ------------------
Collar Contracts
April 2003 - Dec. 2003 45,000 $ - $ - $ 2.75 $ 4.00 $ (14,907)
April 2003 - Dec. 2003 25,000 - - 2.75 4.07 (7,882)
Jan. 2004 - Dec. 2004 30,000 - - 3.50 4.45 (6,122)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.87 (1,343)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.82 (1,387)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (1,005)
Swap Contracts
April 2003 - Dec. 2003 10,000 3.905 - - - (3,362)
At March 31, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of $49.7 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 $29.0 million at March 31, 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 $2.3 million relating to the Enron hedges that ceased to
qualify for hedge accounting treatment when Enron filed for bankruptcy. This
$2.3 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 $29.0 million in
accumulated other comprehensive loss as of March 31, 2003, $24.9 million relates
to current hedging contracts that will expire within the next 12 months.
10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of August 2001, all of the Company's subordinated debt securities were
fully and unconditionally guaranteed by Denbury Resources Inc.'s significant
subsidiaries. Condensed consolidating financial information for Denbury
Resources Inc. and its significant subsidiaries as of March 31, 2003 and
December 31, 2002 and for the three months ended March 31, 2003 and 2002 is as
follows:
15
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Balance Sheets
March 31, 2003
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- ------------- --------------
ASSETS
Current assets..................................$ 248,664 $ 29,105 $ - $ 277,769
Property and equipment.......................... 506,929 269,429 - 776,358
Investment in subsidiaries (equity method)...... 209,188 2,241 (209,188) 2,241
Other assets.................................... 21,960 3,749 - 25,709
-------------- ------------- ------------- --------------
Total assets...............................$ 986,741 $ 304,524 $ (209,188) $ 1,082,077
============== ============= ============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities.............................$ 299,594 $ 15,085 $ - $ 314,679
Long-term liabilities........................... 307,303 80,251 - 387,554
Stockholders' equity............................ 379,844 209,188 (209,188) 379,844
-------------- ------------- ------------- --------------
Total liabilities and stockholders' equity.$ 986,741 $ 304,524 $ (209,188) $ 1,082,077
============== ============= ============= ==============
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 March 31, 2003
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues.....................................$ 57,285 $ 29,147 $ - $ 86,432
Expenses..................................... 44,320 14,590 - 58,910
--------------- -------------- -------------- --------------
Income before the following: 12,965 14,557 - 27,522
Equity in net earnings of subsidiaries.. 8,495 16 (8,495) 16
--------------- -------------- -------------- --------------
Income (loss) before income taxes and
cumulative effect of a change in accounting
principal................................. 21,460 14,573 (8,495) 27,538
Income tax provision......................... 4,376 4,709 - 9,085
--------------- -------------- -------------- --------------
Net income before cumulative effect of a
change in accounting principal............ 17,084 9,864 (8,495) 18,453
Cumulative effect of a change in accounting
principal, net of income taxes............ 3,981 (1,369) - 2,612
--------------- -------------- -------------- --------------
Net income (loss)............................$ 21,065 $ 8,495 $ (8,495) $ 21,065
=============== ============== ============== ==============
Three Months Ended March 31, 2002
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- --------------- --------------
Revenues.....................................$ 45,333 $ 10,114 $ - $ 55,447
Expenses..................................... 38,417 11,507 - 49,924
--------------- -------------- --------------- --------------
Income before the following: 6,916 (1,393) - 5,523
Equity in net earnings of subsidiaries.... (892) - 892 -
--------------- -------------- --------------- --------------
Income before income taxes................... 6,024 (1,393) 892 5,523
Income tax provision (benefit)............... 1,478 (501) - 977
--------------- -------------- --------------- --------------
Net income (loss)............................$ 4,546 $ (892) $ 892 $ 4,546
=============== ============== =============== ==============
17
DENBURY RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Cash Flows
Three Months Ended March 31, 2003
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 20,288 $ 15,221 $ - $ 35,509
Cash flow from investing activities.......... (3,701) (14,438) - (18,139)
Cash flow from financing activities.......... 119,860 - - 119,860
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... 136,447 783 - 137,230
Cash, beginning of period.................... 20,281 3,659 - 23,940
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 156,728 $ 4,442 $ - $ 161,170
================= ============== ============== ==============
Three Months Ended March 31, 2002
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 5,071 $ 6,961 $ - $ 12,032
Cash flow from investing activities.......... (18,301) (8,828) - (27,129)
Cash flow from financing activities.......... 5,970 - - 5,970
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... (7,260) (1,867) - (9,127)
Cash, beginning of period.................... 17,052 6,444 - 23,496
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 9,792 $ 4,577 $ - $ 14,369
================= ============== ============== ==============
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 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 $15.5 million, consisting of the debt
issue discount, underwriters commission and other expenses totaling
approximately $6.5 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 estimate that we
will have a pre-tax charge to earnings in the second quarter of 2003 of
approximately $17.7 million from the early retirement of the old 9% notes, made
up of the write-off of the call premium and the unamortized discount and debt
issue costs. The proceeds from the new issue were ultimately used to retire the
old notes in April 2003, although pending this use, the proceeds were used to
temporarily repay a portion of our bank debt, with the balance invested in
short-term securities.
CAPITAL RESOURCES AND LIQUIDITY
During the first quarter of 2003, we spent $32.7 million on oil and natural
gas exploration and development expenditures, $6.9 million on CO2 capital
investments, and approximately $3.7 million on oil and natural gas property
acquisitions, for total capital expenditures of approximately $43.3 million. In
addition, during the first quarter we incurred approximately $6.5 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
$26.2 million plus other additional consideration that included an interest in
Atchafalaya Bay Field (where we already own an interest) and seismic over that
area. 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 $23.6 million of net total expenditures (including the
debt refinancing costs) was funded by $35.5 million of cash flow from
operations, with the excess used to fund other minor items and to reduce our net
total debt (net of cash), by approximately $12.2 million. Adjusted cash flow
from operations (a non-GAAP measure defined as cash flow from operations before
the changes in assets and liabilities as discussed below under "Results of
Operations-Operating Results")was $47.4 million, with the difference of $11.9
million primarily relating to an increase in oil and gas production receivables
caused by the high natural gas prices in March 2003.
At March 31, 2003, both our old and new subordinated notes were
outstanding, totaling $425 million, plus $50 million of bank debt, for total
outstanding debt of $475 million. However, we also had $161.2 million of cash,
an increase of $137.2 million from our year-end cash balance, resulting in a
$12.2 million reduction in net debt (net of cash) between December 31, 2002 and
March 31, 2003. As of April 30, 2003, after retiring the old notes and payment
of the call premium, we had $350 million of total debt, the same outstanding
principal balance as at December 31, 2002 and consistent with the debt levels
prior to the subordinated debt refinancing, after adjustment for the refinancing
transaction costs.
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Our goal 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 between $22.50 and $25.00 per Bbl and natural gas prices between $3.25
and $3.50 per Mcf. Based on these price assumptions, 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 and, had $15 million not been used to pay
costs of our subordinated debt refinancing, that amount would have been used to
reduce debt during the first four months of 2003. Even with the incremental debt
from the refinancing, we expect to achieve our debt goal of $300 million during
the latter half of 2003 through the application of excess cash flow from
operations, assuming that commodity prices do not decrease substantially. We may
also reduce debt with any cash received from the possible economic transfer of
certain of our assets, such as the value of some of our industrial CO2 sales, to
Genesis Energy, L.P. during 2003.
Our bank borrowing base was recently reaffirmed at $220 million as part of
an amendment to our credit agreement completed in early May. 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 or reduction of sales and ad valorem taxes
on CO2 facilities we build in the next two years in Mississippi. We anticipate
entering into such bond funding arrangements 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.
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 remains
unchanged at approximately $137.7 million, including approximately $7.7 million
of projects carried over from 2002. Based on current projections, using futures
prices in place as of the first part of May 2003, this spending level is
expected to be as much as $50 million to $60 million below our 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, possible acquisitions, although
we may consider increasing our budget slightly if commodity prices remain high
and it appears we can still 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. We are 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, plus we are
continuing to acquire additional interests in the fields that we currently own.
We have targeted the acquisition of offshore blocks, which generally consist of
one or two fields, where we see additional potential based on our review of 3D
seismic or other geologic and geophysical data. Although we are continuing to
pursue 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 March
31, 2003, consisted of $3.5 million of debt and $30.0 million in letters of
credit, $9.7 million of which are for Denbury's benefit) and we have delivery
obligations to deliver CO2 to our industrial customers. Our hedging obligations
are discussed in Note 9 to the Consolidated Financial Statements. Neither the
amounts nor the terms of these commitments or contingent obligations have
changed significantly from the year-end 2002 amounts reflected in our 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 the first quarter, we completed an additional CO2 well, the IP 15-4
#1, which increased our CO2 production capabilities to approximately 175 MMcf/d,
up from approximately 100 to 110 MMcf/d approximately one year ago. As of the
end of April 2003, an additional CO2 well was near completion and is expected to
commence production early in the third quarter with an anticipated daily volume
capability of 30 to 40 MMcf/d. We also plan to upgrade our CO2 facilities in the
third quarter, which coupled with the new wells, should increase our CO2
production capacity to around 210 to 220 MMcf/d. Since our CO2 wells have been
performing better than anticipated, we do not plan to spud the third CO2 well
scheduled in 2003 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 350 MMcf/d in order to develop the oil fields along our
CO2 pipeline as planned, or to potentially 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 unforseen
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.
Our oil production from our CO2 tertiary recovery activities increased 12%
over fourth quarter 2002 levels to 4,345 Bbls/d in the first quarter of 2003.
This represented approximately 22% of our total corporate oil production during
the quarter. While this is still a modest percentage of our total production, we
expect tertiary oil production to be an ever increasing portion of our
production (see further discussion of production below). We spent approximately
$0.16 per Mcf to produce our CO2 during the first quarter of 2003, 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. Unless oil prices continue to increase, we expect our costs
to produce CO2 to decline as our CO2 production increases. The higher cost per
Mcf of CO2 caused a corresponding increase in the operating costs of our
tertiary projects. For the first quarter, our operating costs for our tertiary
properties averaged $10.76 per BOE, slightly higher than our 2002 average of
$10.02 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. This compares
to a cost of around $5 per BOE for a more traditional oil property without
secondary or tertiary operations.
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Results
Our operating results for the first quarter of 2003 were substantially
better than results for the first quarter of the prior year due to the sharp
increase in commodity prices, 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." 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 and per share basis.
Three Months Ended
March 31,
- -------------------------------------------------------- --------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 2003 2002
- -------------------------------------------------------- ------------ ------------
Income before cumulative effect of a change in
accounting principle $ 18,453 $ 4,546
Cumulative effect of a change in accounting principal,
net of income tax expense of $1,600 2,612 -
------------ ------------
Net income $ 21,065 $ 4,546
- -------------------------------------------------------- ------------ ------------
Net income per common share - basic:
Income before cumulative effect of a change in
accounting principle $ 0.34 $ 0.09
Cumulative effect of a change in accounting principle 0.05 -
------------ ------------
Net income per common share - basic $ 0.39 $ 0.09
- -------------------------------------------------------- ------------ ------------
Net income per common share - diluted:
Income before cumulative effect of a change in
accounting principle $ 0.33 $ 0.08
Cumulative effect of a change in accounting principle 0.05 -
------------ ------------
Net income per common share - diluted: $ 0.38 $ 0.08
- -------------------------------------------------------- ------------ ------------
Adjusted cash flow from operations (see below) $ 47,366 $ 28,524
Net change in assets and liabilities relating to operations (11,857) (16,492)
- -------------------------------------------------------- ------------ ------------
Cash flow from operations (1) $ 35,509 $ 12,032
- -------------------------------------------------------- ------------ ------------
(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 the 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, as we have very few uncollectible
receivables and timely pay all of our obligations.
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 first quarter of 2003 we used approximately $11.9 million of
cash to fund a net increase in working capital. This was primarily caused by an
increase in our accrued production receivables during March caused by the
unusually high natural gas price, with natural gas index prices in the $9.28 per
MMBtu range. We received payment for substantially all of this natural gas
during April 2003. Similarly, we used a significant amount of cash flow from
operations in the first quarter of 2002 to fund a $16.5 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
quarters of 2003 and 2002 are included in the following table.
Three Months Ended
March 31,
- ----------------------------------------------------------------- -----------------------------------
2003 2002
- ----------------------------------------------------------------- ---------------- -----------------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 19,565 17,740
Mcf 99,170 105,726
BOE(1) 36,093 35,361
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 52,213 $ 27,833
Natural gas sales 59,511 23,077
Gain (loss) on settlements of derivative contracts (27,685) 2,636
---------------- -----------------
Total oil and natural gas revenues $ 84,039 $ 53,546
---------------- -----------------
Lease operating expenses $ 22,402 $ 15,428
Production taxes and marketing expenses 3,896 2,614
---------------- -----------------
Total production expenses $ 26,298 $ 18,042
---------------- -----------------
CO2 sales to industrial customers $ 2,189 $ 1,490
CO2 operating expenses 317 167
---------------- -----------------
CO2 operating margin $ 1,872 $ 1,323
---------------- -----------------
UNIT PRICES-INCLUDING IMPACT OF HEDGES
Oil price per barrel ("Bbl") $ 24.69 $ 17.72
Gas price per thousand cubic feet ("Mcf") 4.54 2.65
UNIT PRICES-EXCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 29.65 $ 17.43
Gas price per Mcf 6.67 2.43
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1):
Oil and natural gas revenues $ 34.40 $ 15.99
---------------- -----------------
Oil and gas lease operating expenses $ 6.90 $ 4.85
Oil and gas production taxes and marketing expenses 1.20 0.82
---------------- -----------------
Total oil and gas production expenses $ 8.10 $ 5.67
- ----------------------------------------------------------------- ---------------- -----------------
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
23
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 quarter of 2003 is listed in the following table.
Average Daily Production (BOE/d)
--------------------------------------------------------------------
First Second Third Fourth First
Quarter Quarter Quarter Quarter Quarter
Operating Area 2002 2002 2002 2002 2003
- --------------------------------- ----------- ------------ ------------ ------------- -------------
Mississippi - non-CO2 floods 12,423 12,124 13,232 15,703 14,537
Mississippi - CO2 floods 3,839 4,278 3,895 3,863 4,345
Onshore Louisiana 8,405 7,717 8,224 7,859 8,509
Offshore Gulf of Mexico 10,550 11,229 9,863 8,287 8,544
Other 144 178 292 182 158
----------- ------------ ------------ ------------- -------------
Total Company 35,361 35,526 35,506 35,894 36,093
- --------------------------------- ----------- ------------ ------------ ------------- -------------
During the first quarter of 2003, we sold Laurel Field, a Mississippi
non-CO2 flood property that has averaged between 1,500 and 1,700 BOE/d since we
acquired it in August 2002. The field was sold effective January 31, 2003,
lowering our first quarter 2003 oil production, as compared to the fourth
quarter of 2002, by approximately 1,100 BOE/d. Our first quarter of 2003
production was also negatively affected by mechanical failures in two of our
onshore Louisiana natural gas wells, reducing production by approximately 500
BOE/d. However, the production increases from our tertiary recovery projects and
other onshore Louisiana projects more than offset these production decreases,
resulting in a slight increase in overall production in the first quarter of
2003 when compared to fourth quarter of 2002 production. As of May 12, 2003, the
two well failures discussed above had been repaired and production was gradually
increasing, with current production at about 75% of their previous production
levels.
When comparing production in the first 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 2,773 BOE/d to the first
quarter of 2003 average production rate. We also benefitted from a 506 BOE/d
(13%) increase in our tertiary recovery projects when comparing the respective
first quarters. Partially offsetting these increases were general production
declines from normal depletion in the Mississippi - non-CO2 flood properties and
our offshore properties. The net result was a 2% increase in overall production
in the first quarter of 2003 as compared to the first quarter of 2002.
With regard to specific fields, production at Heidelberg Field, a
Mississippi non-CO2 flood property and our single largest field, decreased from
7,702 BOE/d in the first quarter of 2002 to 7,441 BOE/d in the first quarter of
2003, as part of a general decline in production since that field's peak in
2001. However, first quarter of 2003 production was up slightly from the fourth
quarter of 2002 average of 7,290 BOE/d as a result of incremental natural gas
production from three wells drilled at Heidelberg during the fourth quarter of
2002. As previously discussed, production from our tertiary recovery projects
increased in the first quarter of 2003, with most of this increase coming from
Mallalieu Field. The oil production increases correlate with the higher volumes
of CO2 injected during the last few months following the increase in our CO2
production capabilities. Oil production has continued to gradually increase, at
least through April, at both of the primary tertiary recovery projects, Little
Creek and Mallalieu Fields, and is expected to continue, although there may be
fluctuations from period to period. CO2 injection is not expected to commence at
McComb Field, a new project started this year, until the fourth quarter of 2003,
with initial oil production response expected six to twelve months later.
Production from our onshore Louisiana area increased slightly in the first
quarter of 2003 as compared to production in the prior year first quarter, and
increased more significantly when compared to production in the fourth quarter
of 2002. This
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increase was in spite of mechanical well problems on two Louisiana natural gas
wells which lowered overall onshore Louisiana production by approximately 500
BOE/d. The production at Lirette Field accounted for most of the increased
production onshore Louisiana, as production during the first quarter of 2003
averaged 2,097 BOE/d (mostly natural gas), as compared to 1,358 BOE/d in the
fourth quarter of 2002 and 1,645 BOE/d in the first quarter of 2002. This
increase was primarily due to a successful recompletion, in late December 2002,
of the Laterre #29 well. The most significant production declines in this area
have come from Thornwell Field, as most of this production is short-lived
natural gas production. Production at Thornwell Field averaged 3,138 BOE/d
(mostly natural gas) during the first quarter of 2003, down from 4,399 BOE/d
during the first quarter of 2002. Production at Thornwell fluctuates with
drilling activity, and during the first quarter of 2003 the only well we drilled
was a dry hole, our first dry hole in this field. We are continuing development
and exploration activities at Thornwell Field in 2003, although at a lower level
than in 2002.
Production offshore generally declined during the latter half of 2002 due
to the minimal activity level there in 2002. The two exploratory wells drilled
offshore during late 2002 at North Padre Island were successful, but require a
production facility before they can be produced, with production expected to
commence early in the fourth quarter of 2003. Two other wells have been drilled
offshore during the first quarter of 2003, but these were both dry. Similar to
Thornwell Field onshore Louisiana, our production offshore is relatively
short-lived, and without continued activity production will gradually decrease
from normal depletion. We plan to drill up to nine additional wells offshore
during 2003, as well as other development work such as workovers and
recompletions, and expect production to generally increase from first quarter
levels throughout the year.
Our production for the first quarter of 2003 was weighted slightly towards
oil (54%) primarily due to the mechanical problems with two onshore Louisiana
natural gas wells discussed above. Although there will be fluctuations from
period to period, we generally expect our production to remain close to a 50/50
mix 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 first quarter of 2003 increased $30.5 million, or
57%, from the comparable quarter of 2002, and also increased when comparing the
first quarter of 2003 with the fourth quarter of 2002. The increase in oil and
natural gas revenues when comparing the two first quarters is primarily due to
the increase in commodity prices, which increased revenues by $59.8 million, or
112%, from levels in the prior year quarter. This increase was supplemented by
an increase in production volumes, which increased revenues by $1.0 million, or
2%. These increases were partially offset by significant losses on the
settlements of derivative contracts which reduced revenues by $30.3 million, or
57% of the revenues increase when comparing the two first quarters.
Our realized natural gas prices (excluding hedges) for the first quarter of
2003 averaged $6.67 per Mcf, a 174% increase from the average of $2.43 per Mcf
realized during the first quarter of 2002, and our realized oil prices
(excluding hedges) for the first quarter of 2003 averaged $29.65 per Bbl, a 70%
increase from the $17.43 per Bbl average realized in the first quarter of 2002.
We paid out a portion of our increase in revenues due to commodity prices with
the payment of $27.7 million on our hedges in the first quarter of 2003, as
compared to collections of $2.6 million on our commodity hedges in the first
quarter of 2002, reducing our average realized natural gas price to $4.54 per
Mcf and our average realized oil price to $24.69 per Bbl in the first quarter of
2003. On a weighted average price per BOE received net to us, prices were $18.41
per BOE higher (excluding hedges) in the first quarter of 2003 than in the
comparable period of 2002. However, we paid out approximately $8.52 per BOE on
our oil and natural gas hedges in the current quarter, as compared to cash
receipts of $0.83 per BOE in the prior year quarter, leaving a net realized
price increase of approximately $9.06 per BOE.
PRODUCTION EXPENSES: Lease operating expenses increased from $4.85 per BOE
in the first quarter of 2002 to $6.90 per BOE in the first quarter of 2003,
which was also higher than our fourth quarter 2002 average of $6.34 per BOE. The
cost of the two workovers relating to mechanical failures at two onshore
Louisiana gas wells discussed above, totaling approximately $850,000, was the
biggest source of the increase, although continued high expenses on the
properties acquired from COHO,
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
continued expansion of CO2 tertiary projects (which typically have a higher than
average cost per BOE), along with higher lease fuel costs caused by the high
natural gas prices, also contributed to the higher than historical level of
operating costs. We expect to incur between $1.8 million and $2.0 million of
additional expense in the second quarter of 2003 on the two aforementioned
workovers, which were not completed until late April. We anticipate that our
lease operating expenses on a per BOE basis will decrease later this year,
assuming a return to normal operating parameters.
Production taxes and marketing expenses also increased from $0.82 per BOE
in the first quarter of 2002 to $1.20 per BOE in the first quarter of 2003,
primarily due to the higher commodity prices.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 16% on a per BOE
basis between the respective first quarters as set forth below:
Three Months Ended
March 31,
- --------------------------------------------------- ------------------------------------------
2003 2002
- --------------------------------------------------- ------------------- -------------------
NET G&A EXPENSE (THOUSANDS)
Gross G&A expenses $ 11,433 $ 9,509
State franchise taxes 363 367
Operator overhead charges (6,515) (5,203)
Capitalized exploration costs (1,490) (1,457)
------------------- -------------------
Net G&A expense $ 3,791 $ 3,216
------------------- -------------------
Average G&A cost per BOE $ 1.17 $ 1.01
Employees as of March 31 360 324
- --------------------------------------------------- ------------------- -------------------
Gross G&A expenses increased $1.9 million, or 20%, between the first
quarters of 2002 and 2003. The largest components of this increase relate to
expenses associated with the recent sale of stock by the Texas Pacific Group,
higher year-end expenses than in the prior year for engineering fees and audit
fees, 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 the first quarter of 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 25%
between the respective first quarters of 2002 and 2003. Capitalized exploration
costs increased slightly between the comparable periods in 2002 and 2003, along
with the increase in gross G&A expenses. The net effect of the increase in gross
G&A expenses, operator overhead charges and capitalized exploration costs was an
18% increase in net G&A expense between the respective first quarters. On a per
BOE basis, G&A costs increased 16% in the first quarter of 2003 as compared to
the first quarter of 2002, as the production increase was not proportional to
the cost increase.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest and Financing Expenses
Three Months Ended
March 31,
- ---------------------------------------------------- ---------------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002
- ---------------------------------------------------- -------------- ---------------
Interest expense $ 6,461 $ 6,654
Non-cash interest expense (503) (650)
-------------- ---------------
Cash interest expense 5,958 6,004
Interest and other income (204) (411)
-------------- ---------------
Net cash interest expense $ 5,754 $ 5,593
-------------- ---------------
Average net cash interest expense per BOE $ 1.77 $ 1.76
Average interest rate (1) 6.8% 7.0%
Average debt outstanding $ 351,556 $ 342,409
- ---------------------------------------------------- -------------- ---------------
(1) Includes commitment fees but excludes amortization of debt issue costs.
Interest expense for the first quarter of 2003 decreased from levels in the
comparable prior year period primarily due to (i) lower overall interest rates,
as our average outstanding debt balance increased slightly, 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.
Our net cash interest expense increased slightly between periods as our interest
and other income decreased in the first quarter of 2003. We expect interest
expense to further decrease in 2003 as a result of the refinancing of our
subordinated debt (see "Debt Refinancing" above), 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.
Depletion, Depreciation and Amortization
Three Months Ended
March 31,
- ------------------------------------------------------ ----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002
- ------------------------------------------------------ ------------- -----------
Depletion and depreciation $ 21,979 $ 21,216
Depreciation of CO2 assets 438 527
Site restoration provision - 774
Accretion of discount on asset retirement obligations 820 -
Depreciation of other fixed assets 316 409
------------- -----------
Total DD&A $ 23,553 $ 22,926
------------- -----------
DD&A per BOE:
Oil and natural gas properties $ 7.02 $ 6.91
CO2 assets and other fixed assets 0.23 0.29
------------- -----------
Total DD&A cost per BOE $ 7.25 $ 7.20
- ------------------------------------------------------ ------------- -----------
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis was almost the same in the first quarters of 2003 and 2002, and
similar to the average rate per BOE during 2002, as there were no significant
changes in reserves during the first quarter 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 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 estimate that our retirement
obligations will be $81.8 million, with an estimated salvage value of $43.3
million, also on an undiscounted basis. DD&A was calculated on the increase to
oil and natural gas properties, net of estimated salvage value, and the
liability was accreted during the quarter by $820,000.
Income Taxes
Three Months Ended
March 31,
- ----------------------------------------------------------------- ------------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS AND TAX RATES 2003 2002
- ------------------------------------------------------------------ -------------- --------------
Income tax provision
Current income tax expense (benefit) $ 2,730 $ (481)
Deferred income tax expense 6,355 1,458
-------------- --------------
Total income tax expense $ 9,085 $ 977
-------------- --------------
Average income tax expense per BOE $ 2.80 $ 0.31
Effective tax rate 33.0% 17.7%
- ----------------------------------------------------------------- -------------- --------------
Our income tax provision for the first quarter of 2002 was based on an
estimated effective tax rate of 37%, although we increased this effective rate
to 38% during 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 quarter 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 carryfowards and thus recognized current income tax
expense for the projected alternative minimum taxes that are expected to be
incurred during 2003.
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.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended
March 31,
----------------------------
Per BOE Data 2003 2002
- -------------------------------------------------------- ------------ ------------
Revenues $ 34.40 $ 15.99
Gain (loss) on settlements of derivative contracts (8.52) 0.83
Lease operating expenses (6.90) (4.85)
Production taxes and marketing expenses (1.20) (0.82)
- -------------------------------------------------------- ------------ ------------
Production netback 17.78 11.15
CO2 operating margin 0.58 0.42
General and administrative expenses (1.17) (1.01)
Net cash interest expense (1.77) (1.76)
Current income taxes and other (0.83) 0.16
Changes in assets and liabilities (3.66) (5.18)
- -------------------------------------------------------- ------------ ------------
Cash flow from operations 10.93 3.78
DD&A (7.25) (7.20)
Deferred income taxes (1.96) (0.46)
Amortization of derivative contracts and other non-cash
hedging adjustments 0.46 0.34
Cumulative effect of a change in accounting principle 0.80 -
Changes in assets and liabilities and other non-cash items 3.50 4.97
- -------------------------------------------------------- ------------ ------------
Net income $ 6.48 $ 1.43
- -------------------------------------------------------- ------------ ------------
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 2008 Value Value
- ---------------------------------------- ----------- ----------- ------------ ----------- ----------- -----------
Variable rate debt:
Bank debt.......................... $ - $ 50,000 $ - $ - $ 50,000 $ 50,000
The weighted-average interest rate on the bank debt at March 31, 2003 is 3.21%.
Fixed rate debt:
9% subordinated debt, net of
discount........................ $ 195,136 $ - $ - $ - $ 195,136 $ 209,000
7.5% subordinated debt, net of
discount, due 2013.............. $ - $ - $ - $ - $ 223,057 $ 223,057
The interest rate on the subordinated debt is an average fixed rate of 8.2%. The 9% notes were retired on April 16, 2003.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 with 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 counterparty credit risk
through established internal control procedures which are reviewed on an ongoing
basis. We attempt to minimize credit risk exposure to counterparties through
formal credit policies, monitoring procedures, and diversification.
At March 31, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $49.7 million, an increase of
approximately $14.1 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 March 31, 2003, and (ii) the expiration of
certain derivative contracts during 2003 for which we recorded amortization
expense of $294,000. Information regarding our current hedging positions is
included in Note 9 to the Consolidated Financial Statements.
Based on NYMEX natural gas futures prices at March 31, 2003, we would
expect to make future cash payments of $29.9 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 $14.1 million, and if futures prices were to increase by 10% we
would expect to pay $51.0 million. Based on NYMEX crude oil futures prices at
March 31, 2003, we would expect to pay $12.1 million on our crude oil commodity
hedges. If crude oil futures prices were to decline by 10%, we would expect to
receive $1.8 million, and if crude oil futures prices were to increase by 10%,
we would expect to pay $27.7 million under our crude oil commodity hedges.
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to
property, plant and equipment, 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, 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
30
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
31
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
- --------------------------------
We maintain disclosure controls and procedures and internal controls
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 within 90 days
prior to the filing of this Quarterly Report on Form 10-Q and have determined
that such disclosure controls and procedures are effective.
Subsequent to their evaluation, there were no significant changes in
internal controls that could significantly affect such controls subsequent to
the date of their evaluation.
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K DURING THE FIRST 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 from Exhibit 4(a) to the Registration Statement on Form S-4
filed with the SEC on May 14, 2003).
4(b) Registration Rights Agreement dated March 25, 2003 pertaining to $225
million of 7-1/2% Senior Subordinated Notes Due 2013 (incorporated by
reference from Exhibit 4(b) to the Registration Statement on Form S-4
filed with the SEC on May 14, 2003).
10* First Amendment to Third Amended and Restated Credit Agreement.
15* Letter from Independent Accountants as to unaudited interim financial
information.
99* 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 March 11, 2003, we announced that Denbury and TPG entered into an
underwriting agreement, pursuant to which TPG would sell 2.5 million shares of
Denbury's common stock. Additionally, TPG has granted to the underwriter a
30-day option to purchase up to an additional 375,000 shares to cover
over-allotments, if any. Denbury did not receive any proceeds from this
transaction.
On March 17, 2003, we announced that Denbury intends to offer $200 million
of Senior Subordinated Notes due 2013 in a Private Rule 144A offering and,
conditioned upon the closing of such offering, to call for redemption $125
million aggregate principal amount of our 9% Senior Subordinated Notes due 2008
and $75 million aggregate principal amount of our 9% Series B Senior
Subordinated Notes due 2008.
On March 19, 2003, we announced that we had priced our private offering of
$225 million of Senior Subordinated Notes due 2013, which will carry a coupon
interest rate of 7.5%. We also announced that we expect to close the sale of the
Notes on March 25, 2003, subject to the satisfaction of customary closing
conditions.
32
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
-----------------------------------------------
/s/ Phil Rykhoek
Sr. Vice President and Chief Financial Officer
By: /s/ Mark C. Allen
-----------------------------------------------
/s/ Mark C. Allen
Vice President and Chief Accounting Officer
Date: May 14, 2003
33
CERTIFICATIONS
I, Gareth Roberts, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Denbury Resources
Inc. (the "registrant");
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
May 14, 2003 /s/ Gareth Roberts
-------------------------------------
Gareth Roberts
President and Chief Executive Officer
34
I, Phil Rykhoek, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Denbury Resources
Inc. (the "registrant");
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
May 14, 2003 /s/ Phil Rykhoek
-----------------------------------------------
Phil Rykhoek
Sr. Vice President and Chief Financial Officer
35