UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] Quarterly report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2004
[ ] 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 20-0467835
(State or other jurisdictions of (I.R.S. Employer
incorporation or organization) Identification No.)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No__
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No__
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at July 31, 2004
----- ----------------------------
Common Stock, $.001 par value 55,037,839
INDEX
Page
----
Part I. Financial Information
- ------------------------------
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at June 30, 2004
and December 31, 2003 3
Unaudited Condensed Consolidated Statements of Operations for the Three and Six
Months Ended June 30, 2004 and 2003 4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Six
Months Ended June 30, 2004 and 2003 5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for
the Three and Six Months Ended June 30, 2004 and 2003 6
Notes to Unaudited Condensed Consolidated Financial Statements 7-17
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations 18-30
Item 3. Quantitative and Qualitative Disclosures about Market Risk 30
Item 4. Controls and Procedures 30
Part II. Other Information
---------------------------
Item 1. Legal Proceedings N/A
Item 2. Changes in Securities, Use of Proceeds, and Issuer Purchases of Equity Securities 30
Item 3. Defaults Upon Senior Securities N/A
Item 4. Submission of Matters to a Vote of Security Holders 30-31
Item 5. Other Information N/A
Item 6. Exhibits and Reports on Form 8-K 31
Signatures 32
2
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
June 30, December 31,
2004 2003
-------------- --------------
Assets
Current assets
Cash and cash equivalents $ 27,940 $ 24,188
Accrued production receivables 41,041 33,944
Related party accrued production receivable - Genesis 10,666 6,927
Trade and other receivables 19,853 18,080
Deferred tax asset 35,094 25,016
Derivative assets 5,053 -
-------------- ---------------
Total current assets 139,647 108,155
-------------- ---------------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,501,122 1,409,579
Unevaluated 45,681 46,065
CO2 properties and equipment 112,717 85,467
Other 17,571 16,450
Less accumulated depletion and depreciation (758,911) (705,050)
-------------- ---------------
Net property and equipment 918,180 852,511
-------------- ---------------
Investment in Genesis 7,188 7,450
Other assets 16,169 14,505
-------------- ---------------
Total assets $ 1,081,184 $ 982,621
============== ===============
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 62,840 $ 62,349
Oil and gas production payable 27,243 22,215
Derivative liabilities 41,202 42,010
-------------- ---------------
Total current liabilities 131,285 126,574
-------------- ---------------
Long-term liabilities
Long-term debt 308,300 298,203
Asset retirement obligations 43,076 41,711
Derivative liabilities 2,470 2,603
Deferred revenue - Genesis 20,362 21,468
Deferred tax liability 95,810 68,555
Other 1,774 2,305
-------------- ---------------
Total long-term liabilities 471,792 434,845
-------------- ---------------
Stockholders' equity
Common stock, $.001 par value, 100,000,000 shares authorized;
55,112,836 and 54,190,042 shares issued at June 30, 2004 and
December 31, 2003, respectively 55 54
Paid-in capital in excess of par 412,423 401,709
Retained earnings 88,349 46,656
Accumulated other comprehensive loss (22,056) (27,113)
Treasury stock, at cost, 38,265 and 8,162 shares at June 30, 2004 and
December 31, 2003, respectively (664) (104)
-------------- ---------------
Total stockholders' equity 478,107 421,202
-------------- ---------------
Total liabilities and stockholders' equity $ 1,081,184 $ 982,621
============== ===============
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Revenues and other income
Oil, natural gas and related product sales
Unrelated parties $ 95,706 $ 83,575 $ 186,980 $ 182,886
Related party - Genesis 23,365 11,177 42,327 23,590
CO2 sales and transportation fees
Unrelated parties 319 2,445 603 4,634
Related party - Genesis 1,261 - 2,338 -
Loss on settlements of derivative contracts (18,239) (13,356) (32,507) (41,041)
Interest income and other 330 347 749 551
------------ ------------ ------------ ------------
Total revenues and other income 102,742 84,188 200,490 170,620
------------ ------------ ------------ ------------
Expenses
Lease operating expenses 24,530 23,048 47,058 45,450
Production taxes and marketing expenses 4,514 3,467 8,581 7,363
CO2 operating expenses 209 534 353 851
General and administrative expenses 4,178 3,376 8,926 7,167
Interest 5,068 6,227 10,149 12,688
Loss on early retirement of debt - 17,629 - 17,629
Depletion, depreciation and amortization 28,161 23,130 55,485 46,683
Amortization of derivative contracts and other
non-cash hedging adjustments 7,146 (751) 7,964 (2,261)
------------ ------------ ------------ ------------
Total expenses 73,806 76,660 138,516 135,570
------------ ------------ ------------ ------------
Equity in net income of Genesis 102 35 9 51
------------ ------------ ------------ ------------
Income before income taxes 29,038 7,563 61,983 35,101
Income tax provision (benefit)
Current income taxes 977 (1,093) 3,096 1,637
Deferred income taxes 8,672 3,527 17,194 9,882
------------ ------------ ------------ ------------
Income before cumulative effect of change in accounting principle 19,389 5,129 41,693 23,582
Cumulative effect of change in accounting principle, net of income
taxes of $1,600 - - - 2,612
------------ ------------ ------------ ------------
Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194
============ ============ ============ ============
Net income per common share - basic
Income before cumulative effect of change in accounting principle $ 0.35 $ 0.10 $ 0.76 $ 0.44
Cumulative effect of change in accounting principle - - - 0.05
------------ ------------ ------------ ------------
Net income per common share - basic $ 0.35 $ 0.10 $ 0.76 $ 0.49
============ ============ ============ ============
Net income per common share - diluted
Income before cumulative effect of change in accounting principle $ 0.34 $ 0.09 $ 0.73 $ 0.42
Cumulative effect of change in accounting principle - - - 0.05
------------ ------------ ------------ ------------
Net income per common share - diluted $ 0.34 $ 0.09 $ 0.73 $ 0.47
============ ============ ============ ============
Weighted average common shares outstanding
Basic 54,744 53,815 54,566 53,728
Diluted 57,102 55,337 56,739 55,186
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ----------------------
2004 2003 2004 2003
-------- --------- --------- ---------
Cash flow from operating activities:
Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 28,161 23,130 55,485 46,683
Amortization of derivative contracts and other non-cash hedging adjustments 7,146 (751) 7,964 (2,261)
Deferred income taxes 8,672 3,527 17,194 9,882
Deferred revenue - Genesis (599) - (1,110) -
Loss on early retirement of debt - 17,629 - 17,629
Amortization of debt issue costs and other 285 325 748 840
Cumulative effect of change in accounting principle - - - (2,612)
Changes in assets and liabilities:
Accrued production receivable (3,410) 13,492 (10,836) (2,373)
Trade and other receivables (546) (1,911) (1,773) (3,144)
Derivative assets and liabilities (7,518) - (7,518) -
Other assets - 335 - 5
Accounts payable and accrued liabilities (1,012) 561 711 2,214
Oil and gas production payable 3,230 (131) 5,028 3,739
Other liabilities (588) (793) (1,381) (745)
-------- --------- --------- ---------
Net cash provided by operations 53,210 60,542 106,205 96,051
-------- --------- --------- ---------
Cash flow used for investing activities:
Oil and natural gas expenditures (42,014) (38,041) (89,764) (70,709)
Acquisitions of oil and gas properties (2,035) (5,931) (2,198) (9,624)
Acquisitions of CO2 assets and capital expenditures (6,938) (6,469) (27,141) (13,373)
Proceeds from oil and gas property sales 634 1,788 1,146 28,154
Increase in restricted cash (148) (210) (351) (356)
Net purchases of other assets (850) (5,879) (1,154) (6,973)
-------- --------- --------- ---------
Net cash used for investing activities (51,351) (54,742) (119,462) (72,881)
-------- --------- --------- ---------
Cash flow from financing activities:
Bank repayments - (15,000) (3,000) (125,000)
Bank borrowings 5,000 75,000 13,000 85,000
Repayment of subordinated debt obligations, including redemption premium - (209,000) - (209,000)
Issuance of subordinated debt, net of discount - (3) - 223,054
Issuance of common stock 4,795 1,645 8,674 2,970
Purchase of treasury stock (918) - (1,661) -
Costs of debt financing (4) (264) (4) (4,786)
-------- --------- --------- ---------
Net cash provided (used) by financing activities 8,873 (147,622) 17,009 (27,762)
-------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents 10,732 (141,822) 3,752 (4,592)
Cash and cash equivalents at beginning of period 17,208 161,170 24,188 23,940
-------- --------- --------- ---------
Cash and cash equivalents at end of period $ 27,940 $ 19,348 $ 27,940 $ 19,348
======== ========= ========= =========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 514 $ 3,111 $ 9,463 $ 13,371
Cash paid during the period for income taxes 600 184 327 184
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(Amounts in thousands)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ---------------------
2004 2003 2004 2003
-------- -------- -------- --------
Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts, net of tax of
$(5,926), $(8,269), $(12,671), and $(24,338), respectively (9,669) (13,491) (20,673) (39,710)
Reclassification adjustments related to settlements of derivative contracts,
net of tax of $10,348, $4,668, $15,770 and $14,789, respectively 16,884 7,615 25,730 24,129
-------- -------- -------- --------
Comprehensive income (loss) $ 26,604 $ (747) $ 46,750 $ 10,613
======== ======== ======== ========
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of
Denbury Resources Inc. and its subsidiaries have been prepared in accordance
with the instructions to Form 10-Q and do not include all of the information and
footnotes required by accounting principles generally accepted in the United
States for complete financial statements. Unless indicated otherwise or the
context requires, the terms "we," "our," "us," "Denbury" or "Company" refer to
Denbury Resources Inc. and its subsidiaries. These financial statements and the
notes thereto should be read in conjunction with our Annual Report on Form 10-K
for the year ended December 31, 2003. Any capitalized terms used but not defined
in these Notes to Unaudited Condensed 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 management's opinion, the accompanying
unaudited condensed consolidated financial statements include all adjustments
(of a normal recurring nature) necessary to present fairly the consolidated
financial position of Denbury as of June 30, 2004 and the consolidated results
of its operations and cash flows for the three and six month periods ended June
30, 2004 and 2003. Certain prior period items have been reclassified to make the
classification consistent with the classification in the most recent quarter.
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 fair value of the underlying common stock
on the date of grant. The following table illustrates the effect on net income
and net income per common share as if we had applied the fair value recognition
and measurement provisions of Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS
No. 148, in accounting for our stock option plan.
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------
2004 2003 2004 2003
-------- ------- -------- --------
Net income: (thousands)
Net income, as reported...................................... $ 19,389 $ 5,129 $ 41,693 $ 26,194
Less: stock-based compensation expense applying fair value
based method, net of related tax effects .................. 1,796 869 3,472 1,634
-------- ------- -------- --------
Pro-forma net income ........................................ $ 17,593 $ 4,260 $ 38,221 $ 24,560
======== ======= ======== ========
Net income per common share
As reported:
Basic ..................................................... $ 0.35 $ 0.10 $ 0.76 $ 0.49
Diluted.................................................... 0.34 0.09 0.73 0.47
Pro forma:
Basic ..................................................... $ 0.32 $ 0.08 $ 0.70 $ 0.46
Diluted ................................................... 0.32 0.08 0.70 0.45
2. NEW ACCOUNTING STANDARDS
In July 2004, the Financial Accounting Standards Board ("FASB") issued a
proposed FASB staff position that clarified the position that SFAS No. 142,
"Goodwill and Other Intangible Assets," does not apply to the drilling and
mineral rights of oil and gas producing entities that account for such rights in
accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas
7
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Producing Companies." In question was whether acquired contractual mineral
interests, both proved and undeveloped, should be classified separately as
"intangible assets" on the balance sheet apart from other oil and gas property
costs. Denbury and virtually all other companies in the oil and gas industry
have historically included purchased contractual mineral rights in oil and gas
properties on the balance sheet. The proposed FASB staff position will have no
impact on the classification of Denbury's oil and gas property balances if the
proposed staff position is adopted in its current state.
3. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting
for Asset Retirement Obligations." In general, our future asset retirement
obligations relate to future costs associated with plugging and abandonment of
our oil and natural gas wells, dismantling our offshore production platforms,
and removal of equipment and facilities from leased acreage and returning such
land to its original condition. SFAS No. 143 requires that the fair value of a
liability for an asset retirement obligation be recorded in the period in which
it is incurred, discounted to its present value using our credit adjusted
risk-free interest rate, and a corresponding amount capitalized by increasing
the carrying amount of the related long-lived asset. The liability is accreted
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Prior to the adoption of this new standard, we recognized a
provision for our asset retirement obligations each period as part of our
depletion and depreciation calculation, based on the unit-of-production method.
The adoption of SFAS No. 143 on January 1, 2003, required us to record (i)
a $41.0 million liability for our future asset retirement obligations (an
increase of $34.1 million in our liability for asset retirement obligations that
we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and
natural gas properties, (iii) a $3.9 million decrease in accumulated
depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect
adjustment of a change in accounting principle, net of taxes of $1.6 million.
The following table summarizes the changes in our asset retirement
obligations for the six months ended June 30, 2004.
Six Months Ended
June 30, 2004
----------------
(in thousands)
Beginning asset retirement obligation, as of 12/31/2003.... $ 43,812
Liabilities incurred during period......................... 1,254
Liabilities settled during period.......................... (1,647)
Accretion expense.......................................... 1,542
----------------
Ending asset retirement obligation......................... $ 44,961
================
At June 30, 2004, $1.9 million of our asset retirement obligation was
classified in "Accounts payable and accrued liabilities" under current
liabilities in our Condensed Consolidated Balance Sheets. We hold cash and
liquid investments in escrow accounts that are legally restricted for certain of
our asset retirement obligations. The balances of these escrow accounts were
$9.9 million at June 30, 2004, and $9.5 million at December 31, 2003 and are
included in "Other assets" in our Condensed Consolidated Balance Sheets.
4. NET INCOME PER COMMON SHARE
Basic net income per common share is computed by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
Diluted net income per common share is calculated in the same manner but also
considers the impact on net income and common shares for the potential dilution
from stock options and any other convertible securities outstanding. For the
three and six month periods ended June 30, 2004 and 2003, there were no
adjustments to net income for purposes of calculating diluted net income per
common share.
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the weighted average common shares
used in the basic and diluted net income per common share calculations for the
three and six month periods ended June 30, 2004 and 2003 (shares in thousands).
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------- --------------------------
2004 2003 2004 2003
---------------- -------------- ------------- ------------
Weighted average common shares - basic....... 54,744 53,815 54,566 53,728
Potentially dilutive securities:
Stock options.............................. 2,358 1,522 2,173 1,458
---------------- -------------- ------------- ------------
Weighted average common shares - diluted..... 57,102 55,337 56,739 55,186
================ ============== ============= ============
For the three months ended June 30, 2004 and 2003, common stock options to
purchase approximately 32,000 and 1.0 million shares of common stock, and for
the six months ended June 30, 2004 and 2003, common stock options to purchase
approximately 361,000 and 1.0 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 were anti-dilutive
to the calculations.
5. STOCK REPURCHASE PLAN
In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase
shares of our common stock on the NYSE in order for such repurchased shares to
be reissued to our employees who participate in Denbury's Employee Stock
Purchase Plan. The Plan provides for purchases through an independent broker of
50,000 shares of Denbury's common stock per fiscal quarter for a period of
approximately twelve months, or a total of 200,000 shares, during the period
beginning August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of
Directors renewed the Plan for another year, for the period beginning July 1,
2004 and ending June 30, 2005. Purchases are to be made at prices and times
determined at the discretion of the independent broker, provided however that no
purchases may be made during the last ten business days of a fiscal quarter.
During 2003, we purchased 100,000 shares at an average cost of $12.77 per share
and from January 1, 2004 through June 30, 2004, we purchased 100,000 shares at
an average cost of $16.61 per share. Through June 30, 2004, we have reissued
161,735 (80.9%) of these shares under Denbury's Employee Stock Purchase Plan.
6. RELATED PARTY TRANSACTIONS - GENESIS
Interest in and Transactions with Genesis
Denbury is the general partner and owns an aggregate of 9.25% interest in
Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership.
Genesis has three primary lines of business: crude oil gathering and marketing,
pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida,
and wholesale marketing of carbon dioxide.
We are accounting for our 9.25% ownership in Genesis under the equity
method of accounting as we have significant influence over the limited
partnership; however, our control is limited under the limited partnership
agreement and therefore we do not consolidate Genesis. Our equity in Genesis'
net income for the three months ended June 30, 2004 and 2003 was $102,000 and
$35,000, respectively, and for the six months ended June 30, 2004 and 2003 was
$9,000 and $51,000, respectively. Genesis Energy, Inc., the general partner of
which we own 100%, has guaranteed the bank debt of Genesis, which was $5.5
million as of June 30, 2004, and which debt includes $20.6 million in letters of
credit of which $10.7 million are for Denbury's benefit to secure purchases of
oil from Denbury. There are no guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
9
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Genesis has historically been a purchaser of our crude oil and we
anticipate future purchases of our crude oil production by Genesis. At June 30,
2004 and December 31, 2003, we had a production receivable from Genesis of $10.7
million and $6.9 million, respectively. We recorded oil sales to Genesis of
$23.4 million and $11.2 million for the three months ended June 30, 2004 and
2003, respectively, and $42.3 million and $23.6 million for the six months ended
June 30, 2004 and 2003, respectively. Denbury received other miscellaneous
payments from Genesis during the 2004 period, including $60,000 in director fees
for certain executive officers of Denbury that are board members of Genesis, and
$253,000 in pro rata distributions from Genesis.
CO2 Volumetric Production Payment
In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million
($23.9 million as adjusted for interim cash flows from the September 1, 2003
effective date and for transaction costs) under a volumetric production payment
("VPP"). This sale included the assignment to Genesis of three of our existing
long-term commercial CO2 supply agreements with our industrial customers, which
represented approximately 60% of our then current industrial CO2 sales volumes.
Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO2 through 2009,
43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term. We
have recorded the net proceeds of the sale as deferred revenue and will
recognize such revenue as CO2 is delivered during the term of the VPP. At June
30, 2004, $22.5 million was recorded as deferred revenue ($2.1 million in
current liabilities and $20.4 million long term). During the three and six
months ended June 30, 2004, we recognized deferred revenue of $0.6 million and
$1.1 million, respectively, for deliveries under the VPP. We provide Genesis
with certain processing and transportation services in connection with this
agreement for a fee of $0.16 per Mcf of CO2 delivered to their industrial
customers, which resulted in $0.7 million and $1.2 million in revenue to Denbury
for the three and six months ended June 30, 2004, respectively.
Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- ---------------------------
2004 2003 2004 2003
--------- --------- --------- ---------
Revenues................................. $ 232,107 $ 146,670 $ 431,019 $ 322,352
Cost of sales............................ 230,619 145,763 430,143 320,521
Other income (expenses).................. (389) 983 (782) 938
--------- --------- --------- ---------
Net income............................... $ 1,099 $ 1,890 $ 94 $ 2,769
========= ========= ========= =========
June 30, December 31,
2004 2003
-------- --------
Current assets............................... $ 82,606 $ 88,211
Non-current assets........................... 58,771 58,904
-------- --------
Total assets .............................. $141,377 $147,115
======== ========
Current liabilities ......................... $ 85,763 $ 87,244
Non-current liabilities...................... 5,500 7,000
Partners' capital............................ 50,114 52,871
-------- --------
Total liabilities and partners' capital.... $141,377 $147,115
======== ========
7. PRODUCT PRICE HEDGING CONTRACTS
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. 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 33% 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, although our hedging percentage
may vary relative to our debt levels. For example, when our debt levels are
high, we may hedge a higher percentage of our production than when our debt
levels are low. 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. Much of our hedging activity has been with collars,
although for the 2002 COHO acquisition, we also used swaps in order to lock in
the prices used in our economic forecasts. In the second quarter of 2004, we
purchased price floors or puts relating to a portion of
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
our 2005 oil production, allowing us to retain any upside from increases in
commodity prices. 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.
The following is a summary of the net loss on our commodity hedge
settlements which are recorded in "Revenues" in our Condensed Consolidated
Statements of Operations (amounts in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------- -------------------------
2004 2003 2004 2003
--------------- -------------- ------------ ------------
Oil hedge contracts $ (9,795) $ (2,633) $ (20,316) $ (11,371)
Gas hedge contracts (4,929) (10,723) (8,676) (29,670)
Contracts not qualifying for hedge accounting (3,515) - (3,515) -
--------------- -------------- ------------ ------------
Net loss $ (18,239) $(13,356) $ (32,507) $ (41,041)
=============== ============== ============ ============
The following is a summary of "Amortization of derivative contracts and
other non-cash hedging adjustments," included in our Condensed Consolidated
Statements of Operations (amounts in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
--------------- ---------------
2004 2003 2004 2003
----- ---- ---- ----
Hedge ineffectiveness (income) expense on contracts qualifying
for hedge accounting $ (785) $ 321 $ 33 $ (138)
Amortization of contract premiums - 297 - 591
Reclassification of accumulated other comprehensive income
balance and adjustments to fair value associated with termination
of contracts designated to offshore production 8,112 - 8,112 -
Adjustments to fair value and amortization of ineffecitve hedge
no longer qualifying for hedge accounting 1,349 - 1,349 -
Adjustments to fair value associated with contracts to be
transferred in sale of offshore production (1,530) - (1,530) -
Amortization of terminated Enron-related hedges over the original
contract periods - (1,369) - (2,714)
------ ------ ------- --------
$7,146 $ (751) $ 7,964 $ (2,261)
====== ====== ========= ========
Upon reaching a verbal agreement on the offshore property sale, subject
primarily to the purchaser's further due diligence, we entered into natural gas
swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005,
covering the anticipated natural gas production from our offshore properties for
that period, with the understanding with the prospective purchaser that these
hedges would be transferred to the purchaser upon closing. These swaps did not
qualify for hedge accounting and by August 6, 2004, we had assigned them to the
purchaser of the offshore properties. The mark to market adjustment on these
contracts from the time of purchase through June 30, 2004 totaled approximately
$1.5 million. At about the same time, with the expectation that the offshore
transaction would be consummated, we retired, by purchasing offsetting
contracts, 20 MMcf/d of our natural gas hedges for July to December of 2004, at
a cost of approximately $3.9 million. Since the natural gas hedges we retired
were not the same as those hedges previously designated for offshore production,
we recognized a charge to earnings in the second quarter of 2004 of
approximately $8.1 million, representing the then current mark to market value
of the offshore hedges. The difference between this charge and the amount paid
to retire 20 MMcf/d will be reversed over the remainder of 2004. We also had
minor charges and credits for hedge ineffectiveness and a net charge for a
portion of our oil hedges that are no longer considered
11
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
effective during the second quarter of 2004, resulting in a net charge of $7.1
million for the quarter and $8.0 million for the six months ended June 30, 2004.
During the three and six months ended June 30, 2003, we had minor charges
or credits relating to the hedge ineffectiveness, charges for the amortization
of contract premiums, and credits relating to the reclassification of amounts
out of "Accumulated other comprehensive loss" into income relating to our former
Enron hedges, resulting in a net credit of $751,000 for the three months and
$2.3 million for the six months ended June 30, 2003.
Derivative Contracts designated as a hedge of forecasted production at June 30,
2004:
Crude Oil Contracts:
- -------------------
NYMEX Contract Prices Per Bbl
-----------------------------
Collar Prices
---------------------- Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling June 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- -----------------
Swap Contracts (in thousands)
July 2004 - Dec. 2004 4,500 $ 23.00 $ - $ - $ - $ (11,363)
July 2004 - Dec. 2004 2,500 22.89 - - - (6,363)
Jan. 2005 - Dec. 2005 7,500 - 27.50 - - 2,781
Natural Gas Contracts:
- ---------------------
NYMEX Contract Prices Per MMBtu
-------------------------------
Collar Prices
---------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- -----------------
Collar Contracts (in thousands)
July 2004 - Dec. 2004 30,000 $ - $ - $ 3.50 $ 4.45 $ (10,406)
July 2004 - Dec. 2004 10,000 - - 3.00 5.82 (1,271)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (5,534)
12
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Derivative Contracts not designated as a hedge:
Crude Oil Contracts:
- -------------------
NYMEX Contract Prices Per Bbl
-----------------------------
Contract discontinued from hedge accounting due to failing ongoing effectiveness assessment
Collar Prices
---------------------- Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling June 30, 2004
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
July 2004 - Dec. 2004 2,500 $ 23.08 $ - $ - $ - $ (6,276)
Natural Gas Contracts:
- ---------------------
NYMEX Contract Prices Per MMBtu
-------------------------------
Contracts purchased for planned divestiture
Collar Prices
---------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2004
- -------------------------------- -------------------------------------------------------------------------------
(in thousands)
July 2004 - Dec. 2004 21,200 $ 6.50 $ - $ - $ - $ 644
July 2004 - Dec. 2004 23,000 6.44 - - - 601
Jan. 2005 - Oct. 2005 19,800 6.18 - - - 270
Jan. 2005 - Dec. 2005 26,000 6.11 - - - 15
Offsetting Contracts
Collar Prices
---------------------- Fair Value at
Type of Contract and Period MMBtu/d Call Price Put Price Floor Ceiling June 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- -----------------
(in thousands)
July 2004 - Dec. 2004 15,000 $ - $ - $ 3.00 $ 5.87 $ (1,822)
July 2004 - Dec. 2004 15,000 5.87 - - - 1,822
July 2004 - Dec. 2004 5,000 - - 3.00 5.82 (636)
July 2004 - Dec. 2004 5,000 5.82 3.00 - - 636
At June 30, 2004, our derivative contracts were recorded at their fair
value, which was a net liability of $36.9 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 Condensed Consolidated Balance Sheets. The balance in accumulated
other comprehensive loss of $22.1 million at June 30, 2004, represents the
deficit in the fair market value of our derivative contracts as compared to the
cost of our hedges, net of income taxes. Of the $22.1 million in accumulated
other comprehensive loss as of June 30, 2004, $19.3 million relates to current
hedging contracts that will expire within the next 12 months.
8. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
On December 29, 2003, we amended the indenture for our 7.5% Senior
Subordinated Notes due 2013 to reflect our new holding company organizational
structure. As part of this restructuring, our indenture was amended so that both
Denbury Resources Inc. (the new holding company) and Denbury Onshore, LLC
(formerly the parent company and now a wholly-owned subsidiary) became
co-obligors on our subordinated debt. Prior to this restructure, Denbury
Resources Inc., as the parent company, was the sole obligor. Our subordinated
debt is fully and unconditionally guaranteed by Denbury Resources Inc.'s
significant subsidiaries. Genesis Energy, Inc., the subsidiary that holds the
Company's investment in Genesis Energy, L.P., is not a guarantor of our
subordinated debt. Our equity interest in the results of operations of Genesis
is reflected through the equity method by one of our significant subsidiaries,
Denbury Gathering & Marketing. The following is condensed consolidating
financial information for Denbury Resources Inc., Denbury Onshore, LLC, and
significant subsidiaries:
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Balance Sheets
June 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
-------------- --------------- ------------- -------------- ---------------
Amounts in thousands
ASSETS
Current assets..................................... $ 7,029 $ 98,141 $ 34,477 $ - $ 139,647
Property and equipment ............................ - 618,265 299,915 - 918,180
Investment in subsidiaries (equity method)......... 468,014 - 240,814 (701,640) 7,188
Other assets....................................... - 11,623 4,546 - 16,169
-------------- --------------- ------------- -------------- ---------------
Total assets ................................. $ 475,043 $ 728,029 $ 579,752 $ (701,640) $ 1,081,184
============== =============== ============= ============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities................................ $ 76 $ 127,912 $ 3,297 $ - $ 131,285
Long-term liabilities ............................. (3,140) 366,491 108,441 - 471,792
Stockholders' equity .............................. 478,107 233,626 468,014 (701,640) 478,107
-------------- --------------- ---------------------------- ---------------
Total liabilities and stockholders' equity.... $ 475,043 $ 728,029 $ 579,752 $ (701,640) $ 1,081,184
============== =============== ============= ============== ===============
December 31, 2003
-----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
-------------- --------------- ------------- -------------- ---------------
Amounts in thousands
ASSETS
Current assets .................................... $ 1 $ 85,109 $ 23,045 $ - $ 108,155
Property and equipment ............................ - 560,038 292,473 - 852,511
Investment in subsidiaries (equity method) ........ 421,201 - 210,803 (624,554) 7,450
Other assets ...................................... - 11,186 3,319 - 14,505
-------------- --------------- ------------- -------------- ---------------
Total assets.................................. $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621
============== =============== ============= ============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities................................ $ - $ 119,364 $ 7,210 $ - $ 126,574
Long-term liabilities ............................. - 333,616 101,229 - 434,845
Stockholders' equity............................... 421,202 203,353 421,201 (624,554) 421,202
-------------- --------------- ------------- -------------- ---------------
Total liabilities and stockholders' equity.... $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621
============== =============== ============= ============== ===============
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2004
---------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
-------------- --------------- ------------- -------------- ---------------
Amounts in thousands
Revenues.................................... $ - $ 71,928 $ 30,814 $ - $ 102,742
Expenses ................................... 88 56,325 17,393 - 73,806
-------------- ---------------- ------------ -------------- ---------------
Income (loss) before the following: (88) 15,603 13,421 - 28,936
Equity in net earnings of subsidiaries ... 19,448 - 10,510 (29,856) 102
-------------- ---------------- ------------ -------------- ---------------
Income before income taxes.................. 19,360 15,603 23,931 (29,856) 29,038
Income tax provision (benefit).............. (29) 5,195 4,483 - 9,649
-------------- ---------------- ------------ -------------- ---------------
Net income ................................. $ 19,389 $ 10,408 $ 19,448 $ (29,856) $ 19,389
============== ================ ============ ============== ===============
Three Months Ended June 30, 2003
-----------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------ -------------- ---------------
Amounts in thousands
Revenues................................................... $ 58,565 $ 25,623 $ - $ 84,188
Expenses................................................... 62,583 14,077 - 76,660
--------------- ------------ -------------- ---------------
Income (loss) before the following: (4,018) 11,546 - 7,528
Equity in net earnings of subsidiaries .................. 7,939 35 (7,939) 35
--------------- ------------ -------------- ---------------
Income before income taxes................................. 3,921 11,581 (7,939) 7,563
Income tax provision (benefit)............................. (1,208) 3,642 - 2,434
--------------- ------------ -------------- ---------------
Net income................................................. $ 5,129 $ 7,939 $ (7,939) $ 5,129
=============== ============ ============== ===============
15
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations (continued)
Six Months Ended June 30, 2004
---------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
-------------- ---------------- ------------ -------------- ---------------
Amounts in thousands
Revenues................................. $ - $ 143,012 $ 57,478 $ - $ 200,490
Expenses ................................ 88 105,878 32,550 - 138,516
-------------- ---------------- ------------ -------------- ---------------
Income (loss) before the following: (88) 37,134 24,928 - 61,974
Equity in net earnings of subsidiaries ... 41,752 - 25,118 (66,861) 9
-------------- ---------------- ------------ -------------- ---------------
Income before income taxes................ 41,664 37,134 50,046 (66,861) 61,983
Income tax provision (benefit)............ (29) 12,025 8,294 - 20,290
-------------- ---------------- ------------ -------------- ---------------
Net income ............................... $ 41,693 $ 25,109 $ 41,752 $ (66,861) $ 41,693
============== ================ ============ ============== ===============
Six Months Ended June 30, 2003
-------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
---------------- ------------ ------------- ---------------
Amounts in thousands
Revenues.................................................. $ 115,850 $ 54,770 $ - $ 170,620
Expenses.................................................. 106,903 28,667 - 135,570
---------------- ------------ ------------- ---------------
Income before the following: 8,947 26,103 - 35,050
Equity in net earnings of subsidiaries ................. 16,434 51 (16,434) 51
---------------- ------------ ------------- ---------------
Income before income taxes and
cumulative effect of a change in accounting principle... 25,381 26,154 (16,434) 35,101
Income tax provision...................................... 3,168 8,351 - 11,519
---------------- ------------ ------------- ---------------
Net income before cumulative effect of a change in
accounting principle.................................... 22,213 17,803 (16,434) 23,582
Cumulative effect of a change in accounting principle,
net of income taxes..................................... 2,612 (1,369) 1,369 2,612
---------------- ------------ ------------- ---------------
Net income................................................ $ 24,825 $ 16,434 $ (15,065) $ 26,194
================ ============ ============= ===============
16
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
---------------- --------------- ------------ -------------- ---------------
Amounts in thousands
Cash flow from operations.............. $ (7,013) $ 87,668 $ 25,550 $ - $ 106,205
Cash flow from investing activities.... - (93,975) (25,487) - (119,462)
Cash flow from financing activities.... 7,013 9,996 - - 17,009
---------------- --------------- ------------ -------------- ---------------
Net increase in cash................... - 3,689 63 - 3,752
Cash, beginning of period.............. 1 24,174 13 - 24,188
---------------- --------------- ------------ -------------- ---------------
Cash, end of period.................... $ 1 $ 27,863 $ 76 $ - $ 27,940
================ =============== ============ ============== ===============
Six Months Ended June 30, 2003
-----------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------- -------------- --------------
Amounts in thousands
Cash flow from operations................................ $ 72,219 $ 23,832 $ - $ 96,051
Cash flow from investing activities...................... (49,561) (23,320) - (72,881)
Cash flow from financing activities...................... (27,762) - - (27,762)
--------------- ------------- -------------- --------------
Net increase (decrease) in cash.......................... (5,104) 512 - (4,592)
Cash, beginning of period................................ 20,281 3,659 - 23,940
--------------- ------------- -------------- --------------
Cash, end of period...................................... $ 15,177 $ 4,171 $ - $ 19,348
=============== ============= ============== ==============
9. SUBSEQUENT EVENT - SALE OF DENBURY OFFSHORE, INC.
On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a
subsidiary that held our offshore assets, for $200 million before adjustments.
The sale price was based on the asset value as of April 1, 2004, which means
that the net revenue and expenses between April 1st and closing, as well as
expenses of the sale and other contractual adjustments, will adjust the purchase
price. On July 20, 2004, we received $187.0 million in cash from the purchaser,
with such amount subject to a post-closing reconciliation within 90 days. We
excluded two significant items from the sale: (i) a recently drilled discovery
well at High Island A-6 and (ii) certain deep rights at West Delta 27. The well
at High Island A-6 should be on production late this year, if not sold, and we
are in the process of selling a substantial portion of the deep rights at West
Delta 27 for an anticipated minor amount of cash and a carried interest in a
deep exploratory well.
We used $85 million of the sales proceeds to retire our bank debt, project
that we will pay approximately $22 million in income taxes related to the sale,
and expect to have between $70 to $75 million of cash remaining from the sale
after payment of these and other expenses related to the transaction. We expect
to incur approximately $1.6 million in employee severance expense in the third
quarter related to employees terminated in the sale transaction. Also, our bank
borrowing base was reduced from $220 million to $175 million as a result of the
sale.
Our offshore properties made up approximately 12.5% of our year-end 2003
proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented
approximately 25% of our 2004 second quarter production (9,114 BOE/d).
17
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, 2003, 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 an 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, own the largest reserves of
carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi
River, and hold significant operating acreage onshore Louisiana. Our goal is to
increase the value of acquired properties through a combination of exploitation,
drilling, and proven engineering extraction processes, including secondary and
tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a
suburb of Dallas), and we have two primary field offices located in Houma,
Louisiana, and Laurel, Mississippi.
Overview
Increased focus on tertiary operations. Since we acquired our first carbon
dioxide tertiary flood in Mississippi five years ago, we have gradually
increased our emphasis on these types of operations. We particularly like this
play because of its risk profile, rate of return and lack of competition in our
operating area. Generally, from East Texas to Florida, there are no significant
natural sources of carbon dioxide except our own, and these large volumes of CO2
that we own drive the play. Please refer to the sections entitled "Overview" and
"CO2 Operations" in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in our 2003 Form 10-K for further information
regarding these operations, their potential, and the ramifications of this
change in focus.
Sale of offshore operations. On July 20, 2004, we closed the sale of
Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200
million before adjustments. The sale price was based on an asset value as of
April 1, 2004, which means that the net revenue and expenses between April 1st
and closing, as well as expenses of the sale and other contractual adjustments,
will adjust the purchase price. On July 20, 2004, we received $187.0 million in
cash from the purchaser, with such amount subject to a post-closing
reconciliation within 90 days. We excluded two significant items from the sale:
(i) a recently drilled discovery well at High Island A-6 and (ii) certain deep
rights at West Delta 27. The well at High Island A-6 should be on production
late this year, if not sold, and we are in the process of selling a substantial
portion of the deep rights at West Delta 27 for an anticipated minor amount of
cash and a carried interest in a deep exploratory well.
We used $85 million of the sales proceeds to retire our bank debt, project
that we will pay approximately $22 million in income taxes related to the sale,
and expect to have between $70 and $75 million of cash remaining from the sale
after payment of these and other expenses related to the transaction. We have
increased our 2004 exploration and development budget by $20 million to $205
million as a result of the additional cash generated from the sale, and expect
our 2005 budget to be at that or a higher level. We expect to spend the cash
generated from the offshore sale over the next one to two years.
Our offshore properties made up approximately 12.5% of our year-end 2003
proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented
approximately 25% of our 2004 second quarter production (9,114 BOE/d).
Operating results. Our adjusted cash flow from operations (non-GAAP
measure, see "Results of Operations - operating results" below) was close to
record levels in the second quarter of 2004, primarily due to record high
commodity prices. Net income was strong, but less than in the first quarter of
2004 as a result of $7.1 million of charges relating to our oil and natural gas
hedges, primarily caused by the early retirement of 20 MMcf/d of our 2004
natural gas hedges upon our expectation that the offshore sale would be
consummated (see "Market Risk Management" for a further discussion). Commodity
prices for the quarter were 20% higher than the prices in the comparable quarter
in 2003 and production was 4% higher than production levels in the comparable
quarter of 2003, but these gains were partially offset by higher hedging
payments, operating expenses, general and administrative expenses, and
depreciation and amortization expenses in the second quarter of 2004. Net income
increased 278% in the second quarter of 2004 to $19.4 million, as compared to
the second quarter of 2003, with near-record cash flow from operations of $53.2
million in the second quarter of 2004, compared to $60.5 million in the second
quarter of 2003. See "Results of Operations" for a more thorough discussion of
our operating results.
18
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Capital Resources and Liquidity
During the first half of 2004, we spent $89.8 million on oil and natural
gas exploration and development expenditures, $19.7 million on CO2 exploration
and development expenditures, and approximately $9.6 million on property
acquisitions (virtually all CO2 related), for total capital expenditures of
approximately $119.1 million. We funded these expenditures with $106.2 million
of cash flow from operations and $10.0 million of net bank borrowings, with the
balance coming from available cash and other sources. 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 $122.0 million, with the difference of $15.8
million between the two amounts primarily relating to $7.5 million spent during
the second quarter to acquire 7,500 Bbls/d of oil puts or floors for 2005 and to
retire 20 MMcf/d of natural gas hedges for the balance of 2004, and a $10.8
million increase in accrued production receivables since year-end as a result of
the higher commodity prices during the second quarter of 2004, partially offset
by changes in other assets and liabilities.
At June 30, 2004, we had total debt of $310 million, consisting of $225
million of 7.5% subordinated notes due in 2013 and $85 million of bank debt. On
July 20, 2004, we paid off our bank debt with the proceeds from the sale of our
offshore operations (see "Overview - sale of offshore operations"), leaving us
with $225 million of outstanding subordinated debt and an estimated $70 to $75
million of incremental cash from the sale, after the anticipated payment of
estimated income taxes and other expenses associated with the offshore sale, or
net debt of approximately $150 million. Our bank borrowing base was reduced from
$220 million to $175 million as result of the sale, all of which was available
as of August 9, 2004. Our 2004 capital budget was increased to $205 million, as
a result of our additional liquidity after the offshore sale. At current
commodity prices, we estimate that we will use only a small portion of the
excess cash generated from the offshore sale for these purposes for the
remainder of 2004. We are considering another transaction with Genesis Energy,
L.P. ("Genesis") to sell them another volumetric production payment of CO2 and
assign them most of our remaining long-term CO2 supply agreements with our
industrial customers, further increasing our cash position by an estimated $5
million to $10 million. We plan to invest our anticipated excess cash over the
next one to two years by accelerating our development of CO2 reserves and
deliverability at Jackson Dome, accelerating, to the extent possible, our second
phase of tertiary operations planned for East Mississippi, and increasing our
expenditures elsewhere in areas such as the Barnett Shale. We are also
continuing our search for property acquisitions, particularly those that have
future tertiary potential. Although we now control most of the fields along our
CO2 pipeline, there are a few remaining smaller fields with this potential that
we do not control, and we are continuing to acquire additional interests in the
fields that we currently own. We also may seek oil fields in other areas, which
may have future tertiary opportunities, as well as conventional development and
exploration projects.
Off-Balance Sheet Arrangements
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet are
our operating leases and various obligations for development and exploratory
expenditures arising from purchase agreements, our capital expenditure program,
or other transactions common to our industry. In addition, in order to recover
our undeveloped proved reserves, we must also fund the associated future
development costs as forecasted in the proved reserve reports. Further, one of
our subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed
the bank debt of Genesis (which as of June 30, 2004, consisted of $5.5 million
of debt and $20.6 million in letters of credit, $10.7 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 7 to the
Unaudited Condensed Consolidated Financial Statements. Neither the amounts nor
the terms of these commitments or contingent obligations have changed
significantly from the year-end 2003 amounts reflected in our Form 10-K filed in
March 2004. Please refer to Management's Discussion and Analysis of Financial
Condition and Results of Operations contained in our 2003 Form 10-K for further
information regarding our commitments and obligations.
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
CO2 Operations
As described in the "Overview" section above, our CO2 operations are
becoming an ever-increasing part of our business and operations. We believe that
there are significant additional oil reserves and production that can be
obtained through the use of CO2, and we have outlined certain of this potential
in our annual report and other public disclosures. In addition to its long-term
effect, this shift in focus impacts certain trends in our current and near-term
operating results. Please refer to Management's Discussion and Analysis of
Financial Condition and Results of Operations and the section entitled "CO2
Operations" contained in our 2003 Form 10-K for further information regarding
these issues.
To date during 2004, we have drilled or sidetracked four additional CO2
wells, two of which were producing as of August 9, 2004, and two of which were
still being completed. During the first half of the year, our CO2 production
averaged 234.0 MMcf/d. We used 65% of this, or 153.2 MMcf/d, in our tertiary
operations, and sold the balance to our industrial customers or to Genesis
pursuant to our volumetric production payment. We believe that upon completion
of our two latest CO2 wells that our production capacity of CO2 will grow to at
least 350 MMcf/d. Based on preliminary reserve estimates, we believe that the
last two CO2 wells will increase our proven CO2 reserves by approximately [1.0
Tcf], a significant increase from the 1.6 Tcf of proven CO2 reserves as of
December 31 2003. With the success of these last two CO2 wells, we should have
sufficient CO2 reserves for our planned expansion of CO2 operations into East
Mississippi. We have scheduled a 3-D seismic shoot over the Jackson Dome area in
the second half of 2004 to help us delineate our future CO2 drilling efforts
there. We plan to further expand and increase our CO2 reserves and production
capability in order to provide enough CO2 for our planned expansion of our
tertiary operations, a significant focus and growth area for us for the
foreseeable future.
Our oil production from our CO2 tertiary recovery activities in the second
quarter of 2004 increased 5% over first quarter 2004 levels and 46% over second
quarter 2003 levels, to 6,603 Bbls/d in the second quarter of 2004, with most of
the increase since the second quarter of 2003 occurring at Mallalieu Field.
Production at Mallalieu averaged 3,172 Bbls/d during the second quarter of 2004,
as compared to 3,105 Bbls/d in the prior quarter and 1,388 Bbls/d during the
second quarter of 2003. We expect our tertiary oil production to continue to
grow during 2004 to a projected average of approximately 7,000 Bbls/d for the
year, with additional increases expected at all three of our ongoing tertiary
operations at Mallalieu, Little Creek and McComb Fields. During the second
quarter, we have seen our first minor production response from McComb Field as a
result of CO2 injections which commenced late in 2003, averaging 121 Bbls/d for
the second quarter, although we do not expect oil production from this field to
be significant until late in 2004.
We spent approximately $0.11 per Mcf to produce our CO2 during the first
half of 2004, less than the 2003 average of $0.15 per Mcf, as we did not have
any significant workover costs on CO2 wells during the first half of 2004.
However, as a result of continued high oil prices, CO2 royalty expenses
increased, partially offsetting other operating expense savings, as certain of
our CO2 royalty payments increase if the price of oil increases beyond a certain
threshold. Our total cost per thousand cubic feet of CO2 during the first half
of 2004 was approximately $0.20, after inclusion of depreciation and
amortization expense, still significantly less than the $0.37 per thousand cubic
feet that would have been paid had we been paying under the purchase contract
that existed at the time we acquired the CO2 properties in February 2001.
For the first half of 2004, our operating costs for our tertiary properties
averaged $9.94 per BOE, less than the $10.56 per BOE average in the first half
of 2003 and our 2003 annual average of $11.34 per BOE. The savings were a result
of the lower cost to produce CO2 discussed above, higher oil production levels,
and the realization of approximately $174,000 from the sale of CO2 Kyoto
emission reduction credits generated by the re-injection of CO2. In the first
quarter of 2003, we received $232,000 from the sale of emission reduction
credits.
Our net operating margin from the sale of CO2 to industrial customers
decreased in the first half of 2004 to $2.6 million, down from $3.8 million
during the first half of 2003, primarily related to the volumetric production
payment we sold to Genesis at a lower average price per thousand cubic foot than
we received from the industrial customers in the prior year. We received cash
from the Genesis volumetric production payment when the transaction was
consummated in the fourth quarter of 2003, thus $1.1 million of the industrial
sale revenue is non-cash recognition of deferred revenue.
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Results
As summarized in the "Overview" section above, higher commodity prices and
production, partially offset by higher hedge payments and expenses, resulted in
near-record quarterly cash flow from operations and strong earnings. 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 was recorded as a
cumulative effect adjustment of a change in accounting principle, net of income
taxes, in our Unaudited Condensed Consolidated Statements of Operations and is
listed below on both a gross and per share basis.
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------------------------------------ ---------------------------- ---------------------------
Amounts in thousands, except per share amounts 2004 2003 2004 2003
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Income before cumulative effect of a change in
accounting principle $ 19,389 $ 5,129 $ 41,693 $ 23,582
Cumulative effect of a change in accounting
principle, net of income tax expense of $1,600 - - - 2,612
------------- ------------- ------------- ------------
Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Net income per common share - basic:
Income before cumulative effect of a change
in accounting principle $ 0.35 $ 0.10 $ 0.76 $ 0.44
Cumulative effect of a change in accounting principle - - - 0.05
------------- ------------- ------------- ------------
Net income per common share - basic $ 0.35 $ 0.10 $ 0.76 $ 0.49
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Net income per common share - diluted:
Income before cumulative effect of a change
in accounting principle $ 0.34 $ 0.09 $ 0.73 $ 0.42
Cumulative effect of a change in accounting principle - - - 0.05
------------- ------------- ------------- ------------
Net income per common share - diluted $ 0.34 $ 0.09 $ 0.73 $ 0.47
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Adjusted cash flow from operations (see below) $ 63,054 $ 48,989 $ 121,974 $ 96,355
Net change in assets and liabilities relating to operations (9,844) 11,553 (15,769) (304)
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Cash flow from operations (1) $ 53,210 $ 60,542 $ 106,205 $ 96,051
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
(1) Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements of Cash Flows.
Adjusted cash flow from operations is a non-GAAP measure that represents
cash flow provided by operations before changes in assets and liabilities as
presented in our Unaudited Condensed Consolidated Statements of Cash Flows. Cash
flow from operations is the GAAP measure as presented in our Unaudited Condensed
Consolidated Statements of Cash Flows. In our discussion herein, we have elected
to discuss these two components of cash flow provided by operations separately.
Adjusted cash flow from operations, the non-GAAP measure, 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 year. We also use this
measure because the collection of our receivables or payment of our obligations
has not been a significant issue for our business, but merely a timing issue
from one period to the next, with fluctuations generally caused by significant
changes in commodity prices or significant changes in drilling activity.
The net change in assets and liabilities relating to operations is also
important as it does require or provide additional cash for use in our business;
however, we prefer to discuss its effect separately. For instance, as noted
above, during the first six months of 2004, we spent $7.5 million (in the second
quarter) to acquire 7,500 Bbls/d of oil puts or floors for 2005 and to retire 20
MMcf/d of natural gas hedges for the balance of 2004, and funded a $10.8 million
increase in accrued production receivables as a result of the higher commodity
prices during the second quarter of 2004, partially
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
offset by changes in other assets and liabilities. Conversely in 2003, commodity
prices were highest in the first quarter, causing an increase in our accrued
production receivables during March 2003 as a result of unusually high natural
gas prices that month, with natural gas index prices in the $9.28 per MMBtu
range, with such receivables decreasing during the second quarter as commodity
prices declined.
Certain of our operating results and statistics for the comparative second
quarters and first six months of 2004 and 2003 are included in the following
table.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------------------------------------------------------------- ----------------------------
2004 2003 2004 2003
- --------------------------------------------------------------------------------------------- ------------- -------------
Average daily production volumes
Bbls/d 18,730 18,957 19,067 19,259
Mcf/d 107,230 96,558 105,344 97,857
BOE/d (1) 36,602 35,050 36,624 35,569
Operating revenues and expenses (thousands)
Oil sales $ 58,529 $ 43,922 $ 113,054 $ 96,135
Natural gas sales 60,542 50,830 116,253 110,341
Loss on settlements of derivative contracts (2) (18,239) (13,356) (32,507) (41,041)
------------- ------------ ------------- -------------
Total oil and natural gas revenues $ 100,832 $ 81,396 $ 196,800 $ 165,435
============= ============ ============= =============
Lease operating expenses $ 24,530 $ 23,048 $ 47,058 $ 45,450
Production taxes and marketing expenses 4,514 3,467 8,581 7,363
------------- ------------ ------------- -------------
Total production expenses $ 29,044 $ 26,515 $ 55,639 $ 52,813
============= ============ ============= =============
CO2 sales and transportation fees (3) $ 1,580 $ 2,445 $ 2,941 $ 4,634
CO2 operating expenses 209 534 353 851
------------- ------------ ------------- -------------
CO2 operating margin $ 1,371 $ 1,911 $ 2,588 $ 3,783
============= ============ ============= =============
Unit prices - including impact of hedges
Oil price per Bbl $ 26.56 $ 23.93 $ 25.72 $ 24.32
Gas price per Mcf 5.69 4.56 5.61 4.55
Unit prices - excluding impact of hedges
Oil price per Bbl $ 34.34 $ 25.46 $ 32.58 $ 27.58
Gas price per Mcf 6.20 5.78 6.06 6.23
Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues $ 35.75 $ 29.71 $ 34.40 $ 32.07
============= ============ ============= =============
Oil and gas lease operating expenses $ 7.36 $ 7.23 $ 7.06 $ 7.06
Oil and gas production taxes and marketing expense 1.36 1.08 1.29 1.15
------------- ------------ ------------- -------------
Total oil and gas production expenses $ 8.72 $ 8.31 $ 8.35 $ 8.21
- --------------------------------------------------------------------------------------------- --------------- -----------
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the
Company's hedging transactions.
(3) For three and six months ended June 30, 2004, includes deferred revenue of
$0.6 million and $1.1 million, respectively, associated with a volumetric
production payment and $0.7 million and $1.2 million, respectively, of
transportation income from Genesis.
22
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 2003 and the first
- ---------- and second quarters of 2004 is listed in the following table.
Average Daily Production (BOE/d)
--------------------------------------------------------------------------------
First Second Third Fourth First Second
Quarter Quarter Quarter Quarter Quarter Quarter
2003 2003 2003 2003 2004 2004
- ------------------------------------------------------------------------------------------------------------------
Mississippi - non-CO2 floods 14,537 13,600 13,367 13,066 12,754 13,048
Mississippi - CO2 floods 4,345 4,522 4,227 5,579 6,318 6,603
Onshore Louisiana 8,700 8,417 8,024 8,812 8,825 7,492
Offshore Gulf of Mexico 8,353 8,351 7,186 6,865 8,521 9,114
Other 158 160 312 268 229 345
--------------------------------------------------------------------------------
Total Denbury 36,093 35,050 33,116 34,590 36,647 36,602
- ------------------------------------------------------------------------------------------------------------------
Overall production increased 4% on a BOE/d basis in the second quarter of
2004 as compared to the second quarter of 2003, but was relatively stable
between the first and second quarters of 2004 and the respective first six
months of 2003 and 2004. However, several factors that caused fluctuations
between the various periods should be noted. During the first quarter of 2003
(effective January 31), we sold Laurel Field, a Mississippi non-CO2 flood
property that had averaged between 1,500 and 1,700 BOE/d since we acquired it in
August 2002. Eliminating the one month of Laurel Field production in 2003
reduces the variance in the first quarter to first quarter production for
Mississippi - non-CO2 floods by approximately 526 BOE/d. The balance of the
decline in this operating area is primarily related to normal depletion at
several of our fields. Production increased slightly in this area in the second
quarter of 2004, as compared to production in the prior quarter, as a result of
additional natural gas drilling in the Selma Chalk formation at Heidelberg
Field. Natural gas production at this field averaged 14.8 MMcf/d in the second
quarter of 2004, up from 11.0 MMcf/d in the prior quarter and 10.4 MMcf/d in the
second quarter of 2003, making Heidelberg Field our single largest natural gas
producing field for the most recent quarter.
As more fully discussed in "CO2 Operations" above, oil production from our
tertiary operations continued to increase in the second quarter of 2004,
averaging 6,603 Bbls/d, representing 35% of our second quarter corporate oil
production and 24% of our total corporate production on a BOE basis pro forma to
give effect to the offshore sale. Production from our offshore properties
averaged 9,114 BOE/d in the quarter, the highest level for us since 2002,
following an active development program during the last eighteen months. Without
significant continued development in this area, production was expected to
decrease rapidly in the future had the properties not been sold. Production
declines in our onshore Louisiana properties offset the increases in other
areas, declining 15% from first quarter 2004 levels and 11% from second quarter
2003 levels. Production at Thornwell, an onshore Louisiana Field, averaged 1,403
BOE/d during the second quarter of 2004, down from 2,526 BOE/d in the prior
quarter, and 2,820 BOE/d in the second quarter of 2003. We did not process any
liquids this quarter at Thornwell, a decision that is made monthly depending on
the relative price of liquids and natural gas, causing part of the decline. More
significantly, production from this field is in a steep decline due to its
short-lived nature, and is expected to further decline throughout 2004. In spite
of its short remaining life, we have generated a good return on investment at
Thornwell, with a net profit to date (on a cash basis) through June 30, 2004 of
$32.3 million. This field, and our offshore properties just sold, were expected
to have the steepest decline rates of any of our properties during the near
future.
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Oil and Natural Gas Revenues: Oil and natural gas revenues, net of hedge
payments, for the second quarter of 2004 increased $24.3 million, or 26%, from
the comparable quarter of 2003, primarily as a result of higher commodity
prices, plus slightly higher production, partially offset by higher payments on
our hedges. When comparing the respective six-month periods, revenues were also
higher in 2004, primarily as a result of higher commodity prices. Production was
almost the same for the comparable six-month periods and hedge payments were
higher in the first half of 2003 than in the first half of 2004 due to unusually
high natural prices in March 2003, when natural gas index prices were
approximately $9.28 per MMBtu. Cash payments on our hedges were $18.2 million in
the second quarter of 2004 and $32.5 million year to date, up 37% on a quarterly
basis from the $13.4 million paid during the second quarter of 2003, but down
21% from the $41.0 million paid during the first six months of 2003. See "Market
Risk Management" for additional information regarding our hedging activities.
Record high average commodity prices on a per BOE basis in the second
quarter of 2004 increased revenues 25% or $20.1 million between the respective
second quarters of 2004 and 2003. The 4% increase in production in the second
quarter of 2004 further increased oil and natural gas revenues for the two
periods, by $4.2 million, or 5%. However, higher hedge payments reduced revenue
by $4.9 million or 6% between the respective second quarters. While both
commodity prices were higher in the second quarter of 2004 as compared to those
in the second quarter of 2003, the increase in oil prices was the most
significant, with an increase in our average net oil price of $8.88 per Bbl, a
35% increase. Natural gas prices were approximately 7% higher between the two
respective periods.
When comparing the respective six month periods, higher commodity prices,
higher production and lower hedge payments all contributed to higher revenue in
the first half of 2004 as compared to revenue in the first half of 2003. Higher
commodity prices on a per BOE basis in the first half of 2004 increased revenues
9% or $15.5 million between the respective first six months of 2004 and 2003.
The 3% increase in production in the first half of 2004 further increased oil
and natural gas revenues for the two periods, by $7.3 million, or 4%. Lower
hedge payments in the first half of 2004 increased revenue by $8.5 million or 5%
between the respective six month periods. Natural gas prices were almost the
same between the respective six month periods, while our average net oil price
increased 18%, from $27.58 per Bbl in the first half of 2003 to $32.58 per Bbl
in the first half of 2004.
Production Expenses: To date in 2004, we have not had significant workover
expenses, although we had higher than normal repairs and maintenance on offshore
platforms during the period. In comparison, during the first half of 2003, we
incurred $2.9 million on two workovers relating to mechanical failures of two
onshore Louisiana wells. Operating expenses on our tertiary operations increased
from $8.5 million in the first half of 2003 to $11.7 million in the comparable
period of 2004 as a result of increased activity at Mallalieu and McComb Fields.
However, with the 46% higher production from these tertiary operations,
operating expenses for our tertiary operations on a per BOE basis decreased from
$10.56 per BOE in the first half of 2003 to $9.94 per BOE in the first half of
2004. Nonetheless, our tertiary operations are resulting in steadily increasing
costs per BOE on a corporate basis as our tertiary operations constitute a more
significant portion of our total production and operations. The balance of cost
increases is generally attributable to higher energy costs to operate the
properties and general cost inflation in our industry. In general, we expect our
operating costs per BOE to increase throughout 2004 and beyond as the operating
costs of our tertiary operations are higher than for our other operations and as
tertiary operations become more and more significant.
Production taxes and marketing expenses generally change in proportion to
commodity prices and production and as such, were higher in the second quarter
of 2004 following the record high commodity prices.
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General and Administrative Expenses
General and administrative ("G&A") expenses increased 18% on a per BOE
basis between the respective second quarters and 21% between the respective
first six months, as set forth below:
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------------------- ----------------------------------- -------------------------
2004 2003 2004 2003
- ------------------------------------------------- ---------------- ---------------- ------------ ------------
Net G&A expense (thousands)
Gross G&A expenses $ 11,773 $ 10,971 $ 24,453 $ 22,403
State franchise taxes 242 358 488 721
Operator overhead charges (6,714) (6,508) (13,494) (13,023)
Capitalized exploration costs (1,123) (1,445) (2,521) (2,934)
---------------- ---------------- ------------ ------------
Net G&A expense $ 4,178 $ 3,376 $ 8,926 $ 7,167
================ ================ ============ ============
Average G&A cost per BOE $ 1.25 $ 1.06 $ 1.34 $ 1.11
Employees as of June 30 395 369 395 369
- ------------------------------------------------- ---------------- ---------------- ------------ ------------
Gross G&A expenses increased $802,000, or 7%, between the respective second
quarters and $2.1 million or 9% between the respective first six months. The
single largest component of this increase relates to approximately $475,000 and
$975,000 of employee severance payments in the second quarter and first half of
2004, respectively, for a portion of the offshore professional and technical
staff terminated prior to June 30, 2004 in conjunction with our offshore
property sale. We expect the remaining employees dedicated to our offshore
operations to be terminated in the third quarter at an estimated cost of
approximately $1.6 million. We also incurred additional G&A expenses associated
with the corporate restructuring in December 2003, compliance with the
requirements of the Sarbanes-Oxley Act, the sale of stock by the Texas Pacific
Group in March 2004, and overall increases in most other categories of G&A due
to general cost inflation. As a result of the personnel reductions in our
offshore area, our capitalized exploration costs decreased slightly in the
second quarter of 2004 as compared to the level of those costs in the same
period in 2003, partially offset by slightly higher overhead recoveries
resulting from incremental development activity. The change in net G&A was
similar to the change in gross G&A between the respective periods. On a per BOE
basis, G&A costs increased parallel to the change in gross cost as the change in
overall production rates was not significant between the periods.
Interest and Financing Expenses
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------- ---------------------------------- -----------------------------
Amounts in thousands, except per BOE amounts 2004 2003 2004 2003
- ---------------------------------------------------- -------------- ---------------- ------------- ------------
Interest expense $ 5,068 $ 6,227 $ 10,149 $ 12,688
Non-cash interest expense (227) (296) (454) (799)
-------------- ---------------- ------------- ------------
Cash interest expense 4,841 5,931 9,695 11,889
Interest and other income (330) (347) (749) (551)
-------------- ---------------- ------------- ------------
Net cash interest expense $ 4,511 $ 5,584 $ 8,946 $ 11,338
============== ================ ============= ============
Average net cash interest expense per BOE $ 1.35 $ 1.75 $ 1.34 $ 1.76
Average interest rate (1) 6.3% 6.5% 6.3% 6.6%
Average debt outstanding $ 309,286 $ 367,747 $307,703 $359,696
- ---------------------------------------------------- ============== ================ ============= ============
(1) Includes commitment fees but excludes amortization of discount and debt issue costs.
Interest expense for the second quarter and first six months of 2004
decreased from levels in the comparable periods of 2003 primarily due to (i)
lower overall interest rates, primarily as a result of our subordinated debt
refinancing in 2003, and (ii) lower average debt levels as a result of our $50
million reduction in debt during 2003. Our non-cash interest expense also
decreased as a result of the subordinated debt refinancing, which eliminated the
amortization of discount on
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
our old subordinated debt, which was higher than the discount and related
amortization on our new subordinated debt issue.
Depletion, Depreciation and Amortization
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------------------- --------------------------------- --------------------------
Amounts in thousands, except per BOE amounts 2004 2003 2004 2003
- --------------------------------------------------- --------------- -------------- ------------- ------------
Depletion and depreciation $ 25,694 $ 21,449 $ 50,698 $ 43,429
Depletion and depreciation of CO2 assets 1,240 592 2,378 1,030
Accretion of asset retirement obligations 774 684 1,541 1,503
Depreciation of other fixed assets 453 405 868 721
--------------- -------------- ------------- ------------
Total DD&A $ 28,161 $ 23,130 $ 55,485 $ 46,683
=============== ============== ============= ============
DD&A per BOE:
Oil and natural gas properties $ 7.95 $ 6.94 $ 7.83 $ 6.98
CO2 assets and other fixed assets 0.51 0.31 0.49 0.27
- --------------------------------------------------- --------------- -------------- ------------- ------------
Total DD&A cost per BOE $ 8.46 $ 7.25 $ 8.32 $ 7.25
- --------------------------------------------------- =============== ============== ============= ============
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis increased 17% between the respective second quarters, primarily
due to the higher percentage of expenditures on offshore properties during 2003
and the first half of 2004, which have higher overall finding and development
costs. In addition, certain of our future development cost estimates have
increased to reflect the rising costs in the industry, contributing to the
increase in our DD&A rate over the first quarter rate. The 2004 rates are more
comparable to the DD&A rate of $8.00 per BOE during the fourth quarter of 2003
than to the DD&A rate for the first half of 2003. To date, we have added only a
portion of the incremental oil reserves that we expect to add during 2004 from
our tertiary operations. As such, our DD&A rate could change significantly in
the next six months. We project that our DD&A rate will decrease by $0.70 to
$0.80 per BOE in the third quarter as a result of the sale of our offshore
properties. We also expect the DD&A rate for our CO2 assets to decrease in the
third quarter as a result of the recent increase in CO2 reserves from the two
wells being completed, although these savings will be partially offset by the
continuing increase in CO2 production volumes.
Income Taxes
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------------------------------- --------------------------------- --------------------------
Amounts in thousands, except per BOE amounts and tax rates 2004 2003 2004 2003
- ------------------------------------------------------------- -------------- --------------- ------------ -------------
Income tax provision
Current income tax expense (benefit) $ 977 $ (1,093) $ 3,096 $ 1,637
Deferred income tax expense 8,672 3,527 17,194 9,882
-------------- --------------- ------------ -------------
Total income tax expense $ 9,649 $ 2,434 $ 20,290 $ 11,519
============== =============== ============ =============
Average income tax expense per BOE $ 2.90 $ 0.76 $ 3.04 $ 1.79
Effective tax rate 33.2% 32.2% 32.7% 32.8%
- ------------------------------------------------------------- -------------- --------------- ------------ -------------
Our income tax provision for the respective periods was based on an
estimated statutory tax rate of 38%. 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. The current income tax expense
represents our anticipated alternative minimum cash taxes that we cannot offset
with our regular tax net operating loss carryforwards or our enhanced oil
recovery credits. We recognized a current income tax credit of $1.1 million in
the 2003 second quarter due to a downward revision in our 2003 forecast of
taxable income at that time.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Per BOE Data
The following table summarizes our cash flow, DD&A and results of
operations on a per BOE basis for the comparative periods. Each of the
individual components are discussed above.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------------------------------- -------------------------- -------------------------
Per BOE data 2004 2003 2004 2003
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Revenues $ 35.75 $ 29.71 $ 34.40 $ 32.07
Loss on settlements of derivative contracts (5.48) (4.19) (4.88) (6.37)
Lease operating expenses (7.36) (7.23) (7.06) (7.06)
Production taxes and marketing expenses (1.36) (1.08) (1.29) (1.15)
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Production netback 21.55 17.21 21.17 17.49
CO2 operating margin 0.41 0.60 0.39 0.59
General and administrative expenses (1.25) (1.06) (1.34) (1.11)
Net cash interest expense (1.35) (1.75) (1.34) (1.76)
Current income taxes and other (0.42) 0.36 (0.58) (0.24)
Changes in assets and liabilities (2.96) 3.62 (2.37) (0.05)
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Cash flow from operations 15.98 18.98 15.93 14.92
DD&A (8.46) (7.25) (8.32) (7.25)
Deferred income taxes (2.60) (1.11) (2.58) (1.54)
Amortization of derivative contracts and other non-cash
hedging adjustments (2.15) 0.24 (1.19) 0.35
Early retirement of subordinated debt - (5.53) - (2.74)
Cumulative effect of change in accounting principle - - - 0.41
Changes in assets and liabilities and other non-cash items 3.05 (3.72) 2.42 (0.08)
- --------------------------------------------------------------- -------------------------- ------------ ------------
Net income $ 5.82 $ 1.61 $ 6.26 $ 4.07
- --------------------------------------------------------------- -------------------------- ------------ ------------
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
- ----------------------------------------- ---------------------------------------------------------------------------------
2004- Carrying Fair
Amounts in thousands 2005 2006 2007 2008 After Value Value
- ----------------------------------------- ------- -------- ------- ------- --------- ----------- --------------
Variable rate debt:
Bank debt............................... $ - $ 85,000 $ - $ - $ - $ 85,000 $ 85,000
The weighted-average interest rate on the bank debt at June 30, 2004 is 2.6%.
Fixed rate debt:
7.5% subordinated debt,
net of discount, due 2013............. $ - $ - $ - $ - $ 225,000 $ 223,300 $ 233,438
The interest rate on the subordinated debt is a fixed rate of 7.5%.
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes.
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
These contracts have historically consisted of price floors, collars and fixed
price swaps. We generally attempt to hedge between 33% 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, although our hedging percentage
may vary relative to our debt levels. For example, when our debt levels are
high, we may hedge a higher percentage of our production than when our debt
levels are low. 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. Much of our hedging activity has been with collars,
although for the 2002 COHO acquisition, we also used swaps in order to lock in
the prices used in our economic forecasts. In the second quarter of 2004, we
purchased price floors or puts relating to a portion of our 2005 oil production,
allowing us to retain any upside from increases in commodity prices. 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.
Upon reaching a verbal agreement on the offshore property sale, subject
primarily to the purchaser's further due diligence, we entered into natural gas
swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005,
covering the anticipated natural gas production from our offshore properties for
that period, with the tacit understanding with the prospective purchaser that
these hedges would be transferred to the purchaser upon closing. These swaps did
not qualify for hedge accounting and as of August 6, we had assigned them to the
purchaser of the offshore properties. At about the same time, with the
expectation that the offshore transaction would be consummated, we retired, by
purchasing offsetting contracts, 20 MMcf/d of our natural gas hedges for July to
December of 2004, at a cost of approximately $3.9 million. This transaction, and
the related hedge accounting designation changes and associated fair market
value adjustments, was the primary reason for the $7.1 million net charge to
earnings in the second quarter of 2004 relating to our derivative contracts.
At June 30, 2004, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $36.9 million, a decrease of
approximately $7.7 million from the $44.6 million fair value liability recorded
as of December 31, 2003. This decrease in our net liability is a result of the
termination of six months of derivative contracts due to the passage of time,
partially offset by an increase in the liability as a result of higher oil and
natural gas commodity prices between December 31, 2003 and June 30, 2004.
Information regarding our current hedging positions is included in Note 7 to the
Unaudited Condensed Consolidated Financial Statements.
Although we have hedged less of our production in 2004 than in 2003
(approximately 55% of our total production in 2004 as compared to approximately
80% in 2003), we expect our total hedge payments for 2004 to be about the same
as in 2003 due to the currently higher oil prices in 2004 and lower hedged
prices. To date for 2005, we have 15.0 MMcf/d of natural gas collars with a
floor of $3.00 per MMBtu and a ceiling of approximately $5.50 per MMBtu and
7,500 Bbls/d of oil puts or floors with a floor price of $27.50, acquired at a
total cost of approximately $3.6 million. Since these most recent hedges are
puts or price floors, the maximum out-of-pocket exposure is the cost of the put.
Based on NYMEX natural gas futures prices at June 30, 2004, we would expect
to make future cash payments of $13.4 million on our natural gas commodity
hedges. If natural gas futures prices were to decline by 10%, we would expect to
receive $8.2 million under our natural gas commodity hedges, and if futures
prices were to increase by 10% we would expect to pay $36.0 million. Based on
NYMEX crude oil futures prices at June 30, 2004, we would expect to pay $24.2
million on our crude oil commodity hedges. If crude oil futures prices were to
decline by 10%, we would expect to pay $17.8 million, and if crude oil futures
prices were to increase by 10%, we would expect to pay $30.7 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, asset retirement obligations, income taxes and hedging activities, and
which remain unchanged, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in our annual report on Form 10-K for the
year ended December 31, 2003.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q ("Quarterly
Report") that are not historical facts, including, but not limited to,
statements found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, acquisition plans and proposals and dispositions, development
activities, cost savings, production efforts and volumes, hydrocarbon reserves,
hydrocarbon prices, CO2 production and deliverability, liquidity, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "estimate," "budgeted," "expect,"
"predict," "anticipate," "projected," "should," "assume," "believe" or other
words that convey the uncertainty of future events or outcomes. Such
forward-looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and our financial condition and results of
operations. As a consequence, actual results may differ materially from
expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for our oil and natural gas, the uncertainty of
drilling results and reserve estimates, operating hazards, acquisition risks,
requirements for capital, general economic conditions, competition and
government regulations, as well as the risks and uncertainties discussed in this
Quarterly Report, including, without limitation, the portions referenced above,
and the uncertainties set forth from time to time in the Company's other public
reports, filings and public statements.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- -------------------------------------------------------------------
The information required by Item 3 is set forth under "Market Risk
Management" in Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Item 4. Controls and Procedures
- --------------------------------
Denbury maintains disclosure controls and procedures designed to ensure
that information required to be disclosed in our filings under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commission's rules and
forms. Our chief executive officer and chief financial officer have evaluated
our disclosure controls and procedures as of the end of the period covered by
this Quarterly Report on Form 10-Q and have determined that such disclosure
controls and procedures are effective in all material respects in providing to
them on a timely basis material information required to be disclosed in this
quarterly report.
There have been no significant changes in internal controls over financial
reporting during the period covered by this Quarterly Report on Form 10-Q that
have materially affected, or are reasonably likely to materially affect,
Denbury's internal controls over financial reporting.
Part II. Other Information
Item 2. Change in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
- --------------------------------------------------------------------------------
ISSUER PURCHASES OF EQUITY SECURITIES
(c) Total Number of (d) Maximum Number
(a) Total Shares Purchased of Shares that May
Number of (b) Average as Part of Publicly Yet Be Purchased
Shares Price Paid Announced Plans or Under the Plan Or
Period Purchased per Share Programs Programs
- ------------------------------------------------------------------------------------------------------------
January 1 through 31, 2004 - - - 100,000
February 1 through 29, 2004 50,000 $ 14.87 50,000 50,000
March 1 through 31, 2004 - - - 50,000
April 1 through 30, 2004 25,000 $ 18.74 25,000 25,000
May 1 through 31, 2004 25,000 $ 17.96 25,000 100,000
June 1 through 30, 2004 - - - 100,000
Total 100,000 $ 16.61 100,000 100,000
- ------------------------------------------------------------------------------------------------------------
In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase
shares of our common stock on the NYSE in order for such repurchased shares to
be reissued to our employees who participate in Denbury's Employee Stock
Purchase Plan. The Plan provides for purchases through an independent broker of
50,000 shares of Denbury's common stock per fiscal quarter for a period of
approximately twelve months, or a total of 200,000 shares, beginning August 13,
2003 and ending on July 31, 2004. In May 2004, the Board of Directors renewed
the Plan for another year, beginning July 1, 2004 and ending June 30, 2005.
Purchases are to be made at prices and times determined at the discretion of the
independent broker, provided however that no purchases may be made during the
last ten business days of a fiscal quarter.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
Denbury's Annual Meeting of Shareholders was held on May 12, 2004 for the
purposes of: (1) electing six Directors of Denbury for one-year terms to expire
at the 2005 Annual Meeting of Shareholders, and (2) approving a new omnibus
stock and incentive plan. At the record date, March 31, 2004, 54,672,960 shares
of common stock were outstanding and entitled to one vote per share upon all
matters submitted at the meeting. Holders of 46,050,628 shares of common stock,
30
representing approximately 84% of the total issued and outstanding shares of
common stock, were present in person or by proxy at the meeting to cast their
vote.
With respect to the election of directors, all six director nominees were
re-elected. All of the directors are elected on an annual basis. The votes were
cast as follows:
Nominees for Directors For Withheld
- --------------------------- ------------- ----------
Ronald G. Greene 45,908,287 142,341
David I. Heather 45,708,672 341,956
William S. Price, III 45,088,739 961,889
Gareth Roberts 45,893,737 156,891
Wieland F. Wettstein 45,572,972 477,656
Carrie A. Wheeler 45,091,655 958,973
On May 31, 2004, Mr. William S. Price, III and Ms. Carrie A. Wheeler, both
principals of the Texas Pacific Group resigned as directors. On June 3, 2004,
Mr. Donald D. Wolf was appointed as a director to fill one of the vacancies.
The proposed 2004 Omnibus Stock and Incentive Plan was also approved. The
votes were cast as follows:
For Against Abstentions Broker Non-Votes
- --------------- ----------- -------------- --------------------
33,111,946 4,515,825 273,361 8,149,496
Item 6. Exhibits and Reports on Form 8-K during the Second Quarter of 2004
- --------------------------------------------------------------------------
Exhibits:
--------
31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
* Filed herewith.
Reports on Form 8-K:
-------------------
On April 28, 2004, we filed a Form 8-K, which included our press release on
our first quarter 2004 earnings.
On May 17, 2004, we filed a Form 8-K, as amended on May 24, 2004, which
announced the appointment of PricewaterhouseCoopers LLP as the Company's
independent auditors for the year ended December 31, 2004, to replace Deloitte &
Touche LLP. In addition, the company announced it had renewed its stock purchase
plan for another year.
On June 3, 2004, we filed a Form 8-K, which announced the resignation of
William S. Price, III and Carrie A. Wheeler as directors of the company, and the
appointment of Donald S. Wolf to serve as a director of the company.
31
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DENBURY RESOURCES INC.
(Registrant)
By: /s/ Phil Rykhoek
----------------------------------------------
Phil Rykhoek
Sr. Vice President and Chief Financial Officer
By: /s/ Mark C. Allen
----------------------------------------------
Mark C. Allen
Vice President and Chief Accounting Officer
Date August 9, 2004
32