UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] Quarterly report pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the quarterly period ended September 30, 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 October 29, 2004
----- -------------------------------
Common Stock, $.001 par value 56,355,352
INDEX
Page
----
Part I. Financial Information
- ------------------------------
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at September 30, 2004 and
December 31, 2003 3
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2004 and 2003 4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Nine
Months Ended September 30, 2004 and 2003 5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for
the Three and Nine months Ended September 30, 2004 and 2003 6
Notes to Unaudited Condensed Consolidated Financial Statements 7-20
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 21-33
Item 3. Quantitative and Qualitative Disclosures about Market Risk 34
Item 4. Controls and Procedures 34
Part II. Other Information
---------------------------
Item 1. Legal Proceedings 34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 34
Item 3. Defaults Upon Senior Securities N/A
Item 4. Submission of Matters to a Vote of Security Holders N/A
Item 5. Other Information N/A
Item 6. Exhibits 35
Signatures 36
2
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
September 30, December 31,
2004 2003
--------------- --------------
Assets
Current assets
Cash and cash equivalents $ 93,142 $ 24,188
Short-term investments 31,955 -
Accrued production receivables 36,062 33,944
Related party receivable - Genesis 534 6,927
Trade and other receivables 14,218 18,080
Deferred tax asset 31,664 25,016
Derivative assets 1,888 -
---------------- ---------------
Total current assets 209,463 108,155
---------------- ---------------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,276,701 1,409,579
Unevaluated 23,171 46,065
CO2 properties and equipment 132,112 85,467
Other 19,035 16,450
Less accumulated depletion and depreciation (687,083) (705,050)
---------------- ---------------
Net property and equipment 763,936 852,511
---------------- ---------------
Investment in Genesis 7,034 7,450
Other assets 11,276 14,505
---------------- ---------------
Total assets $ 991,709 $ 982,621
================ ===============
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 64,006 $ 62,349
Oil and gas production payable 22,963 22,215
Payable to Newfield Exploration Company 16,020 -
Derivative liabilities 37,796 42,010
---------------- ---------------
Total current liabilities 140,785 126,574
---------------- ---------------
Long-term liabilities
Long-term debt 223,348 298,203
Asset retirement obligations 16,620 41,711
Derivative liabilities 1,979 2,603
Deferred revenue - Genesis 24,018 21,468
Deferred tax liability 82,885 68,555
Other 1,444 2,305
---------------- ---------------
Total long-term liabilities 350,294 434,845
---------------- ---------------
Commitments and contingencies
Stockholders' equity
Common stock, $.001 par value, 100,000,000 shares authorized;
56,443,422 and 54,190,042 shares issued at September 30, 2004 and
December 31, 2003, respectively 56 54
Paid-in capital in excess of par 438,417 401,709
Deferred compensation (22,427) -
Retained earnings 106,623 46,656
Accumulated other comprehensive loss (20,779) (27,113)
Treasury stock, at cost, 64,779 and 8,162 shares at September 30, 2004 and
December 31, 2003, respectively (1,260) (104)
---------------- ---------------
Total stockholders' equity 500,630 421,202
---------------- ---------------
Total liabilities and stockholders' equity $ 991,709 $ 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 Nine Months Ended
September 30, September 30,
------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------- ------------
Revenues and other income
Oil, natural gas and related product sales
Unrelated parties $ 82,502 $ 78,333 $ 269,482 $ 261,219
Related party - Genesis 20,566 10,463 62,893 34,053
CO2 sales and transportation fees
Unrelated parties 307 2,238 910 6,872
Related party - Genesis 1,374 - 3,712 -
Loss on settlements of derivative contracts (22,243) (12,031) (54,750) (53,072)
Interest income and other 701 412 1,450 963
------------ ------------ ------------- ------------
Total revenues and other income 83,207 79,415 283,697 250,035
------------ ------------ ------------- ------------
Expenses
Lease operating expenses 19,781 22,400 66,839 67,850
Production taxes and marketing expenses 4,634 3,761 13,215 11,124
Transportation expense - Genesis 266 - 266 -
CO2 operating expenses 255 602 608 1,453
General and administrative expenses 6,197 3,445 15,123 10,612
Interest 4,768 5,358 14,917 18,046
Loss on early retirement of debt - - - 17,629
Depletion, depreciation and amortization 20,780 22,566 76,265 69,249
Non-cash hedging adjustments 383 (1,441) 8,347 (3,702)
------------ ------------ ------------- ------------
Total expenses 57,064 56,691 195,580 192,261
------------ ------------ ------------- ------------
Equity in net income (loss) of Genesis (37) (25) (28) 26
------------ ------------ ------------- ------------
Income before income taxes 26,106 22,699 88,089 57,800
Income tax provision (benefit)
Current income taxes 18,949 (1,514) 22,045 123
Deferred income taxes (11,117) 9,064 6,077 18,946
------------ ------------ ------------- ------------
Income before cumulative effect of change in accounting principle 18,274 15,149 59,967 38,731
Cumulative effect of change in accounting principle, net of income
taxes of $1,600 - - - 2,612
------------ ------------ ------------- ------------
Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343
============ ============ ============= ============
Net income per common share - basic
Income before cumulative effect of change in accounting principle $ 0.33 $ 0.28 $ 1.10 $ 0.72
Cumulative effect of change in accounting principle - - - 0.05
------------ ------------ ------------- ------------
Net income per common share - basic $ 0.33 $ 0.28 $ 1.10 $ 0.77
============ ============ ============= ============
Net income per common share - diluted
Income before cumulative effect of change in accounting principle $ 0.32 $ 0.27 $ 1.05 $ 0.70
Cumulative effect of change in accounting principle - - - 0.05
------------ ------------ ------------- ------------
Net income per common share - diluted $ 0.32 $ 0.27 $ 1.05 $ 0.75
============ ============ ============= ============
Weighted average common shares outstanding
Basic 55,085 54,014 54,740 53,824
Diluted 57,549 55,718 57,020 55,375
(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 Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------- ------------ ------------
Cash flow from operating activities:
Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 20,780 22,566 76,265 69,249
Non-cash hedging adjustments 383 (1,441) 8,347 (3,702)
Deferred income taxes (11,117) 9,064 6,077 18,946
Deferred revenue - Genesis (648) - (1,758) -
Deferred compensation - restricted stock 593 - 593 -
Loss on early retirement of debt - - - 17,629
Amortization of debt issue costs and other 1,482 273 2,230 1,113
Cumulative effect of change in accounting principle - - - (2,612)
Changes in assets and liabilities:
Accrued production receivable (412) 3,891 (11,248) 1,518
Trade and other receivables 5,635 3,322 3,862 178
Derivative assets and liabilities - - (7,518) -
Other assets (32) 1 (32) 6
Accounts payable and accrued liabilities 15,552 (995) 16,263 1,219
Oil and gas production payable (4,280) (1,540) 748 2,199
Other liabilities (1,444) (501) (2,825) (1,246)
------------ ------------- ------------ ------------
Net cash provided by operations 44,766 49,789 150,971 145,840
------------ ------------- ------------ ------------
Cash flow provided by investing activities:
Oil and natural gas expenditures (35,981) (37,397) (125,745) (108,106)
Acquisitions of oil and gas properties (1,663) (1,854) (3,861) (11,478)
Acquisitions of CO2 assets and capital expenditures (15,825) (2,635) (42,966) (16,008)
Net proceeds from CO2 production payment - Genesis 4,636 - 4,636 -
Sale of Denbury Offshore, Inc. 186,753 - 186,753 -
Proceeds from oil and gas property sales 380 1,174 1,526 29,328
Increase in restricted cash (119) (211) (470) (567)
Purchases of short-term investments (31,957) - (31,957) -
Net (purchases) sales of other assets (1,753) 5,428 (2,907) (1,545)
------------ ------------- ------------ ------------
Net cash provided by (used for) investing activities 104,471 (35,495) (14,991) (108,376)
------------ ------------- ------------ ------------
Cash flow from financing activities:
Bank repayments (85,000) (6,000) (88,000) (131,000)
Bank borrowings - - 13,000 85,000
Repayment of subordinated debt obligations, including redemption premium - - - (209,000)
Issuance of subordinated debt, net of discount - - - 223,054
Issuance of common stock 2,425 1,138 11,099 4,108
Purchase of treasury stock (1,052) (641) (2,713) (641)
Costs of debt financing (408) (31) (412) (4,817)
------------ ------------- ------------ ------------
Net cash used by financing activities (84,035) (5,534) (67,026) (33,296)
------------ ------------- ------------ ------------
Net increase in cash and cash equivalents 65,202 8,760 68,954 4,168
Cash and cash equivalents at beginning of period 27,940 19,348 24,188 23,940
------------ ------------- ------------ ------------
Cash and cash equivalents at end of period $ 93,142 $ 28,108 $ 93,142 $ 28,108
============ ============= ============ ============
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 176 $ 835 $ 9,639 $ 14,206
Cash paid during the period for income taxes 13,000 - 13,327 184
(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 Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2004 2003 2004 2003
------------ ------------- ------------ -------------
Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts, net of tax of
$(8,916), $4,020, $(21,586), and $(20,318), respectively (14,547) 6,559 (35,220) (33,151)
Reclassification adjustments related to settlements of derivative contracts,
net of tax of $9,704, $4,167, $25,474 and $18,956, respectively 15,833 6,798 41,563 30,927
Unrealized loss on securities available-for-sale (9) - (9) -
------------ ------------- ------------ -------------
Comprehensive income $ 19,551 $ 28,506 $ 66,301 $ 39,119
============ ============= ============ =============
(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 September 30, 2004 and the consolidated
results of its operations and cash flows for the three and nine month periods
ended September 30, 2004 and 2003. Certain prior period items have been
reclassified to make the classification consistent with the classification in
the most recent quarter.
Short-term Investments
The Company invests in highly liquid debt securities with strong credit
ratings. Debt securities with a maturity greater than three months, but less
than one year, at the time of purchase are considered to be short-term
investments. The Company classifies its short-term investments in debt
securities as available-for-sale in accordance with the provisions of Statement
of Financial Accounting Standards No. 115, "Accounting for Certain Investments
in Debt and Equity Securities." These debt securities are carried at fair market
value, with unrealized gains and losses reported in stockholders' equity as a
component of Accumulated Other Comprehensive Income (Loss).
Non-Expense 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 No. 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.
7
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Net income: (thousands)
Net income, as reported............................................ $ 18,274 $ 15,149 $ 59,967 $ 41,343
Add: stock-based compensation expense included in reported
net income, net of related tax effects........................... 368 - 368 -
Less: stock-based compensation expense applying fair value
based method, net of related tax effects ........................ 1,764 1,005 5,236 2,638
------------ ------------ ------------ ------------
Pro-forma net income .............................................. $ 16,878 $ 14,144 $ 55,099 $ 38,705
============ ============ ============ ============
Net income per common share
As reported:
Basic ........................................................... $ 0.33 $ 0.28 $ 1.10 $ 0.77
Diluted.......................................................... 0.32 0.27 1.05 0.75
Pro forma:
Basic ........................................................... $ 0.31 $ 0.26 $ 1.01 $ 0.72
Diluted ......................................................... 0.30 0.26 0.97 0.71
Recently Issued Accounting Standards
In September 2004, the Financial Accounting Standards Board ("FASB") issued
a 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 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 FASB staff position has no impact on the classification of
Denbury's oil and gas property balances.
In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB
106), which clarifies the calculation of the full cost ceiling and depreciation,
depletion, and amortization ("DD&A") of oil and gas properties in conjunction
with accounting for asset retirement obligations ("ARO") under SFAS No. 143. SAB
106 does not change our accounting for our full cost ceiling test or our
calculation of DD&A for our oil and gas properties, as we are in compliance with
the SEC views expressed in SAB 106.
In July 2004, the Emerging Issues Task Force of the FASB issued EITF 04-05,
"Investor's Accounting for an Investment in a Limited Partnership When the
Investor is the Sole General Partner and the Limited Partners Have Certain
Rights." In question is what rights held by the limited partners preclude
consolidation of the limited partnership by the sole general partner. The Task
Force noted that in practice differing views have evolved concerning this issue
and it has asked the FASB staff to develop this issue for discussion at a future
date. Denbury is the general partner of Genesis Energy, L.P. ("Genesis") and
currently does not consolidate Genesis in its financial results based primarily
on certain rights of the limited partners. Depending on the outcome of the
discussions of the Task Force in future meetings, the outcome could impact
whether or not Denbury consolidates Genesis. See Note 9, "Related Party
Transactions - Genesis" for further information regarding Denbury's accounting
for its investment in Genesis.
2. 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)
to Newfield Exploration Company. The sale price was based on the asset value of
the offshore assets as of April 1, 2004, which means that the net operating cash
flow (defined as revenue less operating expenses and capital expenditures) from
these properties which we received between April 1st and closing, as well as
expenses of the sale and other contractual adjustments, reduced the purchase
price to approximately $187 million. At September 30, 2004, we owed Newfield
approximately $16.0 million that primarily consisted of accrued production
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
receivables from our offshore assets on July 20, 2004 (the closing date) that we
collected on their behalf. The money was paid to Newfield during October 2004.
We may have minor adjustments to the sale price in the fourth quarter of 2004
related to final settlement of the interim period net operating cash flow and
other contractual arrangements in the sale agreement.
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.
If not sold beforehand, the well at High Island A-6 should be on production late
this year, and we sold a substantial portion of the deep rights at West Delta 27
for $1.8 million but retained a carried interest in a deep exploratory well.
Our third quarter results include production, revenue, operating expenses,
and capital expenditures of the offshore properties for the first 19 days of
July preceding their sale on July 20th. Production for these 19 days totaled
1,885 BOE/d, which generated approximately $5.3 million of net operating revenue
(revenue less operating expenses). We also recorded approximately $18 million of
current income taxes relating to the sale and paid approximately $1.4 million of
employee severance costs during the third quarter (in addition to the $1.0
million of severance recorded and paid during the first half of the year). We
used $85 million of the sales proceeds to retire our bank debt, leaving
approximately $70 million of cash remaining from the sale after payment of
expenses related to the transaction.
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).
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 nine months ended September 30, 2004.
Nine Months Ended
September 30, 2004
---------------------
(in thousands)
Beginning asset retirement obligation, as of 12/31/2003....... $ 43,812
Liabilities incurred during period............................ 1,548
Liabilities settled during period............................. (1,926)
Liabilities sold during the period............................ (25,338)
Accretion expense............................................. 1,971
---------------------
Ending asset retirement obligation, as of 9/30/2004........... $ 20,067
=====================
9
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Liabilities sold during the period represent the asset retirement
obligation associated with our offshore assets held by Denbury Offshore, Inc.,
which was sold in July 2004. At September 30, 2004, $3.4 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 $6.3 million at September 30, 2004, and $9.5 million
at December 31, 2003 and are included in "Other assets" in our Unaudited
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, unvested restricted stock, and any other convertible
securities outstanding. For the three and nine month periods ended September 30,
2004 and 2003, there were no adjustments to net income for purposes of
calculating diluted net income per common share.
The following is a reconciliation of the weighted average common shares
used in the basic and diluted net income per common share calculations for the
three and nine month periods ended September 30, 2004 and 2003 (shares in
thousands).
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- --------------------------
2004 2003 2004 2003
---------------- -------------- ------------- ------------
Weighted average common shares - basic....... 55,085 54,014 54,740 53,824
Potentially dilutive securities:
Stock options.............................. 2,434 1,704 2,280 1,551
Restricted stock........................... 30 - - -
---------------- -------------- ------------- ------------
Weighted average common shares - diluted..... 57,549 55,718 57,020 55,375
================ ============== ============= ============
For purposes of calculating basic net income per share common share, the
1,140,000 shares of non-vested restricted stock outstanding at September 30,
2004, are excluded from the calculation. As these shares vest, they will be
included in the basic net income per common share calculation. However, the
non-vested restricted stock is included in the computation of diluted net income
per common share using the treasury stock method. In applying the treasury stock
method, there is no exercise price to be paid, however, proceeds are equal to
the average unrecognized compensation during the period adjusted for any
estimated future tax consequences that will be recognized directly in equity.
The shares are weighted appropriately for the period they are outstanding. These
shares of restricted stock were issued in August and September 2004, and as a
result they do not have a significant impact on the current period. These shares
may result in greater dilution in future periods, depending on the market price
of our common stock during those periods.
For the three months ended September 30, 2004 and 2003, stock options to
purchase approximately 32,000 and 1.0 million shares of common stock, and for
the nine months ended September 30, 2004 and 2003, stock options to purchase
approximately 63,000 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.
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5. RESTRICTED STOCK
During the third quarter of 2004, the Compensation Committee of the Board
of Directors awarded the officers and independent directors of the Company
1,140,000 shares of restricted stock granted under the Company's 2004 Omnibus
Stock and Incentive Plan. The holders of these shares have all of the rights and
privileges of owning the shares (including voting rights) except that the
holders are not entitled to delivery of the certificates until certain
requirements are met. With respect to the 1,100,000 shares of restricted stock
granted to officers of Denbury, the vesting restrictions on those shares are as
follows: i) 65% of the awards vest 20% per year over five years and, ii) 35% of
the awards vest upon retirement. With respect to the 65% of the awards that vest
over five years, on each annual vesting date, 66-2/3% of the vested shares may
be delivered to the holder with the remaining 33-1/3% retained and held in
escrow until the holder's separation from the Company. With respect to the
40,000 restricted shares issued to Denbury's independent board members, the
shares vest 20% per year over five years. For these shares, on each annual
vesting date, 40% of such vested shares may be delivered to the holder with the
remaining 60% retained and held in escrow until the holder's separation from the
Company. All restricted shares vest upon death, disability or a change in
control.
Upon issuance of the 1,140,000 shares of restricted stock pursuant to the
2004 Omnibus Stock and Incentive Plan, deferred compensation expense of $23.0
million, the market value of the shares on the date of grant, was recorded as a
reduction to shareholders' equity. This expense will be amortized over the
applicable five year or retirement date vesting periods. The compensation
expense recorded with respect to the restricted shares during the three months
ended September 30, 2004, was $593,000.
6. 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 September 30, 2004, we purchased 150,000 shares
at an average cost of $18.09 per share. Through September 30, 2004, we have
reissued 185,221 (74%) of these shares under Denbury's Employee Stock Purchase
Plan.
7. INDEBTEDNESS
September 30, December 31,
2004 2003
------------------ -----------------
(in thousands)
7.5% Senior Subordinated Notes due 2013.......... $ 225,000 $ 225,000
Discount on Senior Subordinated Notes............ (1,652) (1,797)
Senior bank loan................................. - 75,000
------------------ -----------------
Total debt................................... $ 223,348 $ 298,203
================== =================
On September 1, 2004, we entered into a new bank credit agreement which
modified the prior agreement by (i) creating a structure wherein the commitment
amount and borrowing base amount are no longer the same, (ii) improving our
credit pricing by reducing the interest rate chargeable at certain levels of
borrowing, (iii) extending the term by three years to April 30, 2009, (iv)
reducing the collateral requirements, (v) authorizing up to $20 million of
possible future CO2 volumetric production payment transactions with Genesis
Energy, and (vi) other minor modifications and corrections. Under the new
agreement, our borrowing base was initially set at $200 million, a $25 million
increase over the prior borrowing base of $175 million, with an initial
commitment amount of $100 million. The borrowing base represents the amount we
11
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
can borrow from a credit standpoint based on our assets, as confirmed by the
banks, while the commitment amount is the amount we asked the banks to commit to
fund pursuant to the terms of the credit agreement. The banks have the option to
participate in any borrowing request made by us in excess of the commitment
amount, up to the borrowing base limit, although they are not obligated to fund
any amount in excess of $100 million, the commitment amount. The advantage to us
is that we will pay commitment fees on the commitment amount, not the borrowing
base, thus lowering our overall cost of available credit.
8. SHORT-TERM INVESTMENTS
The following is a summary of current available-for-sale marketable
securities at September 30, 2004 (in thousands):
September 30, 2004
----------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
----------------------------------------------------------
Certificate of deposits............................ $ 2,000 $ - $ - $ 2,000
Government and agency obligations.................. 14,939 - 17 14,922
Other debt securities.............................. 15,030 22 19 15,033
----------------------------------------------------------
Total current available-for-sale securities... $31,969 $ 22 $ 36 $31,955
==========================================================
9. RELATED PARTY TRANSACTIONS - GENESIS
Interest in and Transactions with Genesis
Denbury is the general partner of and owns an aggregate 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 (loss) for the three months ended September 30, 2004 and 2003 was
$(37,000) and $(25,000), respectively, and for the nine months ended September
30, 2004 and 2003 was $(28,000) and $26,000, respectively. Genesis Energy, Inc.,
the general partner of which we own 100%, has guaranteed the bank debt of
Genesis, which was $15 million as of September 30, 2004, plus $15.3 million in
letters of credit. There are no guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
Over the past several years and even prior to our investment in Genesis we
sold certain of our oil production to Genesis. Beginning in September 2004, we
discontinued most direct sales of our oil production to Genesis and instead, we
utilize their common carrier pipeline to transport certain of our Mississippi
oil production to an ultimate sales point where it is sold to a third party
purchaser. In return, we pay Genesis a transportation fee for the use of their
pipeline and trucking services. For the three and nine months ended September
30, 2004, we expensed $266,000 under this transportation agreement. At December
31, 2003, we had a receivable from Genesis of $6.9 million and $0.5 million at
September 30, 2004. At September 30, 2004, we had an accounts payable to Genesis
of $402,000 for transportation expenses and interim cash flows for the
volumetric production payment that closed in August 2004. We recorded oil sales
to Genesis of $20.6 million and $10.5 million for the three months ended
September 30, 2004 and 2003, respectively, and $62.9 million and $34.1 million
for the nine months ended September 30, 2004 and 2003, respectively. Denbury
received other miscellaneous payments from Genesis during the 2004 period,
including $90,000 in director fees for certain executive officers of Denbury
that are board members of Genesis, and $373,000 in pro rata distributions from
Genesis.
12
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
CO2 Volumetric Production Payments
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.
On August 26, 2004, we closed on another transaction with Genesis, selling
them a 33.0 Bcf volumetric production payment ("VPPII") of CO2 for $4.8 million
($4.6 million as adjusted for interim cash flows from the July 1 effective date
and for transaction costs) along with a related long-term supply agreement with
an industrial customer. Pursuant to the VPPII, Genesis may take up to 9 MMcf/d
of CO2 to the end of the contract term. We have recorded the net proceeds of
these volumetric production payment sales as deferred revenue and will recognize
such revenue as CO2 is delivered during the term of the VPP and VPPII. At
September 30, 2004, $26.5 million was recorded as deferred revenue ($2.5 million
in current liabilities and $24.0 million long term). During the three and nine
months ended September 30, 2004, we recognized deferred revenue of $0.7 million
and $1.8 million, respectively, for deliveries under the VPP and VPPII. We
provide Genesis with certain processing and transportation services in
connection with these agreements for a fee of $0.16 per Mcf of CO2 delivered to
their industrial customers, which resulted in $0.7 million and $1.9 million in
revenue to Denbury for the three and nine months ended September 30, 2004,
respectively.
Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
Three Months Ended September 30, Nine Months Ended September 30,
--------------------------------------- -------------------------------------
2004 2003 2004 2003
----------------- -------------------- ----------------- -------------------
Revenues.................................. $ 250,736 $ 157,094 $ 681,755 $ 479,446
Cost of sales............................. 250,892 158,503 681,035 479,024
Other income (expenses)................... (238) 196 (1,020) 1,134
----------------- -------------------- ----------------- -------------------
Net income (loss) ........................ $ (394) $ (1,213) $ (300) $ 1,556
================= ==================== ================= ===================
September 30, December 31,
2004 2003
----------------- --------------------
Current assets............................ $ 82,225 $ 88,211
Non-current assets........................ 65,000 58,904
----------------- --------------------
Total assets ............................. $ 147,225 $ 147,115
================= ====================
Current liabilities ...................... $ 83,932 $ 87,244
Non-current liabilities................... 15,000 7,000
Partners' capital......................... 48,293 52,871
----------------- --------------------
Total liabilities and partners' capital... $ 147,225 $ 147,115
================= ====================
10. 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
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
The following is a summary of the net loss on our commodity hedge
settlements which are recorded in "Revenues and other income" in our Condensed
Consolidated Statements of Operations (amounts in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2004 2003 2004 2003
--------------- ------------- ------------ -------------
Oil hedge contracts................................. $ (13,455) $ (4,009) $ (33,771) $ (15,380)
Gas hedge contracts................................. (4,010) (8,022) (12,686) (37,692)
Contracts not qualifying for hedge accounting....... (4,778) - (8,293) -
--------------- ------------- ------------ -------------
Net loss........................................ $ (22,243) $ (12,031) $ (54,750) $ (53,072)
=============== ============= ============ =============
The following is a summary of "Non-cash hedging adjustments," included in
our Condensed Consolidated Statements of Operations (amounts in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2004 2003 2004 2003
----------- ---------- ----------- ----------
Hedge ineffectiveness (income) expense on contracts qualifying
for hedge accounting...............................................$ (1,551) $ (375) $ (1,518) $ (513)
Amortization of contract premiums..................................... - 300 - 891
Reclassification of accumulated other comprehensive income
balance and adjustments to fair value associated with termination
of contracts designated to offshore production..................... 1,206 - 9,318 -
Adjustments to fair value and amortization of ineffective hedge
no longer qualifying for hedge accounting.......................... 1,747 - 3,096 -
Adjustments to fair value associated with contracts
transferred in sale of offshore production......................... (1,019) - (2,549) -
Amortization of terminated Enron-related hedges over the original
contract periods................................................... - (1,366) - (4,080)
----------- ---------- ----------- ----------
$ 383 $ (1,441) $ 8,347 $ (3,702)
=========== ========== =========== ==========
Upon reaching a verbal agreement on our 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 during the third quarter of 2004 we
assigned them to the purchaser of the offshore properties. The mark to market
adjustment on these contracts from the time of purchase through the date they
were assigned to the purchaser totaled approximately $2.5 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
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 effective during the third quarter of 2004, resulting in a
net charge of $0.4 million for the quarter and $8.3 million for the nine months
ended September 30, 2004.
During 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 $1.4 for the three months and $3.7 million for the nine
months ended September 30, 2003.
Derivative Contracts designated as a hedge of forecasted production at September
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 September 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- --------------------
(in thousands)
Swap Contracts
Oct. 2004 - Dec. 2004 4,500 $ 23.00 $ - $ - $ - $ (10,716)
Oct. 2004 - Dec. 2004 2,500 22.89 - - - (5,978)
Floor Contract
Jan. 2005 - Dec. 2005 7,500 - 27.50 - - 251
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 September 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- --------------------
Collar Contracts (in thousands)
Oct. 2004 - Dec. 2004 30,000 $ - $ - $ 3.50 $ 4.45 $ (6,001)
Oct. 2004 - Dec. 2004 10,000 - - 3.00 5.82 (900)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (8,480)
15
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 September 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- ---------------------
(in thousands)
Swap Contract
Oct. 2004 - Dec. 2004 2,500 $ 23.08 $ - $ - $ - $ (5,935)
Natural Gas Contracts:
- ---------------------
NYMEX Contract Prices Per MMBtu
-------------------------------
Offsetting Contracts
Collar Prices
---------------------- Fair Value at
Period MMBtu/d Call Price Put Price Floor Ceiling September 30, 2004
- -------------------------------- ----------- ------------ ------------ ---------- ----------- ---------------------
(in thousands)
Oct. 2004 - Dec. 2004 15,000 $ - $ - $ 3.00 $ 5.87 $ (1,315)
Oct. 2004 - Dec. 2004 15,000 5.87 - - - 1,315
Oct. 2004 - Dec. 2004 5,000 - - 3.00 5.82 (450)
Oct. 2004 - Dec. 2004 5,000 5.82 3.00 - - 450
At September 30, 2004, our derivative contracts were recorded at their fair
value, which was a net liability of $37.8 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 $20.8 million at September 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 $20.8 million in accumulated
other comprehensive loss as of September 30, 2004, $18.2 million relates to
current hedging contracts that will expire within the next 12 months.
11. UNAUDITED 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:
16
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Condensed Consolidating Balance Sheets
September 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.................................... $ 1 $ 194,312 $ 16,117 $ (967) $ 209,463
Property and equipment ........................... - 763,153 3,897 (3,114) 763,936
Investment in subsidiaries (equity method)........ 500,629 - 480,615 (974,210) 7,034
Other assets...................................... - 11,276 - - 11,276
-------------- --------------- ------------- -------------- ---------------
Total assets ................................. $ 500,630 $ 968,741 $ 500,629 $ (978,291) $ 991,709
============== =============== ============= ============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities............................... $ - $ 141,752 $ - $ (967) $ 140,785
Long-term liabilities ............................ - 353,408 - (3,114) 350,294
Stockholders' equity ............................. 500,630 473,581 500,629 (974,210) 500,630
-------------- --------------- ---------------------------- ---------------
Total liabilities and stockholders' equity.... $ 500,630 $ 968,741 $ 500,629 $ (978,291) $ 991,709
============== =============== ============= ============== ===============
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
============== =============== ============= ============== ===============
17
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2004
---------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consoldiated
-------------- ---------------- ------------ -------------- ---------------
Amounts in thousands
Revenues.................................. $ - $ 77,199 $ 6,008 $ - $ 83,207
Expenses ................................. 42 51,873 5,149 - 57,064
-------------- ---------------- ------------ -------------- ---------------
Income (loss) before the following: (42) 25,326 859 - 26,143
Equity in net earnings of subsidiaries ... 18,299 - 20,625 (38,961) (37)
-------------- ---------------- ------------ -------------- ---------------
Income before income taxes................ 18,257 25,326 21,484 (38,961) 26,106
Income tax provision (benefit)............ (17) 4,664 3,185 - 7,832
-------------- ---------------- ------------ -------------- ---------------
Net income ............................... $ 18,274 $ 20,662 $ 18,299 $ (38,961) $ 18,274
============== ================ ============ ============== ===============
Three Months Ended September 30, 2003
-----------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------ -------------- ---------------
Amounts in thousands
Revenues................................................ $ 58,045 $ 21,370 $ - $ 79,415
Expenses................................................ 42,803 13,888 - 56,691
--------------- ------------ -------------- ---------------
Income before the following: 15,242 7,482 - 22,724
Equity in net earnings (loss) of subsidiaries .......... 5,000 (25) (5,000) (25)
--------------- ------------ -------------- ---------------
Income before income taxes.............................. 20,242 7,457 (5,000) 22,699
Income tax provision ................................... 5,093 2,457 - 7,550
--------------- ------------ -------------- ---------------
Net income.............................................. $ 15,149 $ 5,000 $ (5,000) $ 15,149
=============== ============ ============== ===============
18
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Condensed Consolidating Statements of Operations (continued)
Nine Months Ended September 30, 2004
---------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
-------------- ---------------- ------------ -------------- ---------------
Amounts in thousands
Revenues................................. $ - $ 220,211 $ 63,486 $ - $ 283,697
Expenses ................................ 130 157,751 37,699 - 195,580
-------------- ---------------- ------------ -------------- ---------------
Income (loss) before the following: (130) 62,460 25,787 - 88,117
Equity in net earnings of subsidiaries .. 60,051 - 45,743 (105,822) (28)
-------------- ---------------- ------------ -------------- ---------------
Income before income taxes............... 59,921 62,460 71,530 (105,822) 88,089
Income tax provision (benefit)........... (46) 16,689 11,479 - 28,122
-------------- ---------------- ------------ -------------- ---------------
Net income .............................. $ 59,967 $ 45,771 $ 60,051 $ (105,822) $ 59,967
============== ================ ============ ============== ===============
Nine Months Ended September 30, 2003
------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- ------------- ---------------
Amounts in thousands
Revenues................................................. $ 173,895 $ 76,140 $ - $ 250,035
Expenses................................................. 149,706 42,555 - 192,261
--------------- -------------- ------------- ---------------
Income before the following: 24,189 33,585 - 57,774
Equity in net earnings of subsidiaries ................ 21,434 26 (21,434) 26
--------------- -------------- ------------- ---------------
Income before income taxes and
cumulative effect of a change in accounting principle.. 45,623 33,611 (21,434) 57,800
Income tax provision..................................... 8,261 10,808 - 19,069
--------------- -------------- ------------- ---------------
Net income before cumulative effect of a change in
accounting principle................................... 37,362 22,803 (21,434) 38,731
Cumulative effect of a change in accounting principle,
net of income taxes.................................... 3,981 (1,369) - 2,612
--------------- -------------- ------------- ---------------
Net income............................................... $ 41,343 $ 21,434 $ (21,434) $ 41,343
=============== ============== ============= ===============
19
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 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................. $ (8,386) $ 317,322 $ (157,965) $ - $ 150,971
Cash flow from investing activities....... - (172,986) 157,995 - (14,991)
Cash flow from financing activities....... 8,386 (75,412) - - (67,026)
---------------- --------------- ------------- -------------- --------------
Net increase in cash...................... - 68,924 30 - 68,954
Cash, beginning of period................. 1 24,174 13 - 24,188
---------------- --------------- ------------- -------------- --------------
Cash, end of period....................... $ 1 $ 93,098 $ 43 $ - $ 93,142
================ =============== ============= ============== ==============
Nine Months Ended September 30, 2003
-----------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------- -------------- --------------
Amounts in thousands
Cash flow from operations..................... $ 103,242 $ 42,598 $ - $ 145,840
Cash flow from investing activities........... (75,379) (32,997) - (108,376)
Cash flow from financing activities........... (33,296) - - (33,296)
--------------- ------------- -------------- --------------
Net increase (decrease) in cash .............. (5,433) 9,601 - 4,168
Cash, beginning of period..................... 20,281 3,659 - 23,940
--------------- ------------- -------------- --------------
Cash, end of period........................... $ 14,848 $ 13,260 $ - $ 28,108
=============== ============= ============== ==============
12. LITIGATION
We, along with two other companies have been named in a lawsuit entitled
"J. Paulin Duhe, Inc. vs. Texaco, Inc., et al," Cause No. 101,227, filed within
the last year in the 16th Judicial District Court, Division "E", Terrebonne
Parish, Louisiana, seeking unspecified monetary amounts for alleged surface and
groundwater contamination affecting, and asking for restoration of, the lands
that are part of our Iberia Field in Iberia Parish, Louisiana. The first oil and
natural gas well was drilled on this property in 1921. We acquired this property
approximately four years ago and have an indemnification from the prior owner,
which we anticipate will cover us from most environmental damages that occurred
prior to the time that we purchased the property. We have not yet been able to
determine our potential exposure in this case. We plan to vigorously defend this
lawsuit, as well as seek indemnification from the prior owners if necessary.
20
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 and in the
Barnett Shale play in Texas. 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
EXPANSION OF OUR 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 known
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.
In late August 2004, we announced that we had commenced the acquisition of
leases and right-of-way for the construction of an 84-mile pipeline to transport
CO2 from our CO2 source fields located near Jackson, Mississippi to planned
tertiary recovery operations in East Mississippi, initially terminating at
Eucutta Field. We are still reviewing financing options for the pipeline,
expected to cost approximately $45 million, but plan to pay for this line over
time through either long-term project financing, payment of a throughput
transportation charge or a long-term lease. We anticipate that the pipeline will
be ready for use during the first half of 2006. We also announced the completion
of our fourth CO2 well drilled during 2004, confirming the addition of an
estimated 300 Bcf of proved CO2 reserves, resulting in an estimated total
increase in proved CO2 reserves during 2004 of approximately 1.0 Tcf. This
increase in CO2 reserves is sufficient to satisfy the projected CO2 requirements
of our initially planned tertiary recovery operations in Eastern Mississippi
(what we have labeled as "Phase II" of our tertiary recovery operations). Phase
II will initially consist of tertiary recovery operations at six oil fields in
that region, but we ultimately plan to expand these operations to several other
oil fields in the area, which also would be serviced by the new pipeline.
In conjunction with these plans, we have updated our development schedule
and targeted oil production from tertiary recovery operations. Our revised model
projects a 28% compounded increase in our tertiary recovery oil production
between 2003 and 2010, increasing from 4,670 BOE/d in 2003 to a projected 34,000
BOE/d in 2011. The model assumes that the first production from tertiary
recovery operations in Eastern Mississippi will occur in 2007. During 2004, oil
production from our tertiary recovery operations has averaged 6,318 BOE/d, 6,603
BOE/d, and 6,967 BOE/d during the first, second and third quarters respectively,
and is expected to increase similarly in the fourth quarter.
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) to Newfield Exploration Company. The sale price was
based on the asset value of the offshore assets as of April 1, 2004, which means
that the net operating cash flow (defined as revenue less operating expenses and
capital expenditures) from these properties which we received between April 1st
and closing, as well as expenses of the sale and other contractual adjustments,
reduced the purchase price to approximately $187 million. At September 30, 2004,
we owed Newfield approximately $16.0 million that primarily consisted of Denbury
Offshore accrued production receivables on July 20, 2004 (closing date) that we
collected on their behalf. This amount was reflected as a payable to Newfield in
the Unaudited Condensed Consolidated Balance Sheet and was paid to Newfield in
October 2004.
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
If not sold beforehand, the well at High Island A-6 should be on production late
this year, and we sold a substantial portion of the deep rights at West Delta 27
for $1.8 million but retained a carried interest in a deep exploratory well.
Our third quarter results include production, revenues, operating expenses,
and capital expenditures of the offshore properties for the first 19 days of
July preceding their sale. Production for these 19 days totaled 1,885 BOE/d
which generated approximately $5.3 million of net operating revenue (revenue
less operating expenses). We also recorded approximately $18 million of current
income taxes relating to the sale and paid approximately $1.4 million of
employee severance costs during the third quarter (in addition to the $1.0
million of severance recorded and paid during the first half of the year). We
used $85 million of the sales proceeds to retire our bank debt, leaving
approximately $70 million of cash remaining from the sale after payment of
expenses related to the transaction. We increased our 2004 exploration and
development budget by $28 million to $213 million as a result of the additional
cash generated from the sale and 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% (9,114 BOE/d) of our 2004 second quarter production.
OPERATING RESULTS. As a result of the sale of our offshore properties early
in the third quarter of 2004, our total production during this quarter was
significantly reduced, contributing to a 6% decline in net income when compared
to 2004's second quarter production. Cash flow from operations for the quarter
declined even more significantly (53%), primarily due to the $18 million of
current income taxes due on the sale. On a pro forma basis, excluding the impact
of the offshore operations during the third quarter as outlined above, net
income would have been approximately $16.5 million, with a pro forma adjusted
cash flow from operations (non-GAAP measure, see "Results of Operations -
Operating Results" below) of approximately $44.0 million. In summary, the effect
of higher commodity prices was more than offset by the loss of offshore
production and related net operating income from those operations. Payments on
our commodity hedges continued to be a significant outflow, totaling $22.2
million for the third quarter of 2004, and hedge payments are expected to be
even higher in the fourth quarter of 2004 based on current commodity prices,
after which they will drop significantly as most of the out-of-the-money hedges
expire by the end of 2004. Depreciation and amortization expense declined in the
third quarter of 2004 as compared to the second quarter of 2004, primarily as a
result of the proceeds from the offshore sale being credited to the full cost
pool. When comparing the respective third quarters of 2003 and 2004, higher
commodity prices in the 2004 period more than offset the lower production,
resulting in a 21% increase in net income in 2004. See "Results of Operations"
for a more thorough discussion of our operating results.
Capital Resources and Liquidity
During the first nine months of 2004, we spent $125.8 million on oil and
natural gas exploration and development expenditures, $35.2 million on CO2
exploration and development expenditures, and approximately $11.6 million on
property acquisitions (principally CO2 producing assets), for total capital
expenditures of approximately $172.6 million. We funded these expenditures with
$151.0 million of cash flow from operations, with the balance funded with net
proceeds from the offshore sale. We also paid back all of our bank debt during
the period with the offshore sale proceeds, leaving us with approximately $93.1
million of cash and $32.0 million of short-term investments as of September 30,
2004, although $16.0 million of this cash was refunded to Newfield in October
2004 (see "Sale of Offshore Operations" above). During the third quarter of
2004, we closed on another transaction with Genesis Energy, L.P. ("Genesis"),
selling to them a 33.0 Bcf volumetric production payment of CO2 for $4.8 million
along with a related long-term CO2 supply agreement with an industrial customer,
further increasing our cash position. Adjusted cash flow from operations (a
non-GAAP measure defined as cash flow from operations before changes in assets
and liabilities as discussed below under "Results of Operations-Operating
Results") was $151.7 million for the first nine months of 2004.
At September 30, 2004, we had outstanding $225 million (principal amount)
of 7.5% subordinated notes due in 2013, no bank debt, and net working capital on
hand of $68.7 million. On September 1, 2004, we entered into a new bank credit
agreement which modified the prior agreement by (i) creating a structure wherein
the commitment amount and borrowing base amount are no longer the same, (ii)
improving our credit pricing by reducing the interest rate chargeable at certain
levels of borrowing, (iii) extending the term by three years to April 30, 2009,
(iv) reducing the collateral requirements, (v) authorizing up to $20 million of
possible future CO2 volumetric production payment transactions with Genesis
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energy, and (vi) other minor modifications and corrections. Under the new
agreement, our borrowing base was initially set at $200 million, a $25 million
increase over the prior borrowing base of $175 million, with an initial
commitment amount of $100 million. The borrowing base represents the amount we
can borrow from a credit standpoint based on our assets, as confirmed by the
banks, while the commitment amount is the amount we asked the banks to commit to
fund pursuant to the terms of the credit agreement. The banks have the option to
participate in any borrowing request made by us in excess of the commitment
amount, up to the borrowing base limit, although they are not obligated to fund
any amount in excess of $100 million, the commitment amount. The advantage to us
is that we will pay commitment fees on the commitment amount, not the borrowing
base, thus lowering our overall cost of available credit.
Even with our recently increased capital budget for 2004, we do not expect
to spend any significant amount of our cash on hand for our budgeted operations
given high commodity prices. For 2005, we have set a preliminary capital budget
of $260 million, which at current commodity prices will be $50 to $60 million
less than anticipated cash flow from operations. This 2005 capital budget
excludes the $45 million estimated cost of the CO2 pipeline being constructed to
East Mississippi for which we plan to obtain some sort of long-term financing,
effectively paying for the cost of this pipeline over time (see "Expansion of
our tertiary operations" under "Overview" above). We plan to invest our
remaining cash generated from the offshore sale and any cash potentially
generated from operations in excess of our capital budget (such amount being
highly dependent on commodity prices) over the next one to two years on property
acquisitions, particularly those that have future tertiary potential. Although
we now control most of the fields along our existing CO2 pipeline, there are
several fields in East Mississippi that could be acquired to expand our planned
tertiary operations there, plus we are continuing to seek additional interests
in the fields that we currently own. Further, we would like to add additional
phases or areas of tertiary operations by acquiring other old oil fields in
other parts of our region of operations, building a CO2 pipeline to those areas
and initiating additional tertiary floods. We accelerated the pace and
expenditures on our tertiary operations following the offshore sale, and plan to
continue to do so to the extent that it is economic and practical. We also may
seek conventional development and exploration projects in our areas of
operations.
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. Further, one of our subsidiaries,
the general partner of Genesis Energy, L.P., has guaranteed the bank debt of
Genesis (which as of September 30, 2004, consisted of $15 million of debt and
$15.3 million in letters of credit), and we have delivery obligations to deliver
CO2 to our industrial customers. Our hedging obligations are discussed in Note
11 to the Unaudited Condensed Consolidated Financial Statements. In addition, in
order to recover our undeveloped proved reserves, we must also fund the
associated future development costs forecasted in our proved reserve reports. As
a result of the sale of our offshore properties (see "Sale of offshore
operations" under "Overview"), we repaid all of our bank debt and reduced our
future development costs on our proved reserves by approximately $82.0 million
and our asset retirement obligations by approximately $25.3 million. Most of our
other commitments or contingent obligations have not 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.
Results of Operations
CO2 Operations
Our CO2 operations are becoming an ever-increasing part of our business and
operations, including the recent planned expansion of our operations into East
Mississippi (see "Overview" section above). 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, such as a general delay between expenditures and resultant production,
higher operating costs and improved oil prices. Please refer to Management's
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
During the first three quarters of 2004, we drilled or sidetracked four
additional CO2 wells. During that period, our CO2 production averaged 229.7
MMcf/d, of which 64%, or 147.9 MMcf/d, was used in our tertiary operations, with
the balance sold to our industrial customers or to Genesis pursuant to our
volumetric production payments with Genesis. We believe that with the latest CO2
wells, we are capable of producing approximately 350 MMcf/d of CO2. Based on
preliminary reserve estimates, we estimate that we now have approximately 2.6
Tcf of proven CO2 reserves, a significant increase from our 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. A 3-D seismic shoot over the Jackson Dome area
is currently underway 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 the anticipated growth in our
tertiary operations, a significant focus area for us for the foreseeable future.
Our oil production from our CO2 tertiary recovery activities in the third
quarter of 2004 increased 6% over second quarter 2004 levels and 65% over third
quarter 2003 levels, to an average of 6,967 Bbls/d in the third quarter of 2004,
with most of the increase since the third quarter of 2003 occurring at Mallalieu
and McComb Fields. Production at Mallalieu averaged 3,410 Bbls/d during the
third quarter of 2004, as compared to 3,172 Bbls/d in the prior quarter and
1,388 Bbls/d during the third quarter of 2003. McComb Field averaged 427 Bbls/d
during the third quarter, as compared to 121 Bbls/d in the second quarter of
2004 and effectively zero prior to that. Partially offsetting these increases
was a slight decline during the current quarter at Little Creek Field. We expect
our tertiary oil production to continue to grow through the last quarter of 2004
to a projected average of approximately 6,800 Bbls/d for the year. Late in 2004,
we expect to commence CO2 injections at two new tertiary floods, Brookhaven and
Smithdale Fields, although no incremental oil production is expected from these
fields until late 2005.
We spent approximately $0.12 per Mcf to produce our CO2 during the first
nine months of 2004, less than the 2003 period average of $0.15 per Mcf, as we
did not have any significant workover costs on CO2 wells during the first nine
months 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 nine months of 2004 was approximately $0.21, after inclusion of
depreciation and amortization expense, still significantly less than the $0.39
per thousand cubic feet that we would have 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 nine months of 2004, our operating costs for our tertiary
properties averaged $9.84 per BOE, less than the $11.20 per BOE average in the
first nine months 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) and
higher oil production levels.
Our net operating margin from the sale of CO2 to industrial customers
decreased in the first nine months of 2004 to $4.0 million, down from $5.4
million during the first nine months 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 two Genesis volumetric production payments when
the transactions were consummated in the fourth quarter of 2003 and third
quarter of 2004. Thus, $1.8 million of our industrial sale revenue was non-cash
recognition of deferred revenue.
Operating Results
As summarized in the "Overview" section above, the reduced production
resulting from the sale of our offshore properties and the related income taxes
attributable thereto resulted in lower cash flow from operations and earnings in
the third quarter of 2004 than in the prior quarters of 2004. Earnings and cash
flow were higher in the 2004 periods than in the comparable periods in 2003 as
higher commodity prices more than offset lower production. 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 its impact is
shown below on both a gross and per share basis.
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------------ ---------------------------- ---------------------------
Amounts in thousands, except per share amounts 2004 2003 2004 2003
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Income before cumulative effect of a change in
accounting principle $ 18,274 $ 15,149 $ 59,967 $ 38,731
Cumulative effect of a change in accounting
principle, net of income tax expense of $1,600 - - - 2,612
------------- ------------- ------------- ------------
Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343
- ------------------------------------------------------------------ ============= ============= ============= ============
Net income per common share - basic:
Income before cumulative effect of a change
in accounting principle $ 0.33 $ 0.28 $ 1.10 $ 0.72
Cumulative effect of a change in accounting principle - - - 0.05
------------- ------------- ------------- ------------
Net income per common share - basic $ 0.33 $ 0.28 $ 1.10 $ 0.77
- ------------------------------------------------------------------ ============= ============= ============= ============
Net income per common share - diluted:
Income before cumulative effect of a change
in accounting principle $ 0.32 $ 0.27 $ 1.05 $ 0.70
Cumulative effect of a change in accounting principle - - - 0.05
------------- ------------- ------------- ------------
Net income per common share - diluted $ 0.32 $ 0.27 $ 1.05 $ 0.75
- ------------------------------------------------------------------ ============= ============= ============= ============
Adjusted cash flow from operations (see below) $ 29,747 $ 45,611 $ 151,721 $ 141,966
Net change in assets and liabilities relating to operations 15,019 4,178 (750) 3,874
- ------------------------------------------------------------------ ------------- ------------- ------------- ------------
Cash flow from operations (1) $ 44,766 $ 49,789 $ 150,971 $ 145,840
- ------------------------------------------------------------------ ============= ============= ============= ============
(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 period. 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, during the
third quarter of 2004, we collected accrued production receivables related to
offshore production that existed as of the closing date of the sale of Denbury
Offshore, Inc. that were for the benefit of Newfield Exploration Company, the
purchaser (see "Overview - Sale of offshore operations"). As of September 30,
2004, we owed Newfield approximately $16.0 million for these receivables and
other sale adjustments, the primary reason for the $15.0 million net change in
assets and liabilities relating to operations above for the third quarter of
2004. During the first nine 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, although this amount was
more than offset by the payable to Newfield at September 30, 2004. During the
comparable periods in 2003, additional cash flow was generated by changes in our
working capital balances, primarily decreases in various receivables and
increases in various payables.
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Certain of our operating results and statistics for the comparative third
quarters and first nine months of 2004 and 2003 are included in the following
table.
Three Months Ended Nine Months Ended
September 30, September 30,
- ---------------------------------------------------------------- --------------------------- ----------------------------
2004 2003 2004 2003
- ---------------------------------------------------------------- ------------- ------------ ------------- -------------
Average daily production volumes
Bbls/d 19,206 18,051 19,114 18,852
Mcf/d 62,708 90,393 91,028 95,341
BOE/d (1) 29,657 33,116 34,285 34,742
Operating revenues and expenses (thousands)
Oil sales $ 68,144 $ 44,863 $ 181,198 $ 140,998
Natural gas sales 34,924 43,933 151,177 154,274
Loss on settlements of derivative contracts (2) (22,243) (12,031) (54,750) (53,072)
------------- ------------ ------------- -------------
Total oil and natural gas revenues $ 80,825 $ 76,765 $ 277,625 $ 242,200
============= ============ ============= =============
Lease operating expenses $ 19,781 $ 22,400 $ 66,839 $ 67,850
Production taxes and marketing expenses (3) 4,900 3,761 13,481 11,124
------------- ------------ ------------- -------------
Total production expenses $ 24,681 $ 26,161 $ 80,320 $ 78,974
============= ============ ============= =============
CO2 sales and transportation fees (4) $ 1,681 $ 2,238 $ 4,622 $ 6,872
CO2 operating expenses 255 602 608 1,453
------------- ------------ ------------- -------------
CO2 operating margin $ 1,426 $ 1,636 $ 4,014 $ 5,419
============= ============ ============= =============
Unit prices - including impact of hedges
Oil price per Bbl $ 28.25 $ 24.60 $ 26.58 $ 24.41
Gas price per Mcf 5.36 4.32 5.55 4.48
Unit prices - excluding impact of hedges
Oil price per Bbl $ 38.57 $ 27.01 $ 34.60 $ 27.40
Gas price per Mcf 6.05 5.28 6.06 5.93
Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues (excluding hedges) $ 37.78 $ 29.14 $ 35.38 $ 31.13
------------- ------------ ------------- -------------
Oil and gas lease operating expenses $ 7.25 $ 7.35 $ 7.11 $ 7.15
Oil and gas production taxes and marketing expense 1.80 1.23 1.44 1.17
------------- ------------ ------------- -------------
Total oil and gas production expenses $ 9.05 $ 8.58 $ 8.55 $ 8.32
- ---------------------------------------------------------------- ============= ============ ============= =============
(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 informationconcerning the Company's hedging transactions.
(3) For the three and nine monthsended September 30, 2004, includes transportation expenses paid to Genesis of $0.3 million.
(4) For three and nine months ended September 30, 2004, includes deferred revenue of $0.7 million and $1.8 million, respectively,
associated with a volumetric production payment and $0.7 million and $1.9 million, respectively, of transportation income from
Genesis.
26
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
three quarters of 2004 is listed in the following table.
Average Daily Production (BOE/d)
-----------------------------------------------------------------------------------------
First Second Third Fourth First Second Third
Quarter Quarter Quarter Quarter Quarter Quarter Quarter
Operating Area 2003 2003 2003 2003 2004 2004 2004
- ----------------------------------------------------------------------------------------------------------------------------
Mississippi - non-CO2 floods 14,537 13,600 13,367 13,066 12,754 13,048 12,969
Mississippi - CO2 floods 4,345 4,522 4,227 5,579 6,318 6,603 6,967
Onshore Louisiana 8,700 8,417 8,024 8,812 8,825 7,492 7,033
Other 158 160 312 268 229 345 803
-------------------------------------------------------------------------------------
Total Production excl. Offshore 27,740 26,699 25,930 27,725 28,126 27,488 27,772
Offshore Gulf of Mexico 8,353 8,351 7,186 6,865 8,521 9,114 1,885
-------------------------------------------------------------------------------------
Total Denbury 36,093 35,050 33,116 34,590 36,647 36,602 29,657
- ---------------------------------------=====================================================================================
As a result of the sale of our offshore properties in July 2004, third
quarter production included only 19 days of offshore production, and thus third
quarter production was less than production in all of the prior periods listed
in the table above. Production for the third quarter of 2004 was also negatively
impacted by Hurricane Ivan, which forced the shutdown of production at several
of our fields for a few days as a result of several power outages. Adjusting for
the offshore sale, overall production increased 7% on a BOE/d basis in the third
quarter of 2004 as compared to production in the third quarter of 2003 and
increased 4% for the first nine months of 2004 as compared to the same prior
year period. 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
average production of 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 from first quarter 2003 production for Mississippi -
non-CO2 floods by approximately 526 BOE/d. The balance of the decline in this
operating area is primarily related to natural field 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. During
the third quarter of 2004, production in this area was virtually unchanged from
levels in the second quarter. Natural gas production at this field averaged 13.5
MMcf/d in the third quarter of 2004 and 14.8 MMcf/d in the second quarter of
2004, higher than both the 11.0 MMcf/d of production in the first quarter and an
average of 10.3 MMcf/d of production during 2003, making Heidelberg Field our
single largest natural gas producing field for the last two quarters.
As more fully discussed in "CO2 Operations" above, oil production from our
tertiary operations continued to increase in the third quarter of 2004,
averaging 6,967 Bbls/d, representing 36% of our third quarter corporate oil
production and 25% of our total corporate production on a BOE basis pro forma to
give effect to the offshore sale. Production from our offshore properties
averaged 1,885 BOE/d in the third quarter, representing the production during
the first 19 days of July prior to closing the sale on July 20, 2004. Production
declines in our onshore Louisiana properties essentially offset the increases in
other areas, declining 6% from second quarter 2004 levels and 12% from third
quarter 2003 levels. Production at Thornwell, an onshore Louisiana field,
averaged 1,104 BOE/d during the third quarter of 2004, down from 1,403 BOE/d in
the prior quarter and 2,092 BOE/d in the third quarter of 2003. Production from
this field is in a steep decline due to its short-lived nature, and is expected
to further decline in the future. In spite of its short remaining life, we have
generated a good return on investment at Thornwell, with a net profit to date
(operating revenues less operating expenses and capital expenditures) through
September 30, 2004 of $35.3 million. We have also begun to experience some
declines at Lirette Field, another onshore Louisiana field, decreasing from
2,593 BOE/d in the second quarter of 2004 to 2,133 BOE/d in the third quarter,
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
although relatively close to the third quarter of 2003 production average of
2,284 BOE/d. This field is also expected to continue its decline in the near
future. These two onshore Louisiana fields are expected to have the steepest
decline rates of any of our properties.
Our production in the Barnett Shale increased in the third quarter to
approximately 800 BOE/d from 344 BOE/d in the second quarter and 307 BOE/d in
the third quarter of 2003. The production increase was the result of three
recently drilled horizontal wells, with four more wells scheduled for the last
portion of 2004 and 25 wells tentatively scheduled for 2005.
OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues, net of hedge
payments, for the third quarter of 2004 increased $4.1 million, or 5%, from
revenues in the comparable quarter of 2003, all as a result of higher commodity
prices, partially offset by lower production as a result of the sale of our
offshore properties, and by higher payments on our hedges. When comparing the
respective nine-month periods, revenues were also higher in 2004, primarily as a
result of higher commodity prices. Production was almost the same for the
comparable nine-month periods and hedge payments were slightly higher in 2004
than in 2003. Cash payments on our hedges were $22.2 million in the third
quarter of 2004 and $54.8 million year to date, up 85% on a quarterly basis from
the $12.0 million paid during the third quarter of 2003, and up 3% from the
$53.1 million paid during the first nine 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 third
quarter of 2004 increased revenues 31% or $23.5 million between the respective
third quarters of 2004 and 2003. The 10% decrease in production in the third
quarter of 2004 offset increased oil and natural gas revenues for the two
periods, by $9.3 million, or 12%. Higher hedge payments further reduced revenue
by $10.2 million or 13% between the respective third quarters. While both oil
and natural gas prices were higher in the third quarter of 2004 as compared to
those in the third quarter of 2003, the increase in oil prices was the most
significant, with an increase in our average net oil price (before hedging) of
$11.56 per Bbl, a 43% increase.
When comparing the respective nine month periods, the same factors were
involved, as higher commodity prices were partially offset by lower production
and higher hedge payments. Higher commodity prices on a per BOE basis in the
first nine months of 2004 increased revenues 16% or $39.9 million between the
respective nine month periods. The 1% decrease in production in the first nine
months of 2004 decreased oil and natural gas revenues between the two periods by
$2.8 million, or 1%. Higher hedge payments in the first nine months of 2004
further decreased revenue by $1.7 million or 1% between the respective nine
month periods.
PRODUCTION EXPENSES: During the first three quarters of 2004, our workover
expenses have been at normal levels and approximately $3.4 million less than
during the comparable period in 2003, although we had higher than normal repairs
and maintenance on offshore platforms during the first portion of 2004. As an
example, during the first half of 2003, we incurred $2.9 million on two
individually significant workovers relating to mechanical failures of two
onshore Louisiana wells. Operating expenses on our tertiary operations increased
from $13.3 million in the first nine months of 2003 to $17.9 million in the
comparable period of 2004 as a result of increased activity at Mallalieu and
McComb Fields. However, with the 52% higher production from these tertiary
operations between the same periods, operating expenses for our tertiary
operations on a per BOE basis decreased from $11.20 per BOE in the first nine
months of 2003 to $9.84 per BOE in the first nine months of 2004. Nonetheless,
our tertiary operations are resulting in steadily increasing costs per BOE on a
total 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 through the end of 2004 and beyond as the operating
costs of our tertiary operations are higher than for our other operations and as
our tertiary operations become a larger and larger percentage of our total
operations.
Production taxes and marketing expenses generally change in proportion to
commodity prices and production and as such, were higher in the third quarter of
2004 following record high commodity prices. The sale of our offshore properties
also contributed to the increase in production taxes and marketing expenses on a
per BOE basis during the third quarter of 2004, as most of our offshore
properties were tax exempt.
28
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 101% on a per BOE
basis between the respective third quarters and 44% between the respective first
nine month periods, as set forth below:
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------- ----------------------------------- -------------------------
2004 2003 2004 2003
- ------------------------------------------------- ---------------- ---------------- ------------ ------------
Net G&A expense (thousands)
Gross G&A expenses $ 13,562 $ 10,748 $ 38,015 $ 33,152
State franchise taxes 295 378 783 1,099
Operator overhead charges (6,465) (6,359) (19,959) (19,382)
Capitalized exploration costs (1,195) (1,322) (3,716) (4,257)
---------------- ---------------- ------------ ------------
Net G&A expense $ 6,197 $ 3,445 $ 15,123 $ 10,612
================ ================ ============ ============
Average G&A cost per BOE $ 2.27 $ 1.13 $ 1.61 $ 1.12
Employees as of September 30 369 369 369 369
- ------------------------------------------------- ---------------- ---------------- ------------ ------------
Gross G&A expenses increased $2.8 million, or 26%, between the respective
third quarters and $4.9 million, or 15%, between the respective first nine
months. The single largest component of this increase relates to approximately
$1.4 million and $2.4 million of employee severance payments in the third
quarter and first nine months of 2004, respectively, for the offshore
professional and technical staff terminated in conjunction with our offshore
property sale. We also incurred additional G&A expenses associated with our
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.
During the third quarter of 2004, we granted a total of 1.1 million shares
of restricted stock to our officers and independent directors, generating
deferred compensation expense of approximately $23.0 million, the market value
of the shares on the date of grant. A portion of this restricted stock vests
over five years and a smaller portion vests upon retirement (in addition to
vesting upon death, disability or a change of control). We are amortizing the
$23.0 million of compensation expense of this restricted stock over the five
year vesting period and over the projected retirement date vesting period,
expensing approximately $593,000 during the third quarter of 2004. We estimate
that amortized compensation expense for the restricted stock will be
approximately $1.0 million per quarter through 2006.
As a result of the personnel reductions in our offshore area, our
capitalized exploration costs decreased slightly in the third 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, and for the respective third quarters,
further increased as a result of the lower overall production in the third
quarter of 2004 as a result of the sale of our offshore properties.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest and Financing Expenses
Three Months Ended Nine Months Ended
September 30, September 30,
- ---------------------------------------------------- ------------------------------- --------------------------
Amounts in thousands, except per BOE amounts 2004 2003 2004 2003
- ---------------------------------------------------- -------------- ---------------- ------------- ------------
Interest expense $ 4,768 $ 5,358 $ 14,917 $ 18,046
Non-cash interest expense (304) (226) (757) (1,025)
-------------- ---------------- ------------- ------------
Cash interest expense 4,464 5,132 14,160 17,021
Interest and other income (701) (412) (1,450) (963)
-------------- ---------------- ------------- ------------
Net cash interest expense $ 3,763 $ 4,720 $ 12,710 $ 16,058
============== ================ ============= ============
Average net cash interest expense per BOE $ 1.38 $ 1.55 $ 1.35 $ 1.69
Average interest rate (1) 7.3% 6.2% 6.6% 6.5%
Average debt outstanding $ 243,478 $ 332,913 $ 286,139 $ 350,670
- ---------------------------------------------------- -------------- ---------------- ------------- ------------
(1) Includes commitment fees but excludes amortization of discount and debt issue costs.
Interest expense for the third quarter and first nine months of 2004
decreased from levels in the comparable periods of 2003 primarily due to lower
average debt levels as a result of our $50 million reduction in debt during 2003
and the payoff of our bank debt in the third quarter of 2004 with the proceeds
from our offshore property sale. Our non-cash interest expense for the nine
month comparative periods decreased as a result of the subordinated debt
refinancing in March 2003, which eliminated the amortization of discount on 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 Nine Months Ended
September 30, September 30,
- --------------------------------------------------- ------------------------------- --------------------------
Amounts in thousands, except per BOE amounts 2004 2003 2004 2003
- --------------------------------------------------- -------------- ---------------- ------------- ------------
Depletion and depreciation $ 18,658 $ 20,805 $ 69,357 $ 64,234
Depletion and depreciation of CO2 assets 1,200 635 3,577 1,665
Accretion of asset retirement obligations 429 752 1,971 2,255
Depreciation of other fixed assets 493 374 1,360 1,095
-------------- ---------------- ------------- ------------
Total DD&A $ 20,780 $ 22,566 $ 76,265 $ 69,249
============== ================ ============= ============
DD&A per BOE:
Oil and natural gas properties $ 7.00 $ 7.08 $ 7.59 $ 7.01
CO2 assets and other fixed assets 0.62 0.33 0.53 0.29
- --------------------------------------------------- -------------- ---------------- ------------- ------------
Total DD&A cost per BOE $ 7.62 $ 7.41 $ 8.12 $ 7.30
- --------------------------------------------------- ============== ================ ============= ============
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis increased 3% between the respective third quarters, primarily due
to the higher percentage of expenditures on offshore properties during 2003 and
the first six months 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 during 2004. 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 nine months of 2003. Our DD&A rate on a per BOE basis in the
third quarter of 2004 decreased to $7.62 per BOE, down from $8.46 per BOE in the
second quarter of 2004 primarily as a result of the sale of our offshore
properties, the proceeds of which were credited to the full cost pool. We adjust
our DD&A rate each quarter based on our updated oil and natural gas reserve
estimates, and thus our DD&A rate could change significantly in the future. Our
DD&A rate for our CO2 and other fixed assets increased in the third quarter to
30
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$0.62 per BOE as compared to $0.51 per BOE in the second quarter of 2004, as a
result of the additional cost incurred drilling CO2 wells during the quarter and
higher associated future development costs, partially offset by an increase in
CO2 reserves.
Income Taxes
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------- --------------------------------- ----------------------------
Amounts in thousands, except per BOE amounts and tax rates 2004 2003 2004 2003
- ------------------------------------------------------------- ---------------- ---------------- ------------- --------------
Income tax provision
Current income tax expense (benefit) $ 18,949 $ (1,514) $ 22,045 $ 123
Deferred income tax expense (benefit) (11,117) 9,064 6,077 18,946
---------------- ---------------- ------------- -------------
Total income tax expense $ 7,832 $ 7,550 $ 28,122 $ 19,069
================ ================ ============= =============
Average income tax expense per BOE $ 2.87 $ 2.48 $ 2.99 $ 2.01
Effective tax rate 30.0% 33.3% 31.9% 33.0%
- ------------------------------------------------------------- ---------------- ---------------- ------------- -------------
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 rate. 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. During the third quarter of 2004, we recognized approximately
$18.0 million of current income taxes as a result of the sale of our offshore
properties which was a gain for income tax purposes. The taxes on the offshore
sale were primarily alternative minimum taxes as we were able to offset the
related regular tax with our net operating loss carryfowards. As of September
30, 2004, we had utilized all of our tax net operating loss carryforwards. The
deferred income tax benefit recognized in the third quarter of 2004 is primarily
related to the net impact of the adjustments to temporary differences associated
with the sale of Denbury Offshore.
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 Nine Months Ended
September 30, September 30,
- --------------------------------------------------------------- ------------------------- -------------------------
Per BOE data 2004 2003 2004 2003
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Revenues $ 37.78 $ 29.14 $ 35.38 $ 31.13
Loss on settlements of derivative contracts (8.15) (3.95) (5.83) (5.60)
Lease operating expenses (7.25) (7.35) (7.11) (7.15)
Production taxes and marketing expenses (1.80) (1.23) (1.44) (1.17)
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Production netback 20.58 16.61 21.00 17.21
CO2 operating margin 0.55 0.54 0.43 0.57
General and administrative expenses (2.27) (1.13) (1.61) (1.12)
Net cash interest expense (1.38) (1.55) (1.35) (1.69)
Current income taxes and other (6.57) 0.50 (2.32) -
Net changes in assets and liabilities relating to operations 5.50 1.37 (0.08) 0.40
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Cash flow from operations 16.41 16.34 16.07 15.37
DD&A (7.62) (7.41) (8.12) (7.30)
Deferred income taxes 4.07 (2.97) (0.65) (2.00)
Non-cash hedging adjustments 0.14 0.47 (0.89) 0.39
Early retirement of subordinated debt - - - (1.86)
Cumulative effect of change in accounting principle - - - 0.28
Changes in assets and liabilities and other non-cash items (6.30) (1.46) (0.03) (0.52)
- --------------------------------------------------------------- ------------ ------------ ------------ ------------
Net income $ 6.70 $ 4.97 $ 6.38 $ 4.36
- --------------------------------------------------------------- ============ ============ ============ ============
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Risk Management
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. The following table presents the carrying and fair
values of our debt, along with average interest rates. The fair value of our
bank debt is considered to be the same as the carrying value because the
interest rate is based on floating short-term interest rates. The fair value of
the subordinated debt is based on quoted market prices. None of our debt has any
triggers or covenants regarding our debt ratings with rating agencies.
Expected Maturity Dates
- ------------------------------------- ----------- ----------- ---------- ----------- ----------- ----------- -----------
2004- Carrying Fair
Amounts in thousands 2005 2006 2007 2008 Thereafter Value Value
- ------------------------------------- ----------- ----------- ---------- ----------- ----------- ----------- -----------
Fixed rate debt:
7.5% subordinated debt,
net of discount, due 2013........... $ - $ - $ - $ - $ 225,000 $ 223,348 $ 238,500
The interest rate on the subordinated debt is a fixed rate of 7.5%.
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. We generally attempt to hedge between 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 a significant 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 during the third quarter of 2004 we
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, were the primary reasons for the $8.3
million net charge to earnings for the first nine months of 2004 relating to our
derivative contracts.
At September 30, 2004, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $37.8 million, a decrease of
approximately $6.8 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 nine 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 September 30, 2004.
Information regarding our current hedging positions is included in Note 11 to
the Unaudited Condensed Consolidated Financial Statements.
32
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Although we have hedged less of our production in 2004 than in 2003
(approximately 60% of our total production in 2004 as compared to approximately
80% in 2003), we expect our total hedge payments for 2004 to be higher than in
2003 due to the significantly higher oil prices in 2004 and lower hedged prices.
For 2005 production, through September 30, 2004 we had purchased 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 September 30, 2004, we would
expect to make future cash payments of $14.5 million on our natural gas
commodity hedges. If natural gas futures prices were to decline by 10%, we would
expect to pay $8.4 million under our natural gas commodity hedges, and if
futures prices were to increase by 10% we would expect to pay $20.5 million.
Based on NYMEX crude oil futures prices at September 30, 2004, we would expect
to pay $22.9 million on our crude oil commodity hedges. If crude oil futures
prices were to decline by 10%, we would expect to pay $18.6 million, and if
crude oil futures prices were to increase by 10%, we would expect to pay $27.1
million under our crude oil commodity hedges. Most of our hedges that have a
ceiling price expire by the end of 2004.
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.
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q ("Quarterly
Report") that are not historical facts, including, but not limited to,
statements found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, acquisition plans and proposals and dispositions, development
activities, cost savings, production efforts and volumes, hydrocarbon reserves,
hydrocarbon prices, CO2 production and deliverability, liquidity, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "estimate," "budgeted," "expect,"
"predict," "anticipate," "projected," "should," "assume," "believe" or other
words that convey the uncertainty of future events or outcomes. Such
forward-looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and our financial condition and results of
operations. As a consequence, actual results may differ materially from
expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for our oil and natural gas, the uncertainty of
drilling results and reserve estimates, operating hazards, acquisition risks,
requirements for capital, general economic conditions, competition and
government regulations, as well as the risks and uncertainties discussed in this
Quarterly Report, including, without limitation, the portions referenced above,
and the uncertainties set forth from time to time in the Company's other public
reports, filings and public statements.
33
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 1. Legal Proceedings
- --------------------------
We, along with two other companies have been named in a lawsuit entitled
"J. Paulin Duhe, Inc. vs. Texaco, Inc., et al," Cause No. 101,227, filed within
the last year in the 16th Judicial District Court, Division "E", Terrebonne
Parish, Louisiana, seeking unspecified monetary amounts for alleged surface and
groundwater contamination affecting, and asking for restoration of, the lands
that are part of our Iberia Field in Iberia Parish, Louisiana. The first oil and
natural gas well was drilled on this property in 1921. We acquired this property
approximately four years ago and have an indemnification from the prior owner,
which we anticipate will cover us from most environmental damages that occurred
prior to the time that we purchased the property. We have not yet been able to
determine our potential exposure in this case. We plan to vigorously defend this
lawsuit, as well as seek indemnification from the prior owners if necessary.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
- --------------------------------------------------------------------
Presented below is information on repurchases by Denbury of its common stock
during 2004:
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 Plans 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 -
June 1 through 30, 2004 - - - -
July 1 through 31, 2004 40,000 $ 21.31 40,000 160,000
August 1 through 31, 2004 10,000 $ 20.00 10,000 150,000
September 1 through 30, 2004 - - - 150,000
Total 150,000 $ 18.09 150,000 150,000
- ---------------------------------------------------------------------------------------------------------------
34
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 and
three months, beginning July 1, 2004 and ending September 30, 2005 covering
another 200,000 shares at the same 50,000 shares per quarter rate. 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 6. Exhibits
-----------------
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.
35
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DENBURY RESOURCES INC.
(Registrant)
By: /s/ Phil Rykhoek
----------------------------------------------
Phil Rykhoek
Sr. Vice President and Chief Financial Officer
By: /s/ Mark C. Allen
----------------------------------------------
Mark C. Allen
Vice President and Chief Accounting Officer
Date: November 8, 2004
36