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, 2003
Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Commission file number 1-12935
----------------------------------------
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 75-2815171
(State or other jurisdictions of (I.R.S. Employer
incorporation or organization) Identification No.)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No__
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes X No__
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at October 31, 2003
----- -------------------------------
Common Stock, $.001 par value 54,065,660
DENBURY RESOURCES INC.
INDEX
Page
Part I. Financial Information ----
- ------------------------------
Item 1. Financial Statements
Independent Accountants' Report 3
Unaudited Condensed Consolidated Balance Sheets at September 30, 2003
and December 31, 2002 4
Unaudited Condensed Consolidated Statements of Operations for the
Three and Nine Months Ended September 30, 2003 and 2002 5
Unaudited Condensed Consolidated Statements of Cash Flows for the
Three and Nine Months Ended September 30, 2003 and 2002 6
Unaudited Condensed Consolidated Statements of Comprehensive Income for
the Three and Nine Months Ended September 30, 2003 and 2002 7
Notes to Unaudited Condensed Consolidated Financial Statements 8-18
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 19-33
Item 3. Quantitative and Qualitative Disclosures about Market Risk 34
Item 4. Controls and Procedures 34
Part II. Other Information
---------------------------
Items 1-5. Not Applicable
Item 6. Exhibits and Reports on Form 8-K 34
Signatures 35
Part I. Financial Information
Item 1. Financial Statements
- -----------------------------
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Directors of Denbury Resources Inc.:
We have reviewed the accompanying condensed consolidated balance sheet of
Denbury Resources Inc. and subsidiaries (the "Company") as of September 30,
2003, and the related condensed consolidated statements of operations, cash
flows, and comprehensive income for the three-month and nine-month periods ended
September 30, 2003 and 2002. These interim financial statements are the
responsibility of the Company's management.
We conducted our reviews in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures and
making inquiries of persons responsible for financial and accounting matters. It
is substantially less in scope than an audit conducted in accordance with
auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should
be made to such condensed consolidated financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of
Denbury Resources Inc. and subsidiaries as of December 31, 2002 and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year then ended (not presented herein); and in our report dated March 3,
2003, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
condensed consolidated balance sheet as of December 31, 2002 is fairly stated,
in all material respects, in relation to the consolidated balance sheet from
which it has been derived.
As discussed in Note 3 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations," effective January 1, 2003.
/s/ Deloitte & Touche LLP
Dallas, Texas
November 12, 2003
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share amounts)
September 30, December 31,
2003 2002
---------------- ---------------
Assets
Current assets
Cash and cash equivalents $ 28,108 $ 23,940
Accrued production receivable 32,027 34,458
Related party accrued production receivable - Genesis 4,247 3,334
Trade and other receivables 16,668 16,846
Deferred tax asset 16,090 49,886
------------ -----------
Total current assets 97,140 128,464
------------ -----------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,364,366 1,245,896
Unevaluated 50,227 45,736
CO2 properties and equipment 78,600 62,370
Less accumulated depletion and depreciation (671,881) (609,917)
------------ -----------
Net property and equipment 821,312 744,085
------------ -----------
Investment in Genesis 2,202 2,224
Other assets 21,904 20,519
------------ -----------
Total assets $ 942,558 $ 895,292
============ ===========
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 52,365 $ 49,281
Oil and gas production payable 19,508 17,309
Derivative liabilities 27,606 29,289
------------ -----------
Total current liabilities 99,479 95,879
------------ -----------
Long-term liabilities
Long-term debt 327,154 344,889
Asset retirement liabilities 39,049 6,845
Derivative liabilities 7,849 6,281
Deferred tax liability 56,108 71,663
Other 2,533 2,938
------------ -----------
Total long-term liabilities 432,693 432,616
------------ -----------
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding - -
Common stock, $.001 par value, 100,000,000 shares authorized;
54,047,640 and 53,539,329 shares issued and outstanding at September
30, 2003 and December 31, 2002, respectively 54 54
Paid-in capital in excess of par 400,423 395,906
Retained earnings (accumulated deficit) 31,446 (9,875)
Accumulated other comprehensive loss (21,512) (19,288)
Treasury stock, at cost, 1,987 shares at September 30, 2003 (25) -
------------ -----------
Total stockholders' equity 410,386 366,797
------------ -----------
Total liabilities and stockholders' equity $ 942,558 $ 895,292
============ ===========
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
4
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,
--------------------------- -------------------------
2003 2002 2003 2002
------------- ------------- ------------ ------------
Revenues
Oil, natural gas and related product sales
Unrelated parties $ 78,333 $ 64,722 $ 261,219 $ 183,232
Related party - Genesis 10,463 7,431 34,053 10,945
CO2 sales 2,238 2,182 6,872 5,568
Gain (loss) on settlements of derivative contracts (12,031) (218) (53,072) 2,430
Interest and other income 412 407 963 1,229
------------- ------------- ------------ ------------
Total revenues 79,415 74,524 250,035 203,404
------------- ------------- ------------ ------------
Expenses
Lease operating expenses 22,400 17,714 67,850 50,266
Production taxes and marketing expenses 3,761 2,969 11,124 8,880
CO2 operating expenses 602 431 1,453 960
General and administrative expenses 3,445 3,034 10,612 9,544
Interest 5,358 6,860 18,046 20,086
Loss on early retirement of debt - - 17,629 -
Depletion and depreciation 22,566 23,031 69,249 70,162
Amortization of derivative contracts and other
non-cash hedging adjustments (1,441) (1,133) (3,702) (3,226)
------------- ------------- ------------ ------------
Total expenses 56,691 52,906 192,261 156,672
------------- ------------- ------------ ------------
Equity in net income (loss) of Genesis (25) 2 26 22
------------- ------------- ------------ ------------
Income before income taxes 22,699 21,620 57,800 46,754
Income tax provision (benefit)
Current income taxes (1,514) 20 123 (428)
Deferred income taxes 9,064 8,141 18,946 15,679
------------- ------------- ------------ ------------
Income before cumulative effect of change in
accounting principle 15,149 13,459 38,731 31,503
Cumulative effect of change in accounting
principle, net of income taxes of $1,600 - - 2,612 -
------------- ------------- ------------ ------------
Net income $ 15,149 $ 13,459 $ 41,343 $ 31,503
============= ============= ============ ============
Net income per common share - basic
Income before cumulative effect of change in
accounting principle $ 0.28 $ 0.25 $ 0.72 $ 0.59
Cumulative effect of change in accounting principle - - 0.05 -
------------- ------------- ------------ ------------
Net income per common share - basic $ 0.28 $ 0.25 $ 0.77 $ 0.59
============= ============= ============ ============
Net income per common share - diluted
Income before cumulative effect of change in
accounting principle $ 0.27 $ 0.25 $ 0.70 $ 0.58
Cumulative effect of change in accounting principle - - 0.05 -
------------- ------------- ------------ ------------
Net income per common share - diluted $ 0.27 $ 0.25 $ 0.75 $ 0.58
============= ============= ============ ============
Weighted average common shares outstanding:
Basic 54,014 53,354 53,824 53,170
Diluted 55,718 54,562 55,375 54,193
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- --------------------------
2003 2002 2003 2002
------------- ------------ ------------ -----------
Cash flow from operating activities:
Net income $ 15,149 $ 13,459 $ 41,343 $ 31,503
Adjustments needed to reconcile to net cash flow
provided by operations:
Depreciation, depletion and amortization 22,566 23,031 69,249 70,162
Amortization of derivative contracts and other
non-cash hedging adjustments (1,441) (1,133) (3,702) (3,226)
Deferred income taxes 9,064 8,141 18,946 15,679
Loss on early retirement of debt - - 17,629 -
Amortization of debt issue costs and other 273 679 1,113 2,006
Cumulative effect of change in accounting principle - - (2,612) -
Changes in assets and liabilities:
Accrued production receivable 3,891 (3,019) 1,518 (9,085)
Trade and other receivables 3,322 1,960 178 20,576
Other assets 1 572 6 8,198
Accounts payable and accrued liabilities (995) 34 1,219 (33,233)
Oil and gas production payable (1,540) 1,058 2,199 1,020
Other liabilities (501) (403) (1,246) (617)
------------- ------------ ------------ -----------
Net cash provided by operations 49,789 44,379 145,840 102,983
------------- ------------ ------------ -----------
Cash flow used for investing activities:
Oil and natural gas expenditures (37,397) (26,444) (108,106) (76,094)
Acquisitions of oil and gas properties (1,854) (50,974) (11,478) (53,242)
Investment in Genesis - (129) - (2,169)
Acquisitions of CO2 assets and capital expenditures (2,635) (5,459) (16,008) (11,393)
Proceeds from oil and gas property sales 1,174 - 29,328 4,552
(Increase) decrease in restricted cash (211) 2,922 (567) (621)
Net (purchases) sales of other assets 5,428 (538) (1,545) (853)
------------- ------------ ------------ -----------
Net cash used for investing activities (35,495) (80,622) (108,376) (139,820)
------------- ------------ ------------ -----------
Cash flow from financing activities:
Bank repayments (6,000) (5,000) (131,000) (15,000)
Bank borrowings - 44,000 85,000 49,130
Repayment of 9% subordinated debt, including
redemption premium - - (209,000) -
Issuance of 7.5% subordinated debt, net of discount - - 223,054 -
Issuance of common stock 1,138 711 4,108 2,854
Debt issuance costs (31) (719) (4,817) (719)
Purchase of treasury stock (641) - (641) -
------------- ------------ ------------ -----------
Net cash provided (used) for financing activities (5,534) 38,992 (33,296) 36,265
------------- ------------ ------------ -----------
Net increase (decrease) in cash and cash equivalents 8,760 2,749 4,168 (572)
Cash and cash equivalents at beginning of period 19,348 20,175 23,940 23,496
------------- ------------ ------------ -----------
Cash and cash equivalents at end of period $ 28,108 $ 22,924 $ 28,108 $ 22,924
============= ============ ============ ===========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 835 $ 10,759 $ 14,206 $ 22,879
Cash paid (refunded) during the period for income taxes - - 184 (1,305)
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME
(Amounts in thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- --------------------------
2003 2002 2003 2002
------------- ------------ ------------ -----------
Net income $ 15,149 $ 13,459 $ 41,343 $ 31,503
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts, net of
tax of 8,734, (3,510), 43, and (13,727), respectively 14,250 (5,977) 71 (23,374)
Amortization of derivative contracts, net of tax of
114, 856, 338, and 2,751, respectively 187 1,457 553 4,684
Reclassification adjustments related to derivative contracts,
net of tax of (662), (1,452), (1,746), and (4,122), respectively (1,080) (1,993) (2,848) (6,539)
------------- ------------ ------------ -----------
Comprehensive income $ 28,506 $ 6,946 $ 39,119 $ 6,274
============= ============ ============ ===========
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
7
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, 2002. 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 our opinion, the accompanying unaudited
condensed consolidated financial statements include all adjustments (of a normal
recurring nature) necessary to present fairly the consolidated financial
position of Denbury as of September 30, 2003 and the consolidated results of its
operations and cash flows for the three and nine month periods ended September
30, 2003 and 2002. Certain prior period items have been reclassified to make the
classification consistent with this quarter.
Stock-based Compensation
We issue stock options to all of our employees under our stock option plan,
which we account for utilizing the recognition and measurement principles of
Accounting Principles Board Opinion 25, "Accounting for Stock Issued to
Employees," and its related interpretations. Under these principles, we do not
recognize any stock-based employee compensation for stock option grants, as long
as the exercise price is equal to the price 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 if we had applied the fair value recognition and
measurement provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation," as amended by SFAS No 148, in accounting for our stock option
plan.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ------------ ------------
Net income: (thousands)
Net Income, as reported .................................. $ 15,149 $ 13,459 $ 41,343 $ 31,503
Less: stock-based compensation expense applying fair
value based method, net of related tax effects..... 1,005 807 2,638 2,165
------------ ------------ ------------ ------------
Pro forma net income................................... $ 14,144 $ 12,652 $ 38,705 $ 29,338
============ ============ ============ ============
Net income per common share:
As reported:
Basic.................................................. $ 0.28 $ 0.25 $ 0.77 $ 0.59
Diluted................................................ 0.27 0.25 0.75 0.58
Pro forma:
Basic.................................................. $ 0.26 $ 0.24 $ 0.72 $ 0.55
Diluted................................................ 0.25 0.23 0.70 0.54
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2. NEW ACCOUNTING STANDARDS
See Note 3 regarding our change in accounting related to our adoption of
Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for
Asset Retirement Obligations."
In November 2002, the Financial Accounting Standards Board ("FASB") issued
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness by Others."
Interpretation No. 45 requires that a guarantor must recognize, at the inception
of the guarantee, a liability for the fair value of the obligation that it has
undertaken in issuing a guarantee. Interpretation No. 45 also addresses the
disclosure requirements that a guarantor must include in its financial
statements for guarantees issued. The initial recognition and measurement
provisions of this interpretation are applicable on a prospective basis to
guarantees issued or modified after December 31, 2002. We have made all relevant
disclosures regarding our guarantees.
On January 1, 2003, we adopted the provisions of SFAS No. 145, "Rescission
of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." SFAS No. 145 changes the method of reporting gains or
losses on the early extinguishment of debt. Prior to SFAS No. 145, gains or
losses on the early extinguishment of debt were required to be classified in a
company's statement of operations as an extraordinary item, net of the related
income tax effect. SFAS No. 145 considers the use of early debt extinguishment
to generally be a risk management strategy and states that its effects should be
reflected as income or expense from continuing operations, except in rare cases
where the extinguishment of debt could be considered unusual or infrequent and
would therefore be classified as an extraordinary item. In April 2003, we
retired our $200 million of Senior Subordinated Notes Due 2008, and recorded a
$17.6 million loss, before income taxes, on the early retirement of this debt
(see Note 7 for further information regarding this debt retirement).
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires that a
liability be recognized for exit and disposal costs only when the liability has
been incurred and when it can be measured at fair value. The statement is
effective for exit and disposal activities that are initiated after December 31,
2002. We adopted this statement in the first quarter of 2003 and it has not had
any effect on our financial statements.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies certain accounting and reporting for derivative instruments. This
statement is effective for contracts entered into or modified after September
30, 2003. We adopted this statement in the third quarter of 2003 and it did not
have any impact on our financial statements.
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," became effective July 1, 2001 and January 1, 2002,
respectively. It is our understanding that the Securities and Exchange
Commission has raised questions as to the proper application by registrants in
the oil and gas industry of the provisions of SFAS No. 141 and SFAS No. 142 and
has referred this question to the Emerging Issues Task Force of the FASB. In
question is whether the acquisition of contractual mineral interests, including
both proved and undeveloped, should be classified separately as "intangible
assets" on the balance sheet apart from other oil and gas property costs.
Currently, Denbury, and virtually all other companies in the oil and gas
industry, have historically included purchased contractual mineral rights in oil
and gas properties on the balance sheet. Until we receive further guidance
regarding this issue, we will continue to include mineral interests as oil and
gas properties on our balance sheet for mineral interests acquired subsequent to
September 30, 2001. Based on the limited guidance pertaining to this issue, we
have not calculated the potential balance sheet reclassification at this time.
The provisions of SFAS No. 141 and 142 impact only the balance sheet and
associated footnote disclosure, and any reclassifications, if necessary, would
not impact the Company's results of operations or cash flows.
9
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
In January 2003, the FASB issued Interpretation No. 46 "Consolidation of
Variable Interest Entities." The Interpretation will significantly change
whether entities included in its scope are consolidated by their sponsors,
transferors, or investors. An entity is considered to be a variable interest
entity when either (i) the entity lacks sufficient equity to carry on its
principal operations, (ii) the equity owners of the entity cannot make decisions
about the entity's activities, or (iii) the entity's equity neither absorbs
losses nor benefits from gains. These provisions apply immediately to variable
interests in Variable Interest Entities ("VIEs") created after January 15, 2003,
and were originally slated to be effective in the third quarter of 2003 for VIEs
in which a company holds a variable interest that it acquired prior to February
1, 2003. At the October 8, 2003 FASB meeting, FASB agreed to a deferral of the
effective date for VIEs created before February 1, 2003 until the first
reporting period ended after December 15, 2003. Subsequent to January 31, 2003,
we have not acquired an interest in any VIEs that would require immediate
consolidation under Interpretation No. 46. We are currently evaluating our
financial arrangements to determine whether any VIEs existed prior to January
31, 2003.
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.
The following pro forma data summarizes Denbury's net income and net income
per common share as if we had applied the provisions of SFAS No. 143 in prior
periods, and as if we had removed the first quarter 2003 cumulative effect
adjustment for the adoption of SFAS No. 143:
Three Months Ended Nine Months Ended
September 30, September 30, Year Ended December 31,
--------------------- -------------------- ------------------------------
2003 2002 2003 2002 2002 2001 2000
---------- ---------- ---------- --------- --------- --------- ----------
Net income: (thousands)
Net income, as reported ............... $ 15,149 $ 13,459 $ 41,343 $ 31,503 $ 46,795 $ 56,550 $ 142,227
Pro forma adjustments to reflect
retroactive adoption of SFAS 143.. - 23 (2,612) (102) 473 503 306
---------- ---------- ---------- --------- --------- --------- ----------
Pro forma net income................ $ 15,149 $ 13,482 $ 38,731 $ 31,401 $ 47,268 $ 57,053 $ 142,533
========== ========== ========== ========= ========= ========= ==========
Net income per common share:
As reported:
Basic........................... $ 0.28 $ 0.25 $ 0.77 $ 0.59 $ 0.88 $ 1.15 $ 3.10
Diluted......................... 0.27 0.25 0.75 0.58 0.86 1.12 3.07
Pro forma:
Basic........................... $ 0.28 $ 0.25 $ 0.72 $ 0.59 $ 0.89 $ 1.16 $ 3.11
Diluted......................... 0.27 0.25 0.70 0.58 0.87 1.13 3.08
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the changes in our asset retirement
obligations for the nine months ended September 30, 2003.
Nine Months Ended
September 30, 2003
------------------
(in thousands)
Beginning asset retirement obligation, as of December 31, 2002..... $ 6,845
Cumulative effect adjustment for SFAS 143, January 1, 2003......... 34,110
Liabilities incurred during period................................. 931
Liabilities settled during period.................................. (835)
Liabilities sold during period..................................... (2,392)
Accretion expense.................................................. 2,255
------------------
Ending asset retirement obligation................................. $ 40,914
==================
At September 30, 2003, $1.9 million of our asset retirement obligation was
classified in "Accounts payable and accrued liabilities" under current
liabilities in our Consolidated Balance Sheet. We have escrow accounts that are
legally restricted for certain of our asset retirement obligations. The balances
of these escrow accounts were $9.2 million at September 30, 2003, and $8.7
million at December 31, 2002 and are included in "Other assets" in our
Consolidated Balance Sheet. If we had adopted SFAS No. 143 as of January 1,
2002, we estimate that our asset retirement obligations at that date would have
been $34.1 million, based on the same assumptions used in our calculation of our
obligations at January 1, 2003.
4. NET INCOME PER COMMON SHARE
Basic net income per common share is computed by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
Diluted net income per common share is calculated in the same manner, but also
considers the impact on net income and common shares for the potential dilution
from stock options and any other convertible securities outstanding. For the
three and nine month periods ended September 30, 2003 and 2002, there were no
adjustments to net income for purposes of calculating diluted net income per
common share. The following is a reconciliation of the weighted average common
shares used in the basic and diluted net income per common share calculations
for the three and nine month periods ended September 30, 2003 and 2002.
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
2003 2002 2003 2002
-------------- ------------- -------------- ------------
(in thousands) (in thousands)
Weighted average common shares - basic 54,014 53,354 53,824 53,170
Potentially dilutive securities:
Stock options 1,704 1,208 1,551 1,023
-------------- ------------- -------------- ------------
Weighted average common shares - diluted 55,718 54,562 55,375 54,193
============== ============= ============== ============
For the three months ended September 30, 2003 and 2002, common stock
options to purchase approximately 1.0 million and 1.3 million shares of common
stock, and for the nine months ended September 30, 2003 and 2002, common stock
options to purchase approximately 1.0 million and 2.1 million shares of common
stock, respectively, were outstanding but excluded from the diluted net income
per common share calculations. Common stock options with exercise prices in
excess of our average market stock price during the respective periods are
excluded from the diluted net income per common share calculation, as their
impact would be anti-dilutive to our calculation.
11
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5. SALE OF LAUREL FIELD
In February 2003, we sold Laurel Field, acquired in the COHO acquisition in
August 2002, for approximately $26.1 million and other consideration which
included an interest in Atchafalaya Bay Field (where we already owned an
interest) and seismic over that area. At December 31, 2002, Laurel Field had
approximately 7.4 MMBbls of proved reserves.
6. STOCK REPURCHASE PLAN
In August 2003, we adopted a stock repurchase plan ("Plan") to purchase
shares of our common stock on the NYSE in order for such repurchase shares to be
reissued to our employees who participate in Denbury's Employee Stock Purchase
Plan ("ESPP"). 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. 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 the fiscal quarter.
During the third quarter of 2003, we purchased 50,000 shares at an average cost
of $12.81 per share. On September 30, 2003, we issued 48,013 of these shares
under Denbury's ESPP.
7. INDEBTEDNESS
September 30, December 31,
2003 2002
--------------- ---------------
(Amounts in thousands)
9% Senior Subordinated Notes Due 2008................................... $ - $ 125,000
9% Series B Senior Subordinated Notes Due 2008.......................... - 75,000
7.5% Senior Subordinated Notes Due 2013................................. 225,000 -
Senior bank loan........................................................ 104,000 150,000
Discount on Senior Subordinated Notes................................... (1,846) (5,111)
--------------- ---------------
Total debt.......................................................... $ 327,154 $ 344,889
=============== ===============
Issuance of 7.5% Senior Subordinated Notes Due 2013
On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes
Due 2013 in a Rule 144A private offering. The notes were priced at 99.135% of
par and we used most of our $218.4 million of net proceeds from the offering,
after underwriting and issuance costs, to retire our existing $200 million of 9%
Senior Subordinated Notes Due 2008, including the Series B notes, (see
"Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes)"
below).
The notes mature on April 1, 2013 and interest on the notes is payable each
April 1 and October 1, commencing October 1, 2003. We may redeem the notes at
our option beginning April 1, 2008 at the following redemption prices: 103.75%
after April 1, 2008, 102.5% after April 1, 2009, 101.25% after April 1, 2010,
and at 100% after April 1, 2011 and thereafter. In addition, prior to April 1,
2006, we may redeem up to 35% of the notes at a redemption price of 107.5% with
net cash proceeds from a stock offering. The indenture under which the notes
were issued is essentially the same as the indenture covering our previously
outstanding 9% notes. The indenture contains certain restrictions on our ability
to incur additional debt, pay dividends on our common stock, make investments,
create liens on our assets, engage in transactions with our affiliates, transfer
or sell assets, consolidate or merge, or sell substantially all of our assets.
The notes are not subject to any sinking fund requirements.
12
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Redemption of 9% Senior Subordinated Notes Due 2008 (Including Series B Notes)
On March 18, 2003, we issued the required 30-day notice to call our
existing $200 million of 9% Senior Subordinated Notes Due 2008. On April 16,
2003, we redeemed the $200 million of notes at an aggregate cost of $209.0
million, including a $9.0 million call premium. As a result of this early
redemption, we recorded a before-tax charge to earnings in the second quarter of
2003 of $17.6 million, which includes the $9.0 million call premium and the
write-off of the remaining discount and debt issuance costs associated with
these notes.
Senior Bank Loan
Our bank borrowing base was reaffirmed as of October 1, 2003 at $220
million, as part of the semi-annual review by our banks. During 2003, we amended
our credit agreement to increase the percentage of production we are allowed to
hedge, increasing the 2003 limitation to 90% of our forecasted production,
setting a maximum of 85% of our forecasted production from our proved reserves
for the current year (as defined in the amendment which may include up to 18
months), a maximum of 70% of forecasted production for the subsequent year, a
maximum of 55% of forecasted production for the third year and a maximum of 40%
of the forecasted production for the fourth year. We also amended the credit
agreement to allow our borrowings of up to $20 million in a bond issue from a
Mississippi governmental authority, resulting in the exemption or reduction of
sales and ad valorem taxes on CO2 facilities we build during the next two years
in Mississippi. This bond funding arrangement was completed in May 2003. Any
borrowings under this bond program will be purchased by the banks in our credit
facility, will become part of our outstanding borrowings under our credit line,
and will accrue interest and be repaid on the same basis as our bank line. Our
next bank borrowing base redetermination will be as of April 1, 2004, based on
December 31, 2003 assets. We do not anticipate any significant changes to our
borrowing base at this next review, although we cannot be certain, as there are
several subjective aspects to the borrowing base determination.
At September 30, 2003, we had $104.0 million outstanding under our bank
credit facility, leaving us approximately $116.0 million of borrowing capacity.
We also had letters of credit outstanding in the amount of $820,000 at September
30, 2003.
8. RELATED PARTY TRANSACTIONS - GENESIS
See Note 11, "Subsequent Event - Genesis Transactions" for information
regarding recent transactions with Genesis.
Through certain of our subsidiaries, since May 14, 2002 we have been the
general partner of Genesis Energy, L.P. ("Genesis"), a publicly traded master
limited partnership. Our subsidiary general partner has a 2% interest in
Genesis. Genesis has two primary lines of business: crude oil gathering and
marketing, and pipeline transportation, primarily in Mississippi, Texas, Alabama
and Florida.
We account for our 2% ownership in Genesis under the equity method, as we
have significant influence over the limited partnership; however, our control is
limited under the general partnership agreement and therefore we do not
consolidate Genesis. Our equity in Genesis' net income (loss) for the three and
nine month periods ended September 30, 2003 was ($25,000) and $26,000,
respectively. For the first nine months of 2003, Genesis has paid Denbury
$90,000 for directors' fees for the services of the four Denbury officers that
serve on the board of directors of the general partner of Genesis, and $47,690
of distributions. Genesis Energy, Inc., the general partner of which we
indirectly own 100%, has guaranteed the bank debt of Genesis, which was $6.0
million as of September 30, 2003, and also included $19.3 million in letters of
credit, of which $4.1 million are for Denbury's benefit to secure purchases from
Denbury. There are no guarantees by Denbury or any of its other subsidiaries of
the debt of Genesis or of Genesis Energy, Inc.
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Genesis has historically been a purchaser of our crude oil and we
anticipate future purchases of our crude oil production by Genesis. For the nine
month period ended September 30, 2003, we recorded sales to Genesis of $34.1
million and at September 30, 2003, had a production receivable from Genesis of
$4.2 million. Sales to Genesis for the period May 14, 2002 to September 30, 2002
were $10.9 million.
Summarized financial information of Genesis Energy, L.P. is as follows
(amounts in thousands):
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2003
-------------------- --------------------
Revenues.................................. $ 239,031 $ 720,862
Cost of sales............................. 236,877 707,594
Other expenses............................ 3,367 11,712
-------------------- --------------------
Net income (loss)......................... $ (1,213) $ 1,556
==================== ====================
September 30, December 31,
2003 2002
-------------------- --------------------
Current assets............................ $ 84,434 $ 92,097
Non-current assets........................ 46,011 45,440
-------------------- --------------------
Total assets.............................. $ 130,445 $ 137,537
==================== ====================
Current liabilities....................... $ 87,913 $ 96,220
Non-current liabilities................... 6,000 5,500
Partners' capital......................... 36,532 35,817
-------------------- --------------------
Total liabilities and partners' capital... $ 130,445 $ 137,537
==================== ====================
9. PRODUCT PRICE HEDGING CONTRACTS
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. We generally attempt to hedge between 50% and 75% of our
anticipated production each year to provide us with a reasonably certain amount
of cash flow to cover most of our budgeted exploration and development
expenditures without incurring significant debt. When we make an acquisition, we
attempt to hedge a large percentage, up to 100%, of the forecasted production
for the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. All of the mark-to-market
valuations used for our financial derivatives are provided by external sources
and are based on prices that are actively quoted.
The following is a summary of the net gain (loss) representing cash
receipts and payments on our hedge settlements:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------ -----------------------------------------
2003 2002 2003 2002
----------------- ----------------- ------------------ -------------------
(in thousands)
Oil hedge contracts $ (4,009) $ (257) $ (15,380) $ 205
Gas hedge contracts (8,022) 39 (37,692) 2,225
----------------- ----------------- ------------------ -------------------
Net gain (loss) $ (12,031) $ (218) $ (53,072) $ 2,430
================= ================= ================== ===================
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Some of our derivative contracts require us to pay a premium which we
amortize over the contract periods. This expense is included in "Amortization of
derivative contracts and other non-cash hedging adjustments" in our Consolidated
Statements of Operations. We recorded premium amortization expense of $891,000
and $7.4 million, for the nine months ended September 30, 2003 and 2002,
respectively and $300,000 and $2.3 million for the three months ended September
30, 2003 and 2002, respectively. Also, for the nine months ended September 30,
2003, we reclassified $4.1 million related to our former Enron hedges (discussed
below) out of accumulated other comprehensive income into income and recorded a
gain from hedge ineffectiveness of $513,000 which is also included in
"Amortization of derivative contracts and other non-cash hedging adjustments."
Hedging Contracts at September 30, 2003
Crude Oil Contracts:
- -------------------
NYMEX Contract Prices Per Bbl
-------------------------------------------------------------
Collar Prices
---------------------------
Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling September 30, 2003
- ---------------------------------- ------------- ---------- ------------ ------- ---------- --------------------
Collar Contracts (in thousands)
Oct. 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ (529)
Swap Contracts
Oct. 2003 - Dec. 2003 2,500 24.25 - - - (1,033)
Oct. 2003 - Dec. 2003 2,000 24.30 - - - (818)
Oct. 2003 - Dec. 2003 2,000 25.70 - - - (561)
Jan. 2004 - Dec. 2004 2,500 22.89 - - - (3,394)
Jan. 2004 - Dec. 2004 4,500 23.00 - - - (5,931)
Jan. 2004 - Dec. 2004 2,500 23.08 - - - (3,222)
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, 2003
- ---------------------------------- ------------- ---------- ------------ ------- ---------- --------------------
Collar Contracts (in thousands)
Oct. 2003 - Dec. 2003 45,000 $ - $ - $ 2.75 $ 4.00 $ (3,456)
Oct. 2003 - Dec. 2003 25,000 - - 2.75 4.07 (1,773)
Jan. 2004 - Dec. 2004 30,000 - - 3.50 4.45 (8,094)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.87 (1,766)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.82 (1,817)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (2,230)
Swap Contracts
Oct. 2003 - Dec. 2003 10,000 3.905 - - - (832)
At September 30, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of $35.5 million. To the extent our hedges are
considered effective, this fair value liability, net of income taxes, is
included in "Accumulated other comprehensive loss" reported under Stockholders'
equity in our Consolidated Balance Sheets. The balance in accumulated other
comprehensive loss of $21.5 million at September 30, 2003, represents the
deficit in the fair market value of our derivative contracts as compared to the
cost of our hedges, net of income taxes, and also includes the remaining
accumulated other comprehensive income of $600,000 relating to the Enron hedges
that ceased to qualify for hedge accounting treatment when Enron filed for
bankruptcy. This $600,000 relating to the former Enron hedges will be
reclassified out of accumulated other comprehensive income during the remainder
of 2003, over the periods that the hedges would have otherwise expired. Of the
$21.5 million in accumulated other comprehensive loss as of September 30, 2003,
$17.1 million relates to current hedging contracts that will expire within the
next 12 months.
15
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of August 2001, all of the Company's subordinated debt securities were
fully and unconditionally guaranteed by Denbury Resources Inc.'s significant
subsidiaries. Condensed consolidating financial information for Denbury
Resources Inc. and its significant subsidiaries as of September 30, 2003 and
December 31, 2002 and for the three and nine months ended September 30, 2003 and
2002 is as follows:
Condensed Consolidating Balance Sheets
September 30, 2003 (Unaudited)
----------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------- ------------- ---------------
ASSETS
Current assets................................... $ 53,231 $ 43,909 $ - $ 97,140
Property and equipment........................... 545,500 275,812 - 821,312
Investment in subsidiaries (equity method)....... 222,129 2,202 (222,129) 2,202
Other assets..................................... 17,842 4,062 - 21,904
--------------- ------------- ------------- ---------------
Total assets................................ $ 838,702 $ 325,985 $ (222,129) $ 942,558
=============== ============= ============= ===============
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.............................. $ 84,804 $ 14,675 $ - $ 99,479
Long-term liabilities............................ 343,512 89,181 - 432,693
Stockholders' equity............................. 410,386 222,129 (222,129) 410,386
--------------- ------------- ------------- ---------------
Total liabilities and stockholders' equity.. $ 838,702 $ 325,985 $ (222,129) $ 942,558
=============== ============= ============= ===============
December 31, 2002
----------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
--------------- ------------- -------------- ---------------
ASSETS
Current assets................................... $ 111,063 $ 17,401 $ - $ 128,464
Property and equipment........................... 528,754 215,331 - 744,085
Investment in subsidiaries (equity method)....... 169,309 2,224 (169,309) 2,224
Other assets..................................... 16,881 3,638 - 20,519
--------------- ------------- -------------- ---------------
Total assets................................ $ 826,007 $ 238,594 $ (169,309) $ 895,292
=============== ============= ============== ===============
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.............................. $ 87,101 $ 8,778 $ - $ 95,879
Long-term liabilities............................ 372,109 60,507 - 432,616
Stockholders' equity............................. 366,797 169,309 (169,309) 366,797
--------------- ------------- -------------- ---------------
Total liabilities and stockholders' equity.. $ 826,007 $ 238,594 $ (169,309) $ 895,292
=============== ============= ============== ===============
16
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2003 (Unaudited)
-------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- -------------- ---------------
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 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
================ ============== ============== ===============
Three Months Ended September 30, 2002 (Unaudited)
-------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- -------------- ---------------
Revenues..................................... $ 61,264 $ 13,260 $ - $ 74,524
Expenses..................................... 41,381 11,525 - 52,906
---------------- -------------- -------------- ---------------
Income before the following: 19,883 1,735 - 21,618
Equity in net earnings of subsidiaries.. 1,016 2 (1,016) 2
---------------- -------------- -------------- ---------------
Income before income taxes................... 20,899 1,737 (1,016) 21,620
Income tax provision......................... 7,440 721 - 8,161
---------------- -------------- -------------- ---------------
Net income .................................. $ 13,459 $ 1,016 $ (1,016) $ 13,459
================ ============== ============== ===============
Nine Months Ended September 30, 2003 (Unaudited)
-------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- -------------- ---------------
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
================ ============== ============== ===============
17
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Nine Months Ended September 30, 2002 (Unaudited)
-------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- --------------- ---------------
Revenues..................................... $ 163,713 $ 39,691 $ - $ 203,404
Expenses..................................... 120,254 36,418 - 156,672
---------------- -------------- --------------- ---------------
Income before the following: 43,459 3,273 - 46,732
Equity in net earnings of subsidiaries.... 1,966 22 (1,966) 22
---------------- -------------- --------------- ---------------
Income before income taxes................... 45,425 3,295 (1,966) 46,754
Income tax provision......................... 13,922 1,329 - 15,251
---------------- -------------- --------------- ---------------
Net income .................................. $ 31,503 $ 1,966 $ (1,966) $ 31,503
================ ============== =============== ===============
Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2003 (Unaudited)
------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- ---------------
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
================= ============== ============== ===============
Nine Months Ended September 30, 2002 (Unaudited)
-------------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- ---------------
Cash flow from operations.................... $ 97,878 $ 5,105 $ - $ 102,983
Cash flow from investing activities.......... (130,690) (9,130) - (139,820)
Cash flow from financing activities.......... 36,265 - - 36,265
----------------- -------------- -------------- ---------------
Net increase (decrease) in cash.............. 3,453 (4,025) - (572)
Cash, beginning of period.................... 17,052 6,444 - 23,496
----------------- -------------- -------------- ---------------
Cash, end of period.......................... $ 20,505 $ 2,419 $ - $ 22,924
================= ============== ============== ===============
11. SUBSEQUENT EVENT - GENESIS TRANSACTIONS
Although we have not yet closed the transaction, we have reached agreement
to sell 167.5 Bcf of CO2 to Genesis Energy, L.P. for $24.9 million under a
volumetric production payment. We anticipate that the transaction will include
an assignment to Genesis of three of our existing long-term CO2 supply
agreements with our industrial customers, which represent approximately 60% of
our current industrial CO2 sales volumes. Pursuant to the proposed volumetric
production payment, Genesis could take up to 52.5 MMcf/d of CO2 through 2009,
43.0 MMcf/d of CO2 from 2010 through 2012 and 25.2 MMcf/d of CO2 to the end of
the production payment. The proposed transaction contemplates that we will
provide processing and transportation services to Genesis for a fee of $0.16 per
Mcf in connection with the delivery of CO2 to the industrial customers. We also
contemplate a separate transaction, wherein we would purchase approximately
689,000 partnership units of Genesis for $7.15 per unit for an aggregate
purchase price of $4.9 million, representing approximately 8% of Genesis' total
outstanding units. Although both transactions are subject to execution of
definitive agreements and third party consents, Denbury and Genesis have agreed
to the principal terms of the transactions, and we expect the transaction to
close during November 2003. We plan to use the estimated net cash proceeds of
approximately $20 million from these two transactions to reduce our bank debt.
18
DENBURY RESOURCES INC.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
- --------------------------------------------------------------------------------
You should read the following in conjunction with our financial statements
contained herein and our Form 10-K for the year ended December 31, 2002, along
with Management's Discussion and Analysis of Financial Condition and Results of
Operations contained in such Form 10-K. Any terms used but not defined in the
following discussion have the same meaning given to them in the Form 10-K.
We are a growing independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi, hold key operating acreage
onshore Louisiana and have a strong presence in the offshore Gulf of Mexico
areas. Our goal is to increase the value of acquired properties through a
combination of exploitation, drilling, and proven engineering extraction
processes. Our corporate headquarters are in Dallas, Texas, and we have three
primary field offices located in Houma and Covington, Louisiana, and Laurel,
Mississippi.
Debt Refinancing
In late March 2003, we issued $225 million of 7.5% Senior Subordinated
Notes due 2013 to refinance our $200 million of then existing 9% Senior
Subordinated Notes due 2008. The subordinated debt was refinanced to take
advantage of attractive interest rates and to extend the maturity of our
long-term debt an additional five years. We estimate that we will save
approximately $2.6 million per year in interest expense as a result of this
refinancing. The total cost of the refinancing was approximately $15.6 million,
consisting of the debt issue discount, underwriters' commission and other
expenses totaling approximately $6.6 million, and a $9.0 million call premium to
retire the old notes. We had a pre-tax charge to earnings in the second quarter
of 2003 of approximately $17.6 million from the early retirement of the old 9%
notes, made up of the $9.0 million call premium, the write-off of unamortized
discount of $4.8 million and debt issue costs of the old notes of $3.8 million.
The proceeds from the new issue were used to retire the old 9% subordinated
notes in April 2003 at the end of the required thirty day notice period to call
the old notes.
Genesis Transactions
Although we have not yet closed the transaction, we have reached agreement
to sell 167.5 Bcf of CO2 to Genesis Energy, L.P. for $24.9 million under a
volumetric production payment. We anticipate that the transaction will include
an assignment to Genesis of three of our existing long-term CO2 supply
agreements with our industrial customers, which represent approximately 60% of
our current industrial CO2 sales volumes. Pursuant to the proposed volumetric
production payment, Genesis could take up to 52.5 MMcf/d of CO2 through 2009,
43.0 MMcf/d of CO2 from 2010 through 2012 and 25.2 MMcf/d of CO2 to the end of
the production payment. The proposed transaction contemplates that we will
provide processing and transportation services to Genesis for a fee of $0.16 per
Mcf in connection with the delivery of CO2 to the industrial customers. We also
contemplate a separate transaction, wherein we would purchase approximately
689,000 partnership units of Genesis for $7.15 per unit for an aggregate
purchase price of $4.9 million, representing approximately 8% of Genesis' total
outstanding units. Although both transactions are subject to execution of
definitive agreements and third party consents, Denbury and Genesis have agreed
to the principal terms of the transactions, and we expect the transaction to
close during November 2003. We plan to use the estimated net cash proceeds of
approximately $20 million from these two transactions to reduce our bank debt.
CAPITAL RESOURCES AND LIQUIDITY
Focus on Debt Reduction
One of our primary financial goals during 2003 is to reduce our total debt
to approximately $300 million by year-end, a proposed $50 million reduction from
the $350 million outstanding as of December 31, 2002. This target was determined
by reviewing our leverage and setting a debt level that we thought would be
reasonable in the recent price environment. We generally measure leverage using
a debt-to-cash flow ratio, cash flow being defined as cash flow from operations.
Our target is a debt-to-cash flow ratio of 2 to 1 (or less), using a moderate
price deck, which we define as oil prices of around $25.00 per Bbl and natural
gas prices of around $3.50 per Mcf. Based on these price assumptions and
anticipated production levels, we projected that we could reach our target
during 2003 if our total debt was reduced to $300 million. As of September 30,
2003, our total debt was $329 million, consisting of $225 million of recently
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
issued 7.5% subordinated notes and $104 million of bank debt, but by the end of
November 2003, with the expected incremental proceeds from the Genesis
transactions (see "Genesis Transactions" above) and available cash generated
from operations, we expect our total debt to be between $300 and $305 million.
We expect to reduce this further by year-end, with an anticipated year-end
balance of around $300 million.
Since our last significant acquisition in the third quarter of 2002 (COHO),
we have used a portion of our cash flow from operations and proceeds from
property sales to reduce our bank debt. In addition to the anticipated $45 to
$50 million reduction during 2003 through the end of November, as outlined
above, we repaid approximately $25 million during the fourth quarter of 2002, or
a total of approximately $70 million of repayments during the last twelve
months. Furthermore, had $15.6 million not been used to pay for costs of our
subordinated debt refinancing in March 2003, that amount would have also been
used to reduce debt.
Sources and Uses of Capital Resources
During the first nine months of 2003, we generated approximately $145.8
million of cash flow from operations and generated an additional $29.3 million
of cash from sales of oil and gas properties. The largest single asset sale was
the sale of Laurel Field, acquired from COHO in August 2002, which netted us
approximately $26.1 million. In 2003 and over the last several years we have had
a policy of limiting our capital spending, excluding acquisitions, to an amount
equal to or less than our cash flow from operations. During the first nine
months of 2003, we have spent $108.1 million on oil and natural gas exploration
and development expenditures, $16.0 million on CO2 capital investments and
acquisitions, and approximately $11.5 million on oil and natural gas property
acquisitions, for total capital expenditures of $135.6 million. In addition,
during the first nine months of 2003 we incurred approximately $15.6 million of
costs in our subordinated debt refinancing (see "Debt Refinancing" above). The
$121.9 million of net total expenditures (including the $15.6 million of debt
refinancing costs) was funded by our cash flow from operations, with the excess
cash flow used to reduce our bank debt by approximately $21 million.
Bank Credit Facility
Our bank borrowing base was reaffirmed as of October 1, 2003 at $220
million, as part of the semi-annual review by our banks. During 2003, we amended
our credit agreement to increase the percentage of production we are allowed to
hedge, increasing the 2003 limitation to 90% of our forecasted production,
setting a maximum of 85% of our forecasted production from our proved reserves
for the current year (as defined in the amendment which may include up to 18
months), a maximum of 70% of forecasted production for the subsequent year, a
maximum of 55% of forecasted production for the third year and a maximum of 40%
of the forecasted production for the fourth year. We also amended the credit
agreement to allow our borrowings of up to $20 million in a bond issue from a
Mississippi governmental authority, resulting in the exemption or reduction of
sales and ad valorem taxes on CO2 facilities we build during the next two years
in Mississippi. This bond funding arrangement was completed in May 2003. Any
borrowings under this bond program will be purchased by the banks in our credit
facility, will become part of our outstanding borrowings under our credit line,
and will accrue interest and be repaid on the same basis as our bank line. Our
next bank borrowing base redetermination will be as of April 1, 2004, based on
December 31, 2003 assets. We do not anticipate any significant changes to our
borrowing base at this next review, although we cannot be certain, as there are
several subjective aspects to the borrowing base determination.
Capital Spending Forecast and Focus
We anticipate that our capital spending during 2003, excluding
acquisitions, will be equal to or less than our cash flow from operations, a
goal we have met each year since 1999. Our 2003 budget, excluding acquisitions,
is currently $154.2 million, including approximately $7.7 million of projects
carried over from 2002. Based on current projections, using futures prices in
place as of the first part of November 2003, this exploration and development
spending level is expected to be as much as $35 million below our 2003
forecasted cash flow. We have not formalized our 2004 capital budget, but
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
anticipate that it will initially be between $150 million and $175 million
(excluding acquisitions), at or slightly below our anticipated 2004 cash flow,
based on early November futures prices. Tentatively, we plan to strongly focus
on our CO2 operations, with approximately $20 million of 2004's capital budget
to be spent to develop additional CO2 reserves and deliverability for possible
future expansion of our CO2 tertiary floods to other areas, most likely East
Mississippi. This is likely to have the short-term impact of limiting our
production growth, although we believe it will provide long-term asset value for
our shareholders, as it is the first step in expanding our CO2 operations,
adding additional fields as CO2 flood candidates, and ultimately adding
additional potential oil reserves. We believe that this strategy will help us
build net asset value, a goal that is more important to us than production
increases. While we will not finalize our 2004 budget and models until December,
including integration of performance of our new offshore wells in the process of
being completed, based on our preliminary forecasts and plans, without assuming
better than our risked expectations for exploration success, it is possible that
we may not have significant production growth during 2004, and production could
potentially decrease slightly as compared to 2003 production levels. There is
also the possibility of further asset sales. Depletion is also a significant
factor, as our natural gas properties in both Louisiana and offshore have steep
decline rates due to their relatively short lives. As our focus shifts more
heavily toward our CO2 operations, which by their nature require greater time to
realize production increases, it may be difficult to organically grow our
production during the next year.
Although we have a significant inventory of development and exploration
projects in-house, on a long-term basis we will need to make acquisitions in
order to continue our growth and to replace our production. Our primary focus to
date in 2003 has been the purchase of incremental interest in fields that we
already own. We are also continuing to pursue other acquisitions, although
generally small in nature, with our primary focus on properties that are
potential tertiary flood candidates, along with properties where we see
additional potential based on our review of 3D seismic or other geologic and
geophysical data. Although we are continuing to review acquisitions in our other
core areas, including larger acquisitions, acquisitions are a lower priority for
us in 2003 than has been the case historically, given our substantial inventory
of projects in-house and our goal of reducing our debt level. We may increase
our acquisition focus slightly in 2004, as we expect to have achieved our 2003
debt target goal by year-end. Any acquisitions that we make will likely be
funded with either our excess cash flow or bank debt.
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet are
our operating leases, which primarily relate to our office space, minor
equipment, certain equipment at one CO2 processing facility, and various
obligations for development and exploratory expenditures arising from purchase
agreements or other transactions common to our industry. In addition, in order
to recover our undeveloped proved reserves, we must also fund the associated
future development costs forecast in our proved reserve reports. Further, one of
our subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed
the bank debt of Genesis (which as of September 30, 2003, consisted of $6.0
million of debt and $19.3 million in letters of credit, $4.1 million of which
are for Denbury's benefit) and we have delivery obligations to deliver CO2 to
our industrial customers. Since December 31, 2002, the significant changes to
our commitments and obligations include the refinancing of our subordinated debt
(see "Debt Refinancing" above), a $6.0 million lease financing of certain
equipment at our CO2 recycling facility at Mallalieu Field in August 2003, and
the expected sale of a volumetric CO2 production payment to Genesis in November
2003 (see "Genesis Transactions" above). Payments on this lease financing are
approximately $900,000 per year for the next seven years, with an option to
buyout the lease after six years. The volumetric production payment expected to
be sold to Genesis is not substantially different from our prior obligations to
our existing industrial customers whose contracts are expected to be transferred
in the transaction. Our hedging transactions and related obligations are
discussed in Note 9 to the Unaudited Condensed Consolidated Financial
Statements.
Otherwise, except as disclosed herein, neither the amounts nor the terms of
any other commitments or contingent obligations have changed significantly from
the year-end 2002 amounts reflected in our 2002 Form 10-K filed in March 2003.
Please refer to Management's Discussion and Analysis of Financial Condition and
Results of Operations contained in our 2002 Form 10-K for further information
regarding our commitments and obligations.
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
CO2 Operations
During late July and early August 2003, we upgraded our CO2 facility at
Jackson Dome, increasing the CO2 processing capacity of our facility by
approximately 50%, from around 200 MMcf/d to approximately 300 MMcf/d. This
upgrade was performed several months ahead of our original schedule in order to
handle the higher than expected production volumes from our CO2 wells drilled
during late 2002 and early 2003. At the same time, we increased the size of our
CO2 processing facility at Mallalieu Field, increasing the amount of CO2 that we
can recycle at that field from approximately 28 MMcf/d to approximately 108
MMcf/d. During July, we completed our third CO2 well drilled during the prior
twelve months, the Barksdale, which coupled with the upgraded Jackson Dome
facility, increases our CO2 production capability to approximately 220 MMcf/d,
approximately double our production capability in September 2002. Since our CO2
wells have been performing at higher production rates than originally
anticipated, the third CO2 well originally scheduled for mid-2003 has been
postponed until later in the year, currently scheduled to spud in late November
or early December 2003. Based on our inventory of potential tertiary recovery
projects, we will need to drill additional CO2 wells in 2004 and beyond to
further increase our CO2 production capability to an estimated target rate of
350 MMcf/d in order to develop the oil fields along our CO2 pipeline as planned.
In addition, we tentatively plan to expand our tertiary operations to other
parts of the region in the future, which we anticipate will require even higher
production levels and additional CO2 reserves. Tentatively, we plan to spend $20
million to $30 million in 2004 in the Jackson Dome area, over and above what is
currently required for our operations in Southwestern Mississippi, with the
intent to add additional CO2 reserves and deliverability for future operations.
Although we believe that our plans and projections are reasonable and
achievable, there could be unforeseen delays or problems which could delay our
overall tertiary development program. We believe that such delays, if any,
should only be temporary. As of December 31, 2002, based on a report prepared by
DeGolyer and MacNaughton, we estimate that we have approximately 1.6 trillion
cubic feet of usable CO2 reserves.
Oil production from our CO2 tertiary recovery activities decreased 7% from
second quarter 2003 levels to 4,227 Bbls/d in the third quarter of 2003,
representing approximately 23% of our total corporate oil production during the
third quarter of 2003. This decrease occurred primarily due to a curtailment of
CO2 production in the second quarter related to a leak in a newly installed CO2
pipeline and a one-week shutdown of CO2 production during the third quarter (see
above paragraph) while the facilities at Jackson Dome were upgraded. Our
experience has indicated that any time our CO2 production and associated
injections are curtailed, there is a corresponding drop in our oil production
from these projects. While our CO2 production capability is currently ahead of
schedule, as noted above, temporary curtailments have had a negative short-term
effect on our 2003 oil production. Recently we have been injecting more CO2 than
forecast, contributing to an increase in the related oil production, with a
preliminary production estimate of 5,400 Bbls/d during October 2003, a 28%
increase over our third quarter 2003 average. We expect this oil production to
continue to increase, although the increases are not always predictable or
consistent.
We spent approximately $0.19 per Mcf to produce our CO2 during the third
quarter of 2003, higher than the 2002 annual average of $0.13 per Mcf, primarily
due to higher royalty expenses, as certain of our royalty payments increase if
the price of oil increases beyond a certain threshold, and due to approximately
$700,000 of workover expenses on one CO2 well during the third quarter. The
higher overall CO2 production rates partially offset the workover expenses. The
higher cost per Mcf of CO2 during 2003 contributed to a corresponding increase
in the operating costs of our tertiary projects, as did higher electricity and
other expenses, as we continue to inject and recycle higher volumes of CO2 each
quarter. Furthermore at Mallalieu Field, in August 2003 we commenced lease
payments relating to a portion of the upgraded CO2 facilities there (see
"Commitments and Obligations" above). For the third quarter of 2003, our
operating costs for our tertiary properties averaged $12.53 per BOE, higher than
our 2002 annual average of $10.05 per BOE. Our tertiary recovery fields are
expected to average closer to $10 per BOE in operating expenses over the life of
the field, although the cost per BOE is usually higher at the beginning of each
operation, as there is a time lag between the initial injection of the CO2 into
the reservoir and the response of increased oil production. This compares to a
cost of around $5.00 per BOE for a more traditional oil property without
secondary or tertiary recovery operations.
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Results
Our operating results for the third quarter and first nine months of 2003,
as presented in the table below, were better than our results for the comparable
periods of the prior year, primarily due to higher commodity prices,
particularly natural gas, partially offset by higher overall expenses. During
the first quarter of 2003, we implemented SFAS No. 143, "Accounting for Asset
Retirement Obligations," as more fully discussed below under "Depletion,
Depreciation and Amortization" and in Note 3 to the Consolidated Financial
Statements. The adoption of SFAS No. 143 was recorded as a cumulative effect
adjustment of a change in accounting principle, net of income taxes, in our
Unaudited Condensed Consolidated Statements of Operations and is shown below on
both a gross dollar and per share basis.
Three Months Ended Nine Months Ended
September 30, September 30,
- ----------------------------------------------------------- --------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 2003 2002 2003 2002
- ----------------------------------------------------------- ------------ ------------- ------------- ------------
Income before cumulative effect of change in
accounting principle $ 15,149 $ 13,459 $ 38,731 $ 31,503
Cumulative effect of change in accounting principle,
net of income tax expense of $1,600 - - 2,612 -
------------ ------------- ------------- ------------
Net income $ 15,149 $ 13,459 $ 41,343 $ 31,503
- ----------------------------------------------------------- ------------ ------------- ------------- ------------
Net income per common share - basic:
Income before cumulative effect of change in
accounting principle $ 0.28 $ 0.25 $ 0.72 $ 0.59
Cumulative effect of change in accounting principle - - 0.05 -
------------ ------------- ------------- ------------
Net income per common share - basic $ 0.28 $ 0.25 $ 0.77 $ 0.59
- ----------------------------------------------------------- ------------ ------------- ------------- ------------
Net income per common share - diluted:
Income before cumulative effect of change in
accounting principle $ 0.27 $ 0.25 $ 0.70 $ 0.58
Cumulative effect of change in accounting principle - - 0.05 -
------------ ------------- ------------- ------------
Net income per common share - diluted $ 0.27 $ 0.25 $ 0.75 $ 0.58
- ----------------------------------------------------------- ------------ ------------- ------------- ------------
RECONCILIATION OF GAAP AND NON-GAAP MEASURES
- -----------------------------------------------------------
Adjusted cash flow from operations (see below) $ 45,611 $ 44,177 $ 141,966 $ 116,124
Net change in assets and liabilities relating to operations 4,178 202 3,874 (13,141)
- ----------------------------------------------------------- ------------ ------------- ------------- ------------
Cash flow provided by operations - GAAP Measure(1) $ 49,789 $ 44,379 $ 145,840 $ 102,983
- ----------------------------------------------------------- ------------ ------------- ------------- ------------
(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
summarized from our Consolidated Statements of Cash Flows. In our discussion of
cash flow from operations herein, we have elected to discuss the two primary
components of cash flow provided by operations 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 it can often be a better way to
discuss changes in operating trends in our business caused by changes in
production, prices, operating costs, and so forth, without regard to whether the
earned or incurred item was collected or paid during that period. We also use
this measure because the collection of our receivables or payment of our
obligations generally have not been a significant issue for us, 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.
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The net change in assets and liabilities relating to operations, is also
important, as it does require or provide additional cash for use in our
business; however, we prefer to discuss its effect separately. For instance, as
noted above, during the third quarter of 2003, approximately $4.2 million of
cash was generated from changes in our working capital balances, primarily
decreases in our accrued production receivables and trade and other receivables.
Similarly, we used a significant amount of cash in the first nine months of 2002
to fund a $13.1 million increase in working capital, primarily relating to a
significant reduction of our payables and accrued liabilities in early 2002
following a high level of drilling and exploitation activity late in 2001.
Certain of our operating results and statistics for the comparative first
nine months and third quarters of 2003 and 2002 are included in the following
table.
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------- -------------------------- -------------------------
2003 2002 2003 2002
- ------------------------------------------------------------- ------------- ------------ ------------- -----------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 18,051 18,930 18,852 18,201
Mcf 90,393 99,452 95,341 103,581
BOE (1) 33,116 35,506 34,742 35,465
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 44,863 $ 42,372 $ 140,998 $ 107,608
Natural gas sales 43,933 29,781 154,274 86,569
Gain (loss) on settlements of derivative contracts (12,031) (218) (53,072) 2,430
------------- ------------ ------------- -----------
Total oil and natural gas revenues $ 76,765 $ 71,935 $ 242,200 $ 196,607
------------- ------------ ------------- -----------
Lease operating expenses $ 22,400 $ 17,714 $ 67,850 $ 50,266
Production taxes and marketing expenses 3,761 2,969 11,124 8,880
------------- ------------ ------------- -----------
Total production expenses $ 26,161 $ 20,683 $ 78,974 $ 59,146
------------- ------------ ------------- -----------
CO2 sales to industrial customers $ 2,238 $ 2,182 $ 6,872 $ 5,568
CO2 operating costs 602 431 1,453 960
------------- ------------ ------------- -----------
CO2 operating margin $ 1,636 $ 1,751 $ 5,419 $ 4,608
------------- ------------ ------------- -----------
AVERAGE UNIT PRICES-INCLUDING IMPACT OF HEDGES
Oil price per barrel ("Bbl") $ 24.60 $ 24.18 $ 24.41 $ 21.70
Gas price per thousand cubic feet ("Mcf") 4.32 3.26 4.48 3.14
AVERAGE UNIT PRICES-EXCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 27.01 $ 24.33 $ 27.40 $ 21.66
Gas price per Mcf 5.28 3.25 5.93 3.06
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1):
Oil and natural gas revenues (before hedging) $ 29.14 $ 22.09 $ 31.13 $ 20.06
------------- ------------ ------------- -----------
Oil and gas lease operating costs $ 7.35 $ 5.43 $ 7.15 $ 5.19
Oil and gas production taxes and marketing expenses 1.23 0.91 1.17 0.92
------------- ------------ ------------- -----------
Total oil and gas production expenses $ 8.58 $ 6.34 $ 8.32 $ 6.11
- ------------------------------------------------------------- ------------- ------------ ------------- -----------
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Production: Average daily production by area for each of the quarters of
----------
2002 and the first, second and third quarters of 2003 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 2002 2002 2002 2002 2003 2003 2003
- --------------------------------- ----------- ------------ ------------ ------------- ------------- ----------- ------------
Mississippi - non-CO2 floods 12,423 12,124 13,232 15,703 14,537 13,600 13,367
Mississippi - CO2 floods 3,839 4,278 3,895 3,863 4,345 4,522 4,227
Onshore Louisiana 8,405 7,717 8,224 7,859 8,509 8,231 7,836
Offshore Gulf of Mexico 10,550 11,229 9,863 8,287 8,544 8,537 7,374
Other 144 178 292 182 158 160 312
----------- ------------ ------------ ------------- ------------- ----------- ------------
Total Denbury 35,361 35,526 35,506 35,894 36,093 35,050 33,116
- --------------------------------- ----------- ------------ ------------ ------------- ------------- ----------- ------------
Average daily BOE production for the third quarter of 2003 was
approximately 7% lower than the third quarter of 2002 average, due primarily to
production decreases in our offshore Gulf of Mexico properties and onshore
Louisiana properties, offset in part by production increases in our Mississippi
CO2 flood properties. In both the offshore and onshore Louisiana areas, we have
experienced general declines from normal depletion, along with delayed
production from equipment downtime and well workovers, with the single largest
decrease coming from Thornwell Field in Louisiana, which decreased approximately
1,900 BOE/d from third quarter 2002 levels. Although we have generally had good
success in our acquisition of Thornwell Field in 2000, we knew at that time that
it was relatively short-lived gas production that would fluctuate with the
amount of drilling activity. During 2003, our drilling activity at Thornwell was
significantly less than in prior years, contributing to the production decline.
Partially offsetting the large decrease onshore Louisiana from Thornwell Field
was the impact of our recent success in the Exxon Fee A-1 well in North Lirette
Field, which came on production late in the third quarter. A second well drilled
in that field commenced production early in the fourth quarter. While both are
prolific producers, they too are relatively short-lived wells and are expected
to decline in the near future. The increase in our Mississippi CO2 flood
properties is due primarily to increased production at Mallalieu Field, which
increased over 700 BOE/d from the prior year period due to the CO2 flood that we
initiated there during 2002.
When comparing production in the first nine months of 2002 and 2003,
production decreased by only 2% from the prior year period. The primary reason
for the decrease is a decline in offshore production of approximately 2,400
BOE/d due to normal depletion as discussed in the quarterly comparison above.
Also, consistent with the quarterly comparison above, we experienced declines at
Thornwell Field (onshore Louisiana) of approximately 1,300 BOE/d for the nine
month comparative periods; however increases from other onshore Louisiana fields
such as Lirette Field, Lake Gero Field and Bay Baptiste Field more than offset
the Thornwell Field decline. The single largest increase in production when
comparing the first nine months of 2002 and 2003 came from the acquisition of
COHO's Mississippi properties in August of 2002 (Mississippi - non-CO2 flood
properties), which added approximately 1,900 BOE/d (net of Laurel Field sold in
January 2003) as these properties were owned for the full nine months in 2003 as
compared to one month in 2002.
In addition to normal depletion and equipment and well failures
contributing to the overall decrease in our production when comparing the third
quarters and first nine months of 2002 and 2003 as discussed above, there are
other factors that have impacted our production. For example, we have had
temporary curtailments in our CO2 injection into our tertiary recovery fields at
least twice this year, which have delayed the response of additional oil
production from these projects (see CO2 Operations above), we have had less than
expected production increases from our exploration and development results
during the first half of 2003, and we have experienced unexpected delays in
drilling and completing offshore wells. Five offshore wells scheduled to be
drilled in the first seven months of 2003 were delayed while waiting for partner
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approvals, clearance of other logistical issues and negotitions with partners or
potential partners. As of November 1, 2003, three offshore and three onshore
wells were either drilling or expected to commence drilling within the ensuing
two weeks, although even if they are successful, these wells will not have a
meaningful impact to our production in 2003. Two offshore wells have been
drilled during the third quarter and early fourth quarter and were in the
completion process as of November 1, 2003, as were the two wells at North Padre
Island, our year-end 2002 discovery. The delay in these wells negatively
affected our third quarter production, although with anticipated production from
several of these wells, fourth quarter production should be higher than third
quarter production and in the range of 34,500 BOE/d to 35,500 BOE/d, depending
on completion dates and ultimate production rates of the five offshore wells
currently being completed. See "Capital Spending Forecast" in Capital Resources
and Liquidity above for a discussion of our tentative 2004 spending plans and
the potential impact of these plans on 2004 production.
Our production for the third quarter of 2003 was weighted slightly towards
oil (55%), and it appears that we will remain weighted slightly towards oil
throughout 2003, unless we make an acquisition that is predominately oil or
predominantly natural gas.
Oil and Natural Gas Revenues: Oil and natural gas revenues, net of hedge
----------------------------
receipts and payments, for the third quarter of 2003 increased $4.8 million, or
7%, from levels in the comparable quarter of 2002, but decreased when comparing
the third quarter of 2003 with the first two quarters of 2003. The increase in
oil and natural gas revenues when comparing the respective third quarters was
primarily due to the increase in commodity prices, which increased revenues by
$21.5 million, or 30%, from levels in the prior year quarter. This increase was
partially offset by a slight decrease in production volumes, which decreased
these revenues by $4.9 million, or 7%. In addition, significant losses on the
settlements of derivative contracts substantially reduced these revenues by
$11.8 million, or 16%, when comparing the respective third quarters.
Oil and natural gas revenues, net of hedge receipts and payments, for the
first nine months of 2003 increased $45.6 million, or 23%, from levels in the
comparable first nine months of 2002, also primarily due to the increase in
commodity prices, which increased revenues by $105.1 million, or 53%, from
levels in the first nine months of 2002. This increase was partially offset by a
slight decrease in production volumes between the respective first nine months,
causing only a decrease in revenues of $4.0 million or 2%. In addition,
significant losses on the settlements of derivative contracts reduced these
revenues by $55.5 million, or 28%, when comparing the two respective first nine
months.
Our realized natural gas prices (excluding hedges) for the third quarter
and first nine months of 2003 averaged $5.28 per Mcf and $5.93 per Mcf,
respectively, a 62% and 94% increase from the average of $3.25 per Mcf and $3.06
per Mcf realized during the third quarter and first nine months of 2002. Our
realized oil prices (excluding hedges) for the third quarter and first nine
months of 2003 averaged $27.01 per Bbl and $27.40 per Bbl, respectively, an 11%
and 27% increase from the $24.33 per Bbl and $21.66 per Bbl average realized in
the third quarter and first nine months of 2002. Under our hedges, we paid out a
sizable portion of our increase in revenues due to commodity prices, with cash
payments of $12.0 million on our hedges in the third quarter of 2003 and $53.1
million in the first nine months of 2003, as compared to cash payments of
$218,000 on our commodity hedges in the third quarter of 2002 and collections of
$2.4 million in the first nine months of 2002.
During 2002, we received an average discount to NYMEX prices on our oil
production of approximately $3.73 per Bbl, ranging from $3.30 to $4.25 per Bbl
on a quarterly basis. During 2003, the first quarter discount was $4.22 per Bbl,
the second quarter discount improved to $3.47 per Bbl, and the third quarter
discount further improved to $3.25 per Bbl, one of the lowest discounts we have
experienced in our recent corporate history. These compare to a discount of
$3.93 in the third quarter of 2002. These fluctuations have a significant impact
on our cash flow from quarter to quarter, as they directly impact our net
realized oil price. While this discount is difficult to predict, as it
fluctuates due to several different market factors, we would not expect it to
remain at the third quarter level for the rest of 2003. Long term, we expect our
average discount to gradually improve from our historically high levels, as a
larger percentage of our oil production will come from our tertiary recovery
operations, which produce a light, sweet oil that receives a price that
approximates NYMEX prices.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On a weighted average net price per BOE, we received $7.05 and $11.07 per
BOE more for our production (excluding hedges) in the third quarter and first
nine months of 2003, respectively, than in the comparable periods of 2002.
However, we paid out approximately $3.95 per BOE and $5.60 per BOE on our oil
and natural gas hedges in the same 2003 periods, respectively, as compared to
minor cash payments in the prior year quarter and cash receipts of $0.25 per BOE
in the prior year first nine months. Net of the hedging receipts and payments,
our net realized price was approximately $3.17 per BOE higher in the third
quarter of 2003 than in the third quarter of 2002, and approximately $5.22 per
BOE higher in the first nine months of 2003 than in the first nine months of
2002.
Production Expenses: Lease operating expenses increased to $7.35 per BOE
--------------------
and $7.15 per BOE in the third quarter and first nine months of 2003,
respectively, from $5.43 per BOE and $5.19 per BOE in the comparable periods of
2002, both of which were also higher than our fourth quarter 2002 average of
$6.34 per BOE. The costs of two workovers, relating to mechanical failures at
two onshore Louisiana gas wells, totaling approximately $850,000 in the first
quarter and $2.0 million in the second quarter of 2003, were the biggest source
of the increase in the first part of 2003, with several smaller workovers,
including one on a CO2 well (see "CO2 Operations" above), contributing to the
higher expense levels in the third quarter of 2003. Other factors contributing
to higher operating expenses in 2003 were continued high expenses on the
properties acquired from COHO, continued expansion of CO2 tertiary projects
(which typically have a higher than average lease operating cost per BOE), along
with higher lease fuel costs caused by high natural gas prices. The lower
production in 2003 also had a significant impact on per BOE rates. We anticipate
that our lease operating expenses on a per BOE basis will be lower during the
last quarter of the year, assuming a return to normal operating parameters.
Production taxes and marketing expenses also increased to $1.23 per BOE and
$1.17 per BOE in the third quarter and first nine months of 2003, respectively,
from $0.91 per BOE and $0.92 per BOE in the comparable periods of 2002,
primarily due to higher commodity prices.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 22% and 13% on a per
BOE basis between the respective third quarters and respective first nine
months, as set forth below:
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------- --------------------------------- --------------------------------
2003 2002 2003 2002
- ------------------------------------------- --------------- --------------- -------------- ---------------
NET G&A EXPENSE (THOUSANDS)
Gross G&A expenses $ 10,748 $ 9,691 $ 33,152 $ 28,671
State franchise taxes 378 342 1,099 1,070
Operator overhead charges (6,359) (5,708) (19,382) (16,256)
Capitalized exploration costs (1,322) (1,291) (4,257) (3,941)
--------------- --------------- -------------- ---------------
Net G&A expense $ 3,445 $ 3,034 $ 10,612 $ 9,544
--------------- --------------- -------------- ---------------
Average G&A expense per BOE $ 1.13 $ 0.93 $ 1.12 $ 0.99
Employees as of September 30 369 345 369 345
- ------------------------------------------- --------------- --------------- -------------- ---------------
Gross G&A expenses increased $1.1 million and $4.5 million, or 11% and 16%,
between the third quarters and first nine months of 2002 and 2003, respectively.
The largest components of this increase relate to expenses associated with the
recent sale of stock by the Texas Pacific Group in the first quarter of 2003,
higher year-end expenses than in the prior year for engineering fees and audit
fees, incremental expenses associated with the requirements of the
Sarbanes-Oxley Act and an overall increase in personnel and associated expenses.
Partially offsetting these increases was a reduction in the third quarter of
2003 of our bonus accrual, based on our expectations that bonuses will be less
in 2003 than in 2002 due to less positive operating results during 2003 in
certain areas. An increase in operator overhead recovery charges and
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
capitalized exploration costs in 2003 also partially offset the increase in
gross G&A. Our well operating agreements allow us, when we are the operator, to
charge a well with a specified overhead rate during the drilling phase and also
charge a monthly fixed overhead rate for each producing well. As a result of the
additional operated wells from our recent acquisitions and drilling activity
during the past year, the amount we recovered as operator overhead charges
increased by 11% and 19% between the respective third quarters and first nine
months of 2002 and 2003, respectively. Capitalized exploration costs increased
slightly between the comparable periods in 2002 and 2003, along with increases
in employees, employee related costs and certain administrative overhead costs.
The net effects of the increases in gross G&A expenses, operator overhead
recoveries and capitalized exploration costs were 14% and 11% increases in net
G&A expense between the respective third quarters and first nine months. On a
per BOE basis, G&A expenses increased 22% and 13% in the third quarter and first
nine months of 2003 as compared to the comparable periods of 2002, the higher
percentage increases resulting from the lower overall production levels.
Interest and Financing Expenses
Three Months Ended Nine Months Ended
September 30, September 30,
- ----------------------------------------------------- ----------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002 2003 2002
- ----------------------------------------------------- -------------- ------------- ------------ ------------
Interest expense $ 5,358 $ 6,860 $ 18,046 $ 20,086
Non-cash interest expense (226) (659) (1,025) (1,959)
-------------- ------------- ------------ ------------
Cash interest expense 5,132 6,201 17,021 18,127
Interest and other income (412) (407) (963) (1,229)
-------------- ------------- ------------ ------------
Net cash interest expense $ 4,720 $ 5,794 $ 16,058 $ 16,898
-------------- ------------- ------------ ------------
Average net cash interest expense per BOE $ 1.55 $ 1.77 $ 1.69 $ 1.75
Average interest rate (1) 6.2% 7.1% 6.5% 7.0%
Average debt outstanding $ 332,913 $ 351,087 $ 350,670 $ 345,395
- ----------------------------------------------------- -------------- ------------- ------------ ------------
(1) Includes commitment fees but excludes amortization of debt issue costs.
Interest expense for the third quarter of 2003 decreased from levels in the
comparable prior year period primarily due to (i) lower overall interest rates,
largely due to the refinancing of our subordinated debt (see "Debt Refinancing"
above), (ii) a 5% lower average outstanding debt balance during the third
quarter of 2003, and (iii) reduced debt issue cost amortization resulting from
the complete amortization of costs associated with the original maturity of our
bank credit line in December 2002. For the first nine months of 2003, our
average debt levels were higher, primarily because both issues of subordinated
debt were outstanding for 16 days during the second quarter due to the mechanics
of the required 30 day notice to call the old subordinated notes.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depletion, Depreciation and Amortization
Three Months Ended Nine Months Ended
September 30, September 30,
- ---------------------------------------------------- ----------------------------- -----------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002 2003 2002
- ---------------------------------------------------- ------------- ------------- ------------- --------------
Depletion and depreciation $ 20,805 $ 21,376 $ 64,234 $ 64,975
Depreciation of CO2 assets 635 521 1,665 1,660
Accretion of discount on asset retirement obligations 752 - 2,255 -
Site restoration provision - 702 - 2,265
Depreciation of other fixed assets 374 432 1,095 1,262
------------- ------------- ------------- --------------
Total DD&A $ 22,566 $ 23,031 $ 69,249 $ 70,162
------------- ------------- ------------- --------------
DD&A per BOE:
Oil and natural gas properties $ 7.08 $ 6.76 $ 7.01 $ 6.95
CO2 assets and other fixed assets 0.33 0.29 0.29 0.30
------------- ------------- ------------- --------------
Total DD&A cost per BOE $ 7.41 $ 7.05 $ 7.30 $ 7.25
- --------------------------------------------------- ------------- ------------- ------------- --------------
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis increased $0.05 per BOE in the first nine months of 2003 as
compared to the first nine months of 2002, based on our revised estimate of
reserves, production and expenditures for 2003. Our DD&A rate is evaluated each
quarter and is adjusted to our best estimate of projected reserves at year-end,
and estimated production and capital expenditures for the full year. Based on
the ultimate outcome of these factors, we adjust our DD&A computation for the
full year in the fourth quarter. Although our exploration results in the first
half of 2003 were not as good as expected, we have had recent success in a new
discovery at North Lirette Field in Louisiana, and successful wells at Brazos
A-21 and West Cameron 192, both offshore Gulf of Mexico, and we have up to an
additional six exploratory wells planned for the remainder of 2003, although
it is possible that some or all of these wells may not be completed and
evaluated by year-end. Also, we are in the process of preparing our 2004
exploration and development program, which will include an expansion of our
tertiary recovery properties. We expect that we will be able to add additional
proved reserves related to these new tertiary projects by year-end, but have not
yet quantified these amounts, nor finalized our 2004 budget. Based on our
current estimates related to these items and the uncertain timing and results of
these last few exploration wells, we have increased our DD&A rate slightly from
the level in the first two quarters of 2003. However, depending on the outcome
of these estimates and other factors that could change before year-end 2003, our
DD&A rate could change significantly in the last quarter of 2003.
Effective January 1, 2003, we adopted Statement of Financial Accounting
Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143 requires that the fair value of a liability for an asset retirement
obligation be recorded in the period in which it is incurred, discounted to its
present value using our credit adjusted risk- free interest rate, and that the
corresponding amount be capitalized by increasing the carrying amount of the
related long- lived asset. The liability is accreted each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, the
difference is recorded to the full cost pool, unless significant. The adoption
of this statement resulted in a $2.6 million benefit to net income during the
first quarter of 2003 and was recorded as a cumulative effect of a change in
accounting principle in our Consolidated Statements of Operations. As part of
the adoption, we ceased accruing for site reclamation costs, as had been our
practice in the past, and recorded a $41.0 million liability representing the
estimated present value of our retirement obligations, with a $34.4 million
increase to oil and natural gas properties. On an undiscounted basis, we
estimated our retirement obligations as of January 1, 2003 to be $81.8 million,
with an estimated salvage value of $43.3 million, also on an undiscounted basis.
DD&A is calculated on the increase to oil and natural gas properties, net of
estimated salvage value. We also include the accretion of discount on the asset
retirement obligation in our DD&A expense.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
Three Months Ended Nine Months Ended
September 30, September 30,
- ---------------------------------------------------------- ------------------------- ---------------------------
AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS AND TAX RATES 2003 2002 2003 2002
- ---------------------------------------------------------- ------------ ----------- ------------ ------------
Current income tax expense (benefit) $ (1,514) $ 20 $ 123 $ (428)
Deferred income tax expense 9,064 8,141 18,946 15,679
------------ ----------- ------------ ------------
Total income tax expense $ 7,550 $ 8,161 $ 19,069 $ 15,251
------------ ----------- ------------ ------------
Average income tax expense per BOE $ 2.48 $ 2.50 $ 2.01 $ 1.58
Effective tax rate 33.3% 37.7% 33.0% 32.6%
- ---------------------------------------------------------- ------------ ----------- ------------ ------------
Our income tax provision for the 2002 periods was based on an estimated
effective tax rate of 38%. The net effective tax rate was lower than the
statutory rates, primarily due to the recognition of enhanced oil recovery
credits which lowered our overall tax expense. During 2002, we utilized
alternative minimum tax loss carryforwards, virtually eliminating our current
tax expense. The current income tax credit in the first nine months of 2002 was
the result of a tax law change that allowed us to offset 100% of our 2001
alternative minimum taxes with our alternative minimum tax net operating loss
carryforwards. Prior to the law change, we were able to offset only 90% of our
alternative minimum taxes with these carryforwards. This change resulted in a
reclassification of tax expense between current and deferred taxes and did not
impact our overall effective tax rate. As of January 1, 2003, we had utilized
virtually all of the alternative minimum tax carryforwards and thus recognized
current income tax expense for the projected alternative minimum taxes that are
expected to be incurred during 2003. We recognized a current income tax credit
of $1.5 million in the 2003 third quarter due to a downward revision in our 2003
forecast of taxable income.
Per BOE Data
The following table summarizes the cash flow, DD&A and results of
operations on a per BOE basis for the comparative periods. Each of the
individual components are discussed above.
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- --------------------------
Per BOE Data 2003 2002 2003 2002
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Revenue $ 29.14 $ 22.09 $ 31.13 $ 20.06
Gain (loss) on settlements of derivative contracts (3.95) (0.07) (5.60) 0.25
Lease operating expenses (7.35) (5.43) (7.15) (5.19)
Production taxes and marketing expenses (1.23) (0.91) (1.17) (0.92)
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Production netback 16.61 15.68 17.21 14.20
Operating cash flow from CO2 operations 0.54 0.54 0.57 0.48
General and administrative expenses (1.13) (0.93) (1.12) (0.99)
Net cash interest expense (1.55) (1.77) (1.69) (1.75)
Current income taxes and other 0.50 - - 0.05
Changes in assets and liabilities 1.37 0.06 0.40 (1.35)
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Cash flow from operations 16.34 13.58 15.37 10.64
DD&A (7.41) (7.05) (7.30) (7.25)
Deferred income taxes (2.97) (2.49) (2.00) (1.62)
Amortization of derivative contracts and other non-cash
hedging adjustments 0.47 0.35 0.39 0.35
Early retirement of subordinated debt - - (1.86) -
Cumulative effect of a change in accounting principle - - 0.28 -
Changes in assets and liabilities and other non-cash items (1.46) (0.27) (0.52) 1.13
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
Net income $ 4.97 $ 4.12 $ 4.36 $ 3.25
- ---------------------------------------------------------- ------------- ------------- ------------ ------------
30
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NEW ACCOUNTING STANDARDS
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," became effective July 1, 2001 and January 1, 2002,
respectively. It is our understanding that the Securities and Exchange
Commission has raised questions as to the proper application by registrants in
the oil and gas industry of the provisions of SFAS No. 141 and SFAS No. 142 and
has referred this question to the Emerging Issues Task Force of the FASB. In
question is whether the acquisition of 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. Currently,
Denbury, and virtually all other companies in the oil and gas industry, have
historically included purchased contractual mineral rights in oil and gas
properties on their balance sheets. Until we receive further guidance regarding
this issue, we will continue to include mineral interests as oil and gas
properties on our balance sheet for mineral interests acquired subsequent to
September 30, 2001. Based on the limited guidance pertaining to this issue, we
have not calculated any potential balance sheet reclassification at this time.
The provisions of SFAS No. 141 and 142 impact only the balance sheet and
associated footnote disclosure, and any reclassifications, if necessary, would
not impact the Company's results of operations or cash flows.
In January 2003, the FASB issued Interpretation No. 46 "Consolidation of
Variable Interest Entities." The Interpretation will significantly change
whether entities included in its scope are consolidated by their sponsors,
transferors, or investors. An entity is considered to be a variable interest
entity when either (i) the entity lacks sufficient equity to carry on its
principal operations, (ii) the equity owners of the entity cannot make decisions
about the entity's activities, or (iii) the entity's equity neither absorbs
losses nor benefits from gains. These provisions apply immediately to variable
interests in Variable Interest Entities ("VIEs") created after January 15, 2003,
and were originally slated to be effective in the third quarter of 2003 for VIEs
in which a company holds a variable interest that it acquired prior to February
1, 2003. At the October 8, 2003 FASB meeting, the FASB agreed to a deferral of
the effective date for VIEs created before February 1, 2003 until the first
reporting period ended after December 15, 2003. Subsequent to January 31, 2003,
we have not acquired an interest in any VIEs that would require immediate
consolidation under Interpretation No. 46. We are currently evaluating our
financial arrangements to determine whether any VIEs existed prior to January
31, 2003.
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.
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Expected Maturity Dates
- ---------------------------------------- ------------------------------------------------ ----------- -----------
Carrying Fair
Amounts in Thousands 2003-2005 2006 2007 Thereafter Value Value
- ---------------------------------------- ----------- ----------- ------------ ----------- ----------- -----------
Variable rate debt:
Bank debt.......................... $ - $ 104,000 $ - $ - $ 104,000 $ 104,000
(The weighted-average interest rate on the bank debt at September 30, 2003 was 3.0%.)
Fixed rate debt:
7.5% subordinated debt, net of
discount, due 2013.............. $ - $ - $ - $ 225,000 $ 223,154 $ 225,000
(The interest rate on the subordinated debt is a fixed rate of 7.5%.)
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. We generally attempt to hedge between 50% and 75% of our
anticipated production each year to provide us with a reasonably certain amount
of cash flow to cover most of our budgeted exploration and development
expenditures without incurring significant debt. When we make an acquisition, we
attempt to hedge a large percentage, up to 100%, of the forecasted production
for the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. Our recent hedging activity
has been predominately through the purchase of collars, although for the recent
COHO acquisition, we also used swaps in order to lock in the prices used in our
economic forecasts. As the result of a sale of a portion of the COHO properties
in early 2003, our hedges have covered over 85% of our production during the
first nine months of 2003. All of the mark-to-market valuations used for our
financial derivatives are provided by external sources and are based on prices
that are actively quoted. We manage and control market and counter party credit
risk through established internal control procedures which are reviewed on an
ongoing basis. We attempt to minimize credit risk exposure to counter parties
through formal credit policies, monitoring procedures, and diversification.
At September 30, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $35.5 million, a decrease of
approximately $100,000 from the $35.6 million fair value liability recorded as
of December 31, 2002. This change is the result of the expiration of certain
derivative contracts during 2003 for which we recorded amortization expense of
$891,000, partially offset by an increase in the fair market value liability of
the remaining hedges due to an increase in oil and natural gas commodity prices
between December 31, 2002 and September 30, 2003. Information regarding our
current hedging positions is included in Note 9 to the Unaudited Condensed
Consolidated Financial Statements.
Based on NYMEX natural gas futures prices at September 30, 2003, we would
expect to make future cash payments of $10.5 million on our natural gas
commodity hedges. If natural gas futures prices were to decline by 10%, the
amount we would expect to pay under our natural gas commodity hedges would
decrease to $3.0 million, and if futures prices were to increase by 10% we would
expect to pay $19.5 million. Based on NYMEX crude oil futures prices at
September 30, 2003, we would expect to pay $15.4 million on our crude oil
commodity hedges. If crude oil futures prices were to decline by 10%, we would
expect to pay $4.4 million, and if crude oil futures prices were to increase by
10%, we would expect to pay $28.0 million under our crude oil commodity hedges.
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to
property, plant and equipment, depletion and depreciation, oil and natural gas
reserves and hedging activities, and which remain unchanged, see "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, 2002.
32
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q ("Quarterly
Report") that are not historical facts, including, but not limited to,
statements found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, acquisition plans and proposals and dispositions, development
activities, cost savings, production efforts and volumes, hydrocarbon reserves,
hydrocarbon prices, CO2 production and deliverability, liquidity, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "estimate," "budgeted," "expect,"
"predict," "anticipate," "projected," "should," "assume," "believe" or other
words that convey the uncertainty of future events or outcomes. Such
forward-looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and our financial condition and results of
operations. As a consequence, actual results may differ materially from
expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for our oil and natural gas, the uncertainty of
drilling results and reserve estimates, operating hazards, acquisition risks,
requirements for capital, general economic conditions, competition and
government regulations, as well as the risks and uncertainties discussed in this
Quarterly Report, including, without limitation, the portions referenced above,
and the uncertainties set forth from time to time in the Company's other public
reports, filings and public statements.
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 6. Exhibits and Reports on Form 8-K during the Third Quarter of 2003
- --------------------------------------------------------------------------
Exhibits:
--------
15* Letter from Independent Accountants as to unaudited interim financial information.
31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
* Filed herewith.
Reports on Form 8-K:
-------------------
On July 31, 2003, we filed a Form 8-K which included our press release on
our second quarter 2003 earnings.
On August 12, 2003, we filed a Form 8-K that announced that Denbury had
adopted a pre-determined stock repurchase plan to purchase shares of its common
stock on the New York Stock Exchange in order for such repurchased shares to be
made available for purchase by employees under Denbury's Employee Stock Purchase
Plan.
On September 22, 2003, we filed a form 8-K that announced that David
Bonderman, without any disagreement with the Company or its management, resigned
as a director of Denbury Resources Inc.
34
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 12, 2003
35