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, 2005
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 1-12935
______________________
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 20-0467835
(State or other jurisdictions of (I.R.S. Employer
incorporation or organization) Identification No.)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal executive (Zip code)
offices)
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, 2005
----- -------------------------------
Common Stock, $.001 par value 114,564,508
INDEX
Page
----
Part I. Financial Information
- ------------------------------
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at September 30, 2005 and
December 31, 2004 3
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2005 and 2004 4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Nine
Months Ended September 30, 2005 and 2004 5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for
the Three and Nine Months Ended September 30, 2005 and 2004 6
Notes to Unaudited Condensed Consolidated Financial Statements 7-19
Item 2. Management's Discussion and Analysis of Financial Condition of Operations
and Results of Operations 20-35
Item 3. Quantitative and Qualitative Disclosures about Market Risk 35
Item 4. Controls and Procedures 35-36
Part II. Other Information
- ---------------------------
Item 1. Legal Proceedings 36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 36
Item 3. Defaults Upon Senior Securities 36
Item 4. Submission of Matters to a Vote of Security Holders 36
Item 5. Other Information 36
Item 6. Exhibits 37
Signatures 37
2
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
September 30, December 31,
2005 2004
-------------- --------------
Assets
Current assets
Cash and cash equivalents $ 36,990 $ 33,039
Short-term investments - 57,171
Accrued production receivables 55,567 44,790
Related party receivable - Genesis 1,062 745
Trade and other receivables 14,189 10,963
Deferred tax asset 35,421 25,189
Derivative assets - 949
-------------- -------------
Total current assets 143,229 172,846
-------------- -------------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,584,092 1,326,401
Unevaluated 49,187 20,253
CO2 properties and equipment 180,619 132,685
Other 32,361 25,929
Less accumulated depletion and depreciation (776,773) (707,906)
-------------- -------------
Net property and equipment 1,069,486 797,362
-------------- -------------
Investment in Genesis 6,669 6,791
Other assets 10,791 15,707
-------------- -------------
Total assets $ 1,230,175 $ 992,706
============== =============
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 70,316 $ 49,429
Current deferred revenue and other - Genesis 2,432 2,431
Oil and gas production payable 30,108 24,856
Derivative liabilities 11,390 5,815
Short-term capital lease obligations - Genesis 560 375
-------------- -------------
Total current liabilities 114,806 82,906
-------------- -------------
Long-term liabilities
Capital lease obligations - Genesis 6,018 4,184
Long-term debt 243,543 223,397
Asset retirement obligations 24,078 18,944
Deferred revenue - Genesis 21,404 23,378
Deferred tax liability 145,823 97,125
Other 2,222 1,100
-------------- -------------
Total long-term liabilities 443,088 368,128
-------------- -------------
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized,
none issued and outstanding - -
Common stock, $.001 par value, 250,000,000 shares authorized;
114,927,186 and 56,607,877 shares issued at September 30, 2005
and December 31, 2004, respectively 115 57
Paid-in capital in excess of par 459,821 441,023
Deferred compensation (18,860) (21,678)
Retained earnings 238,389 129,104
Accumulated other comprehensive loss (1,384) (4,788)
Treasury stock, at cost, 371,694 and 93,072 shares at
September 30, 2005 and December 31, 2004, respectively (5,800) (2,046)
-------------- -------------
Total stockholders' equity 672,281 541,672
-------------- -------------
Total liabilities and stockholders' equity $ 1,230,175 $ 992,706
============== =============
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ----------------------------
2005 2004 2005 2004
------------- ------------- -------------- -------------
Revenues and other income
Oil, natural gas and related product sales
Unrelated parties $ 137,137 $ 82,502 $ 371,947 $ 269,482
Related party - Genesis 1,411 20,566 3,389 62,893
CO2 sales and transportation fees
Unrelated parties 1,119 307 1,583 910
Related party - Genesis 1,475 1,374 4,258 3,712
Loss on effective hedge contracts - (17,465) - (46,457)
Interest income and other 716 701 2,026 1,450
------------- ------------- -------------- -------------
Total revenues and other income 141,858 87,985 383,203 291,990
------------- ------------- -------------- -------------
Expenses
Lease operating expenses 25,983 19,781 75,702 66,839
Production taxes and marketing expenses 5,995 4,634 16,713 13,215
Transportation expense - Genesis 1,023 266 3,013 266
CO2 operating expenses 631 255 1,422 608
General and administrative expenses 8,952 6,197 21,439 15,123
Interest, net of amounts capitalized of $415, none, $1,049
and none, respectively 4,507 4,768 13,318 14,917
Depletion and depreciation 24,340 20,780 70,273 76,265
Commodity derivative expense 11,818 5,161 18,614 16,640
------------- ------------- -------------- -------------
Total expenses 83,249 61,842 220,494 203,873
------------- ------------- -------------- -------------
Equity in net income (loss) of Genesis (55) (37) 276 (28)
------------- ------------- -------------- -------------
Income before income taxes 58,554 26,106 162,985 88,089
Income tax provision (benefit)
Current income taxes 7,684 18,949 17,320 22,045
Deferred income taxes 12,324 (11,117) 36,380 6,077
------------- ------------- -------------- -------------
Net income $ 38,546 $ 18,274 $ 109,285 $ 59,967
============= ============= ============== =============
Net income per common share - basic $ 0.34 $ 0.17 $ 0.98 $ 0.55
Net income per common share - diluted $ 0.32 $ 0.16 $ 0.92 $ 0.53
Weighted average common shares outstanding
Basic 112,159 110,170 111,466 109,480
Diluted 119,487 115,098 119,098 114,040
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- ---------------------------
2005 2004 2005 2004
------------ ------------ ------------- -------------
Cash flow from operating activities:
Net income $ 38,546 $ 18,274 $ 109,285 $ 59,967
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation and depletion 24,340 20,780 70,273 76,265
Non-cash hedging adjustments 8,054 383 11,975 8,347
Deferred income taxes 12,324 (11,117) 36,380 6,077
Deferred revenue - Genesis (682) (648) (1,974) (1,758)
Deferred compensation - restricted stock 1,031 593 3,090 593
Current income tax benefit from stock options 3,242 988 8,676 988
Amortization of debt issue costs and other 491 494 1,003 1,242
Changes in assets and liabilities:
Accrued production receivable (3,700) (412) (11,094) (11,248)
Trade and other receivables 5,284 5,635 (3,226) 3,862
Derivative assets and liabilities - - - (7,518)
Other assets - (32) 130 (32)
Accounts payable and accrued liabilities (13,546) 15,552 2,272 16,263
Oil and gas production payable 955 (4,280) 5,253 748
Other liabilities (52) (1,444) (742) (2,825)
------------ ------------ ------------- -------------
Net cash provided by operations 76,287 44,766 231,301 150,971
------------ ------------ ------------- -------------
Cash flow used for investing activities:
Oil and natural gas expenditures (72,020) (35,981) (210,900) (125,745)
Acquisitions of oil and gas properties (2,700) (1,663) (71,244) (3,861)
Increase in accrual for capital expenditures 10,878 - 19,868 -
Acquisitions of CO2 assets and capital expenditures (14,751) (15,825) (49,869) (42,966)
Net proceeds from CO2 production payment - Genesis - 4,636 - 4,636
Sale of Denbury Offshore, Inc. - 186,753 - 186,753
Purchases of other assets (1,057) (1,753) (4,156) (2,907)
Proceeds from property sales 1,888 380 1,865 1,526
Deposits on oil and gas property acquisitions - - 4,507 -
Purchases of short-term investments - (31,957) - (31,957)
Sales of short-term investments 2,000 - 57,133 -
Increase in restricted cash (78) (119) (188) (470)
------------ ------------ ------------- -------------
Net cash provided by (used by) investing activities (75,840) 104,471 (252,984) (14,991)
------------ ------------ ------------- -------------
Cash flow from financing activities:
Bank repayments - (85,000) (19,800) (88,000)
Bank borrowings 10,000 - 39,800 13,000
Payments on capital lease obligations - Genesis (132) - (386) -
Issuance of common stock 3,314 2,425 11,139 11,099
Purchase of treasury stock (1,955) (1,052) (5,119) (2,713)
Costs of debt financing - (408) - (412)
------------ ------------ ------------- -------------
Net cash provided by (used by) financing activities 11,227 (84,035) 25,634 (67,026)
------------ ------------ ------------- -------------
Net increase in cash and cash equivalents 11,674 65,202 3,951 68,954
Cash and cash equivalents at beginning of period 25,316 27,940 33,039 24,188
------------ ------------ ------------- -------------
Cash and cash equivalents at end of period $ 36,990 $ 93,142 $ 36,990 $ 93,142
============ ============ ============= =============
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 374 $ 176 $ 9,280 $ 9,639
Cash paid during the period for income taxes 1,500 13,000 9,000 13,327
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2005 2004 2005 2004
------------- ------------ ------------- ------------
Net income $ 38,546 $ 18,274 $ 109,285 $ 59,967
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts, net of tax of
$(8,916) and $(21,586), respectively - (14,547) - (35,220)
Reclassification adjustments related to settlements of derivative
contracts, net of tax of $713, $9,704, $2,072, and $25,474, respectively 1,163 15,833 3,380 41,563
Unrealized gain (loss) on securities available for sale - (9) 24 (9)
------------- ------------ ------------- ------------
Comprehensive income $ 39,709 $ 19,551 $ 112,689 $ 66,301
============= ============ ============= ============
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of
Denbury Resources Inc. and its subsidiaries have been prepared in accordance
with the instructions to Form 10-Q and do not include all of the information and
footnotes required by accounting principles generally accepted in the United
States for complete financial statements. Unless indicated otherwise or the
context requires, the terms "we," "our," "us," "Denbury" or "Company" refer to
Denbury Resources Inc. and its subsidiaries. These financial statements and the
notes thereto should be read in conjunction with our Annual Report on Form 10-K
for the year ended December 31, 2004. Any capitalized terms used but not defined
in these Notes to Unaudited Condensed Consolidated Financial Statements have the
same meaning given to them in the Form 10-K.
Accounting measurements at interim dates inherently involve greater
reliance on estimates than at year end and the results of operations for the
interim periods shown in this report are not necessarily indicative of results
to be expected for the fiscal year. In management's opinion, the accompanying
unaudited condensed consolidated financial statements include all adjustments
(of a normal recurring nature) necessary to present fairly the consolidated
financial position of Denbury as of September 30, 2005 and the consolidated
results of its operations and cash flows for the three and nine month periods
ended September 30, 2005 and 2004. Certain prior period items have been
reclassified to make the classification consistent with the classification in
the most recent quarter.
Stock Split
On October 19, 2005, stockholders of Denbury Resources Inc. approved an
amendment to our Restated Certificate of Incorporation to increase the number of
shares of our authorized common stock from 100,000,000 shares to 250,000,000
shares and to split our common stock on a 2-for-1 basis. Stockholders of record
on October 31, 2005, received one additional share of Denbury common stock for
each share of common stock held at that time. Information pertaining to shares
and earnings per share has been retroactively adjusted in the accompanying
financial statements and related notes thereto to reflect the stock split.
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, 2005 and 2004, 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, 2005 and 2004.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- --------------------------
(Shares in Thousands) 2005 2004 2005 2004
---------------- -------------- ------------- ------------
Weighted average common shares - basic....... 112,159 110,170 111,466 109,480
Potentially dilutive securities:
Stock options.............................. 6,264 4,868 6,691 4,560
Restricted stock........................... 1,064 60 941 -
---------------- -------------- ------------- ------------
Weighted average common shares - diluted..... 119,487 115,098 119,098 114,040
================ ============== ============= ============
The weighted average common shares - basic amount in 2005 excludes
2,018,000 shares of non-vested restricted stock granted in 2005 and 2004 that is
subject to future time vesting requirements. As these restricted shares vest,
they will be included in the shares outstanding used to calculate basic net
income per common share. For purposes of calculating weighted average common
shares - diluted, the non-vested restricted stock is included in the computation
using the treasury stock method, with the proceeds equal to the average
unrecognized compensation during the period, adjusted for any estimated future
7
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
tax consequences recognized directly in equity. The restricted shares were
issued in August 2004 through January 2005 and have been included in the
calculation for the periods they were outstanding. These shares may result in
greater dilution in future periods, depending on the market price of our common
stock during those periods.
For the three months ended September 30, 2005 and 2004, stock options to
purchase approximately 131,000 and 64,000 shares of common stock, and for the
nine months ended September 30, 2005 and 2004, stock options to purchase
approximately 304,000 and 126,000 shares of common stock, respectively, were
outstanding but excluded from the diluted net income per common share
calculations, as the exercise prices of the options exceeded the average market
price of the Company's common stock during these periods and would be
anti-dilutive to the calculations.
Stock-based Compensation
We issue stock options to all of our employees under our stock option plans
and we have issued restricted stock to our officers and directors. We account
for this stock-based compensation 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 no
stock-based employee compensation expense for stock options is reflected in net
income as long as the stock options have an exercise price equal to the price of
the underlying common stock on the date of grant. We recognize compensation
expense for restricted stock over the applicable vesting periods. The following
table illustrates the effect on net income and net income per common share as if
we had applied the fair value recognition and measurement provisions of
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for
Stock-Based Compensation," as amended by SFAS No. 148, in accounting for our
stock options.
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- --------------------------
2005 2004 2005 2004
------------ ------------ ------------- ------------
Net income: (thousands)
Net income, as reported................................. $ 38,546 $ 18,274 $ 109,285 $ 59,967
Add: stock-based compensation included in reported
net income, net of related tax effects................ 679 368 2,073 368
Less: stock-based compensation expense applying fair
value based method, net of related tax effects ....... 2,152 1,155 5,627 2,229
------------ ------------ ------------- ------------
Pro-forma net income ................................... $ 37,073 $ 17,487 $ 105,731 $ 58,106
============ ============ ============= ============
Net income per common share
As reported:
Basic ................................................ $ 0.34 $ 0.17 $ $ 0.98 $ 0.55
Diluted............................................... 0.32 0.16 0.92 0.53
Pro forma:
Basic ................................................ $ 0.33 $ 0.16 $ $ 0.95 $ 0.53
Diluted .............................................. 0.31 0.15 0.90 0.51
Derivative Instruments and Hedging Activities
Effective January 1, 2005, we elected to discontinue hedge accounting for
our oil and natural gas derivative contracts. See Note 5 for further discussion
regarding this change.
Short-term Investments
During the first nine months of 2005, we sold all of our available-for-sale
securities.
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Recent Accounting Pronouncements
On December 16, 2004, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R)
supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally,
the approach in SFAS No. 123(R) is similar to the approach described in SFAS No.
123. However, SFAS No. 123(R) will require all share-based payments to
employees, including grants of employee stock options, to be recognized in our
Consolidated Statements of Operations based on their estimated fair values. Pro
forma disclosure is no longer an alternative.
SFAS No. 123(R) must be adopted at the beginning of our next fiscal year
(i.e., January 1, 2006) and permits public companies to adopt its requirements
using one of two methods:
o A "modified prospective" method in which compensation cost is
recognized based on the requirements of SFAS No. 123(R) for all
share-based payments granted prior to the effective date of SFAS No.
123(R) that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of
the modified prospective method described above, but also permits
entities to restate either all prior periods presented or prior
interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
As permitted by SFAS No. 123, we currently account for share-based payments
to employees using the intrinsic value method prescribed by APB 25 and related
interpretations. As such, we generally do not recognize compensation expense
associated with employee stock options. Accordingly, the adoption of SFAS No.
123(R)'s fair value method could have a significant impact on Denbury's future
results of operations, although it will have no impact on our overall financial
position. We currently plan to adopt the provisions of SFAS No. 123(R) on
January 1, 2006 using the modified prospective approach. We have not completed
evaluating the impact the adoption of SFAS No. 123(R) will have on our future
results of operations.
SFAS No. 123(R) also requires the tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce Denbury's future cash provided by operating activities and
increase future cash provided by financing activities, to the extent of
associated tax benefits that may be realized in the future; however, it will not
have an impact on the Company's overall cash flows.
2. 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,
removal of equipment and facilities from leased acreage and land restoration.
The fair value of a liability for an asset retirement obligation is 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.
9
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, 2005.
Nine Months Ended
September 30, 2005
-----------------------
(in thousands)
Beginning asset retirement obligation, as of 12/31/2004.... $ 21,540
Liabilities incurred during period......................... 2,035
Revisions in estimated cash flows.......................... 981
Liabilities settled during period.......................... (442)
Accretion expense.......................................... 1,279
-----------------------
Ending asset retirement obligation, as of 9/30/2005........ $ 25,393
=======================
At September 30, 2005, $1.3 million of our asset retirement obligation was
classified in "Accounts payable and accrued liabilities" under current
liabilities in our Condensed Consolidated Balance Sheets. We hold cash and
liquid investments in escrow accounts that are legally restricted for certain of
our asset retirement obligations. The balances of these escrow accounts were
$6.6 million at September 30, 2005, and $6.4 million at December 31, 2004 and
are included in "Other assets" in our Condensed Consolidated Balance Sheets.
3. STOCK REPURCHASE PLAN
Between August 2003 and June 30, 2005, Denbury had an active stock
repurchase plan ("Plan") to purchase shares of our common stock on the NYSE in
order for such repurchased shares to be reissued to our employees who
participate in Denbury's Employee Stock Purchase Plan ("ESPP"). The Plan
provided for purchases through an independent broker of 100,000 shares of
Denbury's common stock per fiscal quarter over a period of approximately twelve
months, or a total of 400,000 shares per year. Purchases were made at prices and
times determined at the discretion of the independent broker, provided however
that no purchases may be made during the last ten business days of a fiscal
quarter. In 2004, we repurchased into treasury 400,000 shares at an average cost
of $9.95 per share and reissued 230,180 treasury shares under the ESPP. In the
first six months of 2005, we repurchased into treasury 200,000 shares at an
average cost of $15.82 per share and reissued 99,024 treasury shares under the
ESPP. The repurchase plan expired as of June 30, 2005 and the Board of Directors
currently does not plan to renew the Plan until a significant portion of the
treasury shares have been used under our ESPP.
4. RELATED PARTY TRANSACTIONS - GENESIS
Interest in and Transactions with Genesis
Denbury is the general partner and owns an aggregate 9.25% interest in
Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership.
Genesis has three primary lines of business: crude oil gathering and marketing,
pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida,
and wholesale marketing of carbon dioxide.
We are accounting for our 9.25% ownership in Genesis under the equity
method of accounting as we have significant influence over the limited
partnership; however, our control is limited under the limited partnership
agreement and therefore we do not consolidate Genesis. Our equity in Genesis'
net income (loss) for the three months ended September 30, 2005 and 2004 was
$(55,000) and $(37,000), and for the nine months ended September 30, 2005 and
2004 was $276,000 and $(28,000), respectively. Genesis Energy, Inc., the general
partner of which we own 100%, has guaranteed the bank debt of Genesis, which as
of September 30, 2005 was $32.6 million, plus $5.8 million in outstanding
letters of credit. There are no guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
Over the past several years, including the period prior to our investment
in Genesis, we sold certain of our oil production to Genesis. Beginning in
September 2004, we discontinued most of our direct oil sales to Genesis and
began to transport our crude oil using Genesis' Mississippi common carrier
pipeline to a sales point where it is sold to third party purchasers. For these
transportation services, we pay Genesis a fee for the use of their pipeline and
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
trucking services. For the three and nine months ended September 30, 2005, we
expensed $1.0 million and $3.0 million, respectively, for these transportation
services. For the three and nine months ended September 30, 2004, we expensed
$266,000 under this transportation agreement. We recorded oil sales to Genesis
of $1.4 million and $20.6 million for the respective quarters ended September
30, 2005 and 2004, and $3.4 million and $62.9 million for the respective nine
months ended September 30, 2005 and 2004. Denbury received other miscellaneous
payments from Genesis for the nine months ended September 30, 2005 and 2004,
including $90,000 in each period of director fees for certain executive officers
of Denbury that are board members of Genesis, and $387,000 and $373,000,
respectively, in pro rata dividend distributions from Genesis as part of
Genesis' cash distributions to all of its public holders.
Transportation Leases
In late 2004 and early 2005, we entered into pipeline transportation
agreements with Genesis to transport in its pipelines our crude oil from Olive,
Brookhaven, and McComb Fields in Southwest Mississippi to Genesis' main crude
oil pipeline in order to improve our ability to market our crude oil, and to
transport CO2 from our main CO2 pipeline to Brookhaven Field for our tertiary
operations. As part of these arrangements, we entered into three transportation
agreements. The first agreement, entered into in November 2004, was to transport
crude oil from Olive Field. This agreement is for 10 years and has a minimum
payment of approximately $18,000 per month. In December 2004, we entered into a
second transportation agreement, to transport CO2 to Brookhaven Field in
Southwest Mississippi. This agreement is for an eight-year period and has
minimum payments of approximately $49,000 per month. In January 2005, we entered
into a third transportation agreement to transport crude oil from Brookhaven
Field. This agreement is for 10 years and has a minimum payment of approximately
$32,000 per month. The minimum monthly payment in each agreement will increase
for any volumes transported in excess of the stated monthly volume in the
contract. Genesis operates and maintains these pipelines at its own expense.
We have accounted for these agreements as capital leases. The pipelines
held under these capital leases are classified as property and equipment and are
amortized using the straight-line method over the lease terms. Lease
amortization is included in depreciation expense. At September 30, 2005, we had
$6.6 million of capital lease obligations recorded as liabilities in our
Condensed Consolidated Balance Sheet, of which $560,000 was current. At December
31, 2004, we had $4.6 million of capital lease obligations recorded as
liabilities in our Condensed Consolidated Balance Sheet, of which $375,000 was
current.
CO2 Volumetric Production Payments
In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million
($23.9 million as adjusted for interim cash flows from the September 1, 2003
effective date and for transaction costs) under a volumetric production payment
("VPP"), and assigned to Genesis three of our existing long-term commercial CO2
supply agreements with our industrial customers. These industrial contracts
represented approximately 60% of our then current industrial CO2 sales volumes.
Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO2 through 2009,
43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term.
On August 26, 2004, we closed on another transaction with Genesis, selling
to them a 33.0 Bcf volumetric production payment ("VPPII") of CO2 for $4.8
million ($4.6 million as adjusted for interim cash flows from the July 1
effective date and for transaction costs) along with a related long-term supply
agreement with an industrial customer. Pursuant to the VPPII, Genesis may take
up to 9 MMcf/d of CO2 to the end of the contract term.
We have recorded the net proceeds of these volumetric production payment
sales as deferred revenue and will recognize such revenue as CO2 is delivered
during the term of the two volumetric production payments. At September 30, 2005
and December 31, 2004, $23.8 million and $25.8 million, respectively, was
recorded as deferred revenue of which $2.4 million was included in current
liabilities at September 30, 2005 and December 31, 2004. We recognized deferred
revenue of $0.7 million during each of the three month periods ended September
30, 2005 and 2004 and $2.0 and $1.8 million for the nine months ended September
30, 2005, respectively, for deliveries under the VPP and VPPII. We provide
Genesis with certain processing and transportation services in connection with
these agreements for a fee of approximately $0.16 per Mcf of CO2 delivered to
their industrial customers, which resulted in $0.8 million and $0.7 million in
revenue to Denbury for the three months ended September 30, 2005 and 2004 and
$2.3 million and $1.9 million for the nine months ended September 30, 2005 and
2004, respectively.
11
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------------- --------------------------------------
2005 2004 2005 2004
------------------ ------------------- ------------------ -------------------
Revenues........................................ $ 300,577 $ 250,736 $ 814,321 $ 681,755
Cost of sales................................... 300,686 250,892 810,581 681,035
Other expenses ................................. 532 203 1,141 701
Income (loss) from discontinued operations...... 45 (35) 318 (319)
------------------ ------------------- ------------------ -------------------
Net income (loss)............................. $ (596) $ (394) $ 2,917 $ (300)
================== =================== ================== ===================
September 30, December 31,
2005 2004
------------------ -------------------
Current assets.................................. $ 107,456 $ 77,396
Non-current assets.............................. 79,163 65,758
------------------ -------------------
Total assets ................................. $ 186,619 $ 143,154
================== ===================
Current liabilities ............................ $ 109,437 $ 81,938
Non-current liabilities......................... 32,786 15,460
Partners' capital............................... 44,396 45,756
------------------ -------------------
Total liabilities and partners' capital....... $ 186,619 $ 143,154
================== ===================
12
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Effective January 1, 2005, we elected to discontinue hedge accounting for
our oil and natural gas derivative contracts and accordingly de-designated our
derivative instruments from hedge accounting treatment. As a result of this
change, we began accounting for our oil and natural gas derivative contracts as
speculative contracts in the first quarter of 2005. As speculative contracts,
the changes in the fair value of these instruments are recognized in income in
the period of change. Additionally, the balance remaining in accumulated
comprehensive income at December 31, 2004 related to the derivative contracts is
being amortized over the remaining life of the contracts, all of which expire in
2005. While this may result in more volatility in our net income than if we had
continued to apply hedge accounting treatment as permitted by SFAS No. 133, we
believe that the benefits associated with applying hedge accounting do not
outweigh the cost, time and effort required to comply with hedge accounting.
We enter into various financial contracts to economically 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. Historically, we have generally attempted
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 a majority of our
budgeted exploration and development expenditures without incurring significant
debt, although our hedging percentage may vary relative to our debt levels. For
2005 and beyond, we have hedged significantly less, primarily because of our
strong financial position resulting from our lower levels of debt relative to
our cash flow from operations. When we make a significant acquisition, we
generally 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. We manage and
control market and counterparty credit risk through established internal control
procedures, which are reviewed on an ongoing basis. We attempt to minimize
credit risk exposure to counterparties through formal credit policies,
monitoring procedures, and diversification.
For the 2004 period, the following is a summary of the net loss on our
commodity contracts that qualified for hedge accounting and is included in "Loss
on effective hedge contracts" in our Condensed Consolidated Statements of
Operations:
Three Months Ended Nine Months Ended
(In Thousands) September 30, 2004 September 30, 2004
- ------------------------------------------------------------ ------------------------ ------------------------
Settlements of hedge contracts - Oil........................ $ (13,455) $ (33,771)
Settlements of hedge contracts - Gas........................ (4,010) (12,686)
------------------------ ------------------------
Loss on effective hedge contracts......................... $ (17,465) $ (46,457)
======================== ========================
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following is a summary of "Commodity Derivative Expense" included in
our Condensed Consolidated Statements of Operations:
Three Months Nine Months
(In Thousands) Ended September 30, Ended September 30,
- ------------------------------------------------------------------------ ------------------------- -------------------------
2005 2004 2005 2004
------------ ------------ ------------ ------------
Settlements of derivative contracts not designated as hedges - Oil...... $ - $ 4,778 $ - $ 8,293
Settlements of derivative contracts not designated as hedges - Gas...... 3,765 - 6,640 -
Hedge ineffectiveness on contracts qualifying for hedge
accounting............................................................ - (1,551) - (1,518)
Reclassification of accumulated other comprehensive income
balance............................................................... 1,875 1,206 5,451 9,318
Adjustments to fair value associated with contracts no longer
designated as hedges.................................................. 6,178 1,747 6,523 3,096
Adjustment to fair value associated with contracts transferred in
sale of offshore production........................................... - (1,019) - (2,549)
------------ ------------ ------------ ------------
Commodity derivative expense........................................ $ 11,818 $ 5,161 $ 18,614 $ 16,640
============ ============ ============ ============
Derivative Contracts at September 30, 2005
Crude Oil Contracts:
- -------------------
NYMEX Contract Prices Per Bbl
-----------------------------------------------
Collar Prices Fair Value at
---------------------- September 30, 2005
Type of Contract and Period Bbls/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ----------- ------------ ---------- ---------- --------------------
Floor Contracts
Oct. 2005 - Dec. 2005 7,500 $ 27.50 - - $ -
Natural Gas Contracts:
- ---------------------
NYMEX Contract Prices Per MMBtu
-----------------------------------------------
Collar Prices Fair Value at
---------------------- September 30, 2005
Type of Contract and Period MMBtu/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ----------- ------------ ---------- ---------- --------------------
Collar Contracts
Oct. 2005 - Dec. 2005 15,000 - $ 3.00 $ 5.50 $ (11,390)
At September 30, 2005, our derivative contracts were recorded at their fair
value, which was a net liability of $11.4 million. The balance in accumulated
other comprehensive loss of $1.4 million at September 30, 2005, represents the
unamortized deficit in the fair market value of our derivative contracts as
compared to the cost of our hedges, net of income taxes, associated with our
derivative contracts that we de-designated from hedge accounting effective
January 1, 2005. The $1.4 million in accumulated other comprehensive loss as of
September 30, 2005 will be amortized by December 31, 2005.
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
September 30, December 31,
(In Thousands) 2005 2004
----------------- -----------------
Accounts payable................................. $ 18,067 $ 26,262
Accrued compensation............................. 5,133 5,613
Accrued exploration and development costs........ 25,307 5,439
Accrued interest ................................ 8,468 4,219
Asset retirement obligations - current........... 1,315 2,596
Other............................................ 12,026 5,300
----------------- -----------------
Total ......................................... $ 70,316 $ 49,429
================= =================
7. SUBSEQUENT EVENTS
On October 19, 2005, stockholders of Denbury Resources Inc. approved an
amendment to our Restated Certificate of Incorporation to increase the number of
shares of our authorized common stock from 100,000,000 shares to 250,000,000
shares and to split our common stock on a 2-for-1 basis. Stockholders of record
on October 31, 2005, received one additional share of Denbury common stock for
each share of common stock held at that time. Information pertaining to shares
and earnings per share has been retroactively adjusted in the accompanying
financial statements and related notes thereto to reflect the stock split.
In October 2005, we sold 80.0 Bcf of CO2 to Genesis for $14.7 million under
a volumetric production payment, and assigned to Genesis two of our existing
long-term commercial CO2 supply agreements with our industrial customers. Net
proceeds will be reflected as deferred revenue and will be recognized as
revenues as the CO2 is delivered during the term of the volumetric production
payment.
8. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
On December 29, 2003, we amended the indenture for our 7.5% Senior
Subordinated Notes due 2013 to reflect our new holding company organizational
structure. As part of this restructuring our indenture was amended so that both
Denbury Resources Inc. and Denbury Onshore, LLC became co-obligors of our
subordinated debt. The co-obligations are full and unconditional and are joint
and several. Prior to this restructure, Denbury Resources Inc. was the sole
obligor. Our subordinated debt is fully and unconditionally guaranteed jointly
and severally by all of Denbury Resources Inc.'s subsidiaries other than minor
subsidiaries. The results of our equity interest in Genesis is reflected through
the equity method by one of our subsidiaries, Denbury Gathering & Marketing.
Each subsidiary guarantor and the subsidiary co-obligor are 100% owned, directly
or indirectly, by Denbury Resources Inc. The following is condensed
consolidating financial information for Denbury Resources Inc., Denbury Onshore,
LLC, and significant subsidiaries:
15
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Balance Sheets
September 30, 2005
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
ASSETS
Current assets................................. $ 221,680 $ 141,462 $ 3,080 $ (222,993) $ 143,229
Property and equipment ........................ - 1,069,432 54 - 1,069,486
Investment in subsidiaries (equity method)..... 448,263 - 446,847 (888,441) 6,669
Other assets................................... 2,338 10,790 286 (2,623) 10,791
---------------- --------------- ------------ -------------- ---------------
Total assets ................................ $ 672,281 $ 1,221,684 $ 450,267 $ (1,114,057) $ 1,230,175
================ =============== ============ ============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities............................ $ - $ 335,849 $ 1,950 $ (222,993) $ 114,806
Long-term liabilities ......................... - 445,657 54 (2,623) 443,088
Stockholders' equity .......................... 672,281 440,178 448,263 (888,441) 672,281
---------------- --------------- ------------ -------------- ---------------
Total liabilities and stockholders' equity... $ 672,281 $ 1,221,684 $ 450,267 $ (1,114,057) $ 1,230,175
================ =============== ============ ============== ===============
December 31, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
ASSETS
Current assets ................................ $ 1 $ 171,997 $ 204,709 $ (203,861) $ 172,846
Property and equipment ........................ - 796,578 784 - 797,362
Investment in subsidiaries (equity method) .... 541,671 - 333,907 (868,787) 6,791
Other assets .................................. - 15,707 2,271 (2,271) 15,707
---------------- --------------- ------------ -------------- ---------------
Total assets................................. $ 541,672 $ 984,282 $ 541,671 $ (1,074,919) $ 992,706
================ =============== ============ ============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities............................ $ - $ 286,767 $ - $ (203,861) $ 82,906
Long-term liabilities ......................... - 370,399 - (2,271) 368,128
Stockholders' equity........................... 541,672 327,116 541,671 (868,787) 541,672
---------------- --------------- ------------ -------------- ---------------
Total liabilities and stockholders' equity... $ 541,672 $ 984,282 $ 541,671 $ (1,074,919) $ 992,706
================ =============== ============ ============== ===============
16
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2005
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Revenues....................................... $ - $ 141,858 $ - $ - $ 141,858
Expenses ...................................... 41 82,825 383 - 83,249
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (41) 59,033 (383) - 58,609
Equity in net earnings of subsidiaries...... 38,571 - 38,724 (77,350) (55)
---------------- --------------- ------------ -------------- ---------------
Income before income taxes..................... 38,530 59,033 38,341 (77,350) 58,554
Income tax provision (benefit)................. (16) 20,254 (230) - 20,008
---------------- --------------- ------------ -------------- ---------------
Net income .................................... $ 38,546 $ 38,779 $ 38,571 $ (77,350) $ 38,546
================ =============== ============ ============== ===============
Three Months Ended September 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Revenues....................................... $ - $ 81,977 $ 6,008 $ - $ 87,985
Expenses....................................... 42 56,651 5,149 - 61,842
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (42) 25,326 859 - 26,143
Equity in net earnings of subsidiaries....... 18,299 - 20,625 (38,961) (37)
---------------- --------------- ------------ -------------- ---------------
Income before income taxes..................... 18,257 25,326 21,484 (38,961) 26,106
Income tax provision (benefit)................. (17) 4,664 3,185 - 7,832
---------------- --------------- ------------ -------------- ---------------
Net income..................................... $ 18,274 $ 20,662 $ 18,299 $ (38,961) $ 18,274
================ =============== ============ ============== ===============
17
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations (continued)
Nine Months Ended September 30, 2005
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Revenues....................................... $ - $ 383,203 $ - $ - $ 383,203
Expenses ...................................... 123 219,509 862 - 220,494
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (123) 163,694 (862) - 162,709
Equity in net earnings of subsidiaries ...... 109,360 - 109,934 (219,018) 276
---------------- --------------- ------------ -------------- ---------------
Income before income taxes..................... 109,237 163,694 109,072 (219,018) 162,985
Income tax provision (benefit)................. (48) 54,036 (288) - 53,700
---------------- --------------- ------------ -------------- ---------------
Net income .................................... $ 109,285 $ 109,658 $ 109,360 $ (219,018) $ 109,285
================ =============== ============ ============== ===============
Nine Months Ended September 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Revenues....................................... $ - $ 228,504 $ 63,486 $ - $ 291,990
Expenses ...................................... 130 166,044 37,699 - 203,873
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (130) 62,460 25,787 - 88,117
Equity in net earnings of subsidiaries ...... 60,051 - 45,743 (105,822) (28)
---------------- --------------- ------------ -------------- ---------------
Income before income taxes..................... 59,921 62,460 71,530 (105,822) 88,089
Income tax provision (benefit)................. (46) 16,689 11,479 - 28,122
---------------- --------------- ------------ -------------- ---------------
Net income .................................... $ 59,967 $ 45,771 $ 60,051 $ (105,822) $ 59,967
================ =============== ============ ============== ===============
18
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2005
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Cash flow from operations...................... $ (6,020) $ 236,921 $ 400 $ - $ 231,301
Cash flow from investing activities............ - (252,963) (21) - (252,984)
Cash flow from financing activities............ 6,020 19,614 - - 25,634
---------------- --------------- ------------ -------------- ---------------
Net increase in cash........................... - 3,572 379 - 3,951
Cash, beginning of period...................... 1 32,881 157 - 33,039
---------------- --------------- ------------ -------------- ---------------
Cash, end of period............................ $ 1 $ 36,453 $ 536 $ - $ 36,990
================ =============== ============ ============== ===============
Nine Months Ended September 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Cash flow from operations...................... $ (8,386) $ 317,322 $ (157,965) $ - $ 150,971
Cash flow from investing activities............ - (172,986) 157,995 - (14,991)
Cash flow from financing activities............ 8,386 (75,412) - - (67,026)
---------------- --------------- ------------ -------------- ---------------
Net increase in cash .......................... - 68,924 30 - 68,954
Cash, beginning of period...................... 1 24,174 13 - 24,188
---------------- --------------- ------------ -------------- ---------------
Cash, end of period............................ $ 1 $ 93,098 $ 43 $ - $ 93,142
================ =============== ============ ============== ===============
19
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, 2004, along
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" contained in such Form 10-K. Any terms used but not defined in the
following discussion have the same meaning given to them in the Form 10-K.
We are an independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi, own the largest reserves of
carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi
River, and hold significant operating acreage onshore Louisiana and in the
Barnett Shale play near Fort Worth, Texas. Our goal is to increase the value of
acquired properties through a combination of exploitation, drilling, and proven
engineering extraction processes, including secondary and tertiary recovery
operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas),
and we have two primary field offices located in Houma, Louisiana, and Laurel,
Mississippi.
OVERVIEW
STOCK SPLIT. On October 19, 2005, our stockholders approved an amendment to
our certificate of incorporation to increase our authorized shares of common
stock from 100 million shares to 250 million shares and to split our common
stock on a two-for-one basis. Stockholders of record as of the close of business
on October 31, 2005 received one additional share of Denbury common stock for
each share of common stock held at that time. All per share numbers included
herein have been restated for this two-for-one split.
IMPACT OF HURRICANES KATRINA AND RITA. During August and September, 2005,
Hurricanes Katrina and Rita came ashore negatively affecting almost all of our
existing production. While we did not incur any significant property damage as a
result of either storm, we estimate that we lost approximately 350,000 barrels
of oil equivalent ("BOE") of production during the third quarter as most of our
fields were shut-in for periods ranging from several days to a few weeks,
primarily because of a lack of power or because of flooding. As a result,
production was lower in the third quarter than in the immediately prior quarter
in every area of our operations except for the Barnett Shale play in Texas.
While almost all of our wells had been returned to production by late October,
we estimate that we lost an additional 500 BOE/d of production in the fourth
quarter as a result of the two hurricanes.
Many of our operating statistics were affected by the decreased production.
Operating costs and general and administrative costs per BOE were higher in the
third quarter as a result of the reduced production levels. We also incurred
approximately $1.6 million to provide food, water, gasoline, power generators,
and other essential supplies to our employees and charitable organizations in
Mississippi and Louisiana following the storms, most of which was expensed,
further increasing our general and administrative costs on both a gross and per
BOE basis.
CONTINUED EXPANSION OF OUR TERTIARY OPERATIONS. Since we acquired our first
carbon dioxide tertiary flood in Mississippi nearly six years ago, we have
gradually increased our emphasis on these types of operations. We particularly
like this play because of its risk profile, rate of return and lack of
competition in our operating area. Generally, from East Texas to Florida, there
are no known significant natural sources of carbon dioxide except our own, and
these large volumes of CO2 that we own drive the play. Please refer to
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the sections entitled "Overview" and "CO2 Operations" contained
in our 2004 Form 10-K for further information regarding these operations, their
potential, and the ramifications of this change in focus.
Near the end of October 2005, we reached total depth and logged another CO2
source well. Preliminary analysis of the well logs indicate CO2 reserves in
excess of one Tcf, subject to confirmation through production tests, gas
composition analysis, and delineation of the reservoir. This is in addition to
the estimated 130 Bcf of proved CO2 reserves that we added from another CO2
source well drilled in the first half of 2005. If preliminary estimates are
correct, this will give us additional CO2 reserves to further expand our
tertiary operations and potentially add another phase of operations.
Oil production from our tertiary operations decreased slightly as a result
of the two hurricanes (see "Impact of Hurricanes Katrina and Rita" above) to
8,850 BOE/d in the third quarter of 2005, a 6% decrease compared to our second
quarter 2005 tertiary production level of 9,417 BOE/d, but still a 27% increase
over our third quarter of 2004 average tertiary production level of 6,967 BOE/d.
As a result of the hurricanes and other delays, we have reduced our targeted
2005 average rate of oil production from tertiary operations from our prior
estimate of between 9,500 and 9,750 BOE/d to a revised estimated range between
9,250 and 9,500 BOE/d. Generally, our fields are performing as anticipated, but
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with our tertiary fields shut-in briefly as a result of the hurricanes and other
delays, our 2005 annual production will not be as high as originally expected.
In addition, the timing of specific well responses is not always possible to
accurately forecast, thus there could be variances from our expected long-term
oil production forecast.
OPERATING RESULTS. Despite the negative impact on earnings from the two
hurricanes (see above), earnings and cash flow from operations were at
near-record quarterly and nine month levels for the 2005 periods, primarily as a
result of high commodity prices. Production was lower in the respective 2005
periods, primarily as a result of the sale of our offshore properties early in
the third quarter of 2004 and as a result of the production lost from the two
hurricanes. Our total production, when comparing the two third quarters,
decreased 8% in the 2005 period. Adjusting for the offshore sale, our total
production was almost the same in the two third quarters, even though the third
quarter of 2005 was negatively impacted by the loss of approximately 3,800 BOE/d
as a result of the two hurricanes.
Higher commodity prices more than offset the lower production levels,
resulting in net income of $38.5 million during the third quarter of 2005 as
compared to $18.3 million of net income during the third quarter of 2004.
Included in third quarter of 2005 net income is the effect of approximately $8.1
million ($5.3 million after tax) of mark-to-market expense and non-cash
amortization expense of accumulated other comprehensive income that related to
our decision to discontinue hedge accounting in 2005 (see "Market Risk
Management").
Cash payments on our commodity hedges were significantly lower in the third
quarter of 2005 than in the third quarter of 2004, as most of our
out-of-the-money hedges expired as of December 31, 2004. Total cash payments on
hedges were approximately $3.8 million in the third quarter of 2005 as compared
to $22.2 million paid during the third quarter of 2004.
Most of our expenses increased on a per BOE basis during the 2005 period
due to (i) rising costs in the industry, (ii) a higher percentage of operations
related to tertiary operations (which have higher operating costs per BOE), and
(iii) lower production levels in the 2005 period following our offshore property
sale in July 2004 and production lost from the two hurricanes. See "Results of
Operations" for a more thorough discussion of our operating results. We are also
experiencing significant cost inflation in our industry, as evidenced by the
cost increases in almost every aspect of our business, and if commodity prices
remain high and demand for goods and services remain strong, we expect this
inflationary trend to continue.
Our operating results for the comparative first nine months of 2005 and
2004 were generally consistent with the summary discussed above for the
respective third quarters. Earnings and cash flow from operations increased over
the prior-year period due to the higher commodity prices and lower hedge
payments, offset in part by lower production due to the offshore sale in July
2004 and the hurricanes in the third quarter of 2005. Most expenses on a per BOE
basis increased in the first nine months of 2005 period for the reasons noted
above.
CAPITAL RESOURCES AND LIQUIDITY
Our current capital budget for 2005, excluding any potential acquisitions,
is approximately $365 million, which at commodity futures prices as of the end
of October 2005, will be reasonably close to our anticipated cash flow from
operations. The capital budget includes an estimated $50 million of expenditures
for a CO2 pipeline being constructed to East Mississippi, which we may refinance
upon completion by entering into some type of long-term financing, effectively
paying for the cost of the pipeline over time and recouping cash previously
spent. As has been our practice in the past, we attempt to reinvest all of our
available cash flow and profits to find additional reserves and increase
production. We monitor our capital expenditures on a regular basis, adjusting
them up or down depending on commodity prices and the resultant cash flow.
Therefore, during the last few years as commodity prices have increased, we have
increased our capital budget. As a result of the recent cost inflation in our
industry, we are having to continually review and increase our capital budget
each quarter, or consider the elimination of a portion of our planned projects.
We have not yet set our 2006 capital budget, but it is likely to be
significantly higher than our 2005 budget and is preliminarily expected to be
between $450 million and $500 million, a level that is reasonably close to our
anticipated cash flow from operations using current prices. Preliminarily,
approximately 50% of the budget would be spent on tertiary related operations,
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approximately 25% in the Barnett Shale area, approximately 10% on exploration
projects, and the balance on our properties in Mississippi or Louisiana. The
2006 budget will be set and approved by our Board of Directors at our next
regularly scheduled board meeting in December 2005.
In addition to our capital exploration and development budget, during the
first nine months of 2005 we also spent approximately $71.2 million on
acquisitions, primarily for interests in other oil fields that may be tertiary
flood candidates and for additional acreage and interests in the Barnett Shale
play near Fort Worth, Texas. We are continuing to pursue additional acquisitions
of a similar nature during the remainder of 2005 and in 2006, some of which may
have higher existing production and therefore be more expensive, although it is
not practical to forecast if these will be successful or in what amounts.
At September 30, 2005, we had used our remaining cash and short-term
investments from the 2004 sale of our offshore properties and had borrowed $20
million on our bank credit line, primarily to fund acquisitions. We repaid $10
million on our line in October 2005 with proceeds from another transaction with
Genesis Energy, L.P. ("Genesis"), selling them a volumetric production payment
of 80 Bcf of CO2 for $14.7 million along with two related long-term CO2 supply
agreements with two industrial customers. Based on current prices, we anticipate
that our cash flow will be sufficient for the remainder of the year to fund our
currently planned capital expenditures, although there could be short-term
borrowings and repayments under our bank line depending on the timing of such
expenditures. If we are successful in making further acquisitions, these would
likely be initially funded under our bank credit line.
At September 30, 2005, we had outstanding $225 million (principal amount)
of 7.5% subordinated notes due in 2013, approximately $6.6 million of capital
lease commitments, $20 million of bank debt, and working capital of $28.4
million. We amended our bank agreement in April 2005 to (i) reaffirm our $200
million borrowing base, and (ii) allow us to borrow up to $80 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 through May
2007 in Mississippi. This bond funding arrangement was completed in April 2005
to replace a prior two year program that expired as of May 1, 2005. Any
borrowing 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
borrowing base was reaffirmed again in September 2005.
SOURCES AND USES OF CAPITAL RESOURCES
During the first nine months of 2005, we spent $210.9 million on oil and
natural gas exploration and development, $49.9 million on CO2 exploration and
development (including $27.9 million on our CO2 pipeline being constructed to
East Mississippi), and approximately $71.2 million on property acquisitions, for
total capital expenditures of approximately $332.0 million. Our exploration and
development expenditures included approximately $94.9 million for drilling,
$20.1 million for geological, geophysical and acreage expenditures and $95.8
million for facilities and recompletion costs. Our year-to-date acquisition
expenditures include the purchase of additional interest and acreage in the
Barnett Shale area and purchase of two oil fields that may be potential tertiary
flood candidates in the future, Cranfield and Lake St. John fields. We funded
these expenditures with $231.3 million of cash flow from operations, $20.0
million of net bank borrowings, and a $19.9 million increase in our accrued
capital expenditures, with the balance funded with cash remaining from our 2004
offshore property sale. Adjusted cash flow from operations (a non-GAAP measure
defined as cash flow from operations before changes in assets and liabilities as
discussed below under "Results of Operations - Operating Results" below) was
$238.7 million for the first nine months of 2005, while cash flow from
operations for the same period, the GAAP measure, was $231.3 million.
During the first nine months of 2004, we spent $125.8 million on oil and
natural gas exploration and development, $35.2 million on CO2 exploration and
development, and approximately $11.6 million on property acquisitions
(principally CO2 producing assets), for total capital expenditures of
approximately $172.6 million. We funded these expenditures with $151.0 million
of cash flow from operations, with the balance funded with net proceeds from the
July 2004 offshore sale. We also paid back all of our bank debt during the
period with the offshore sale proceeds, leaving us with approximately $93.1
million of cash and $32.0 million of short-term investments as of September 30,
2004, although $16.0 million of this cash was refunded to the purchaser of our
offshore assets in October 2004. During the third quarter of 2004, we closed on
another transaction with Genesis, selling to them a 33.0 Bcf volumetric
production payment of CO2 for $4.8 million along with a related long-term CO2
supply agreement with an industrial customer, further increasing our cash
position. Adjusted cash flow from operations (a non-GAAP measure defined as cash
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
flow from operations before changes in assets and liabilities as discussed below
under "Results of Operations - Operating Results") was $151.7 million for the
first nine months of 2004.
OFF-BALANCE SHEET ARRANGEMENTS
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet are
our operating leases and various obligations for development and exploratory
expenditures arising from purchase agreements, our capital expenditure program,
or other transactions common to our industry. In addition, in order to recover
our undeveloped proved reserves, we must also fund the associated future
development costs as forecasted in 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, 2005, consisted of $32.6
million of debt and $5.8 million in letters of credit), and we have delivery
obligations to deliver CO2 for Genesis and to our industrial customers. Our
hedging obligations are discussed in Note 5 to the Unaudited Condensed
Consolidated Financial Statements. Neither the amounts nor the terms of these
commitments or contingent obligations have changed significantly from the
year-end 2004 amounts reflected in our Form 10-K filed in March 2005. Please
refer to "Management's Discussion and Analysis of Financial Condition and
Results of Operations" contained in our 2004 Form 10-K for further information
regarding our commitments and obligations.
RESULTS OF OPERATIONS
CO2 Operations
As described in the "Overview" section above, our CO2 operations are
becoming an ever-increasing part of our business and operations. We believe that
there are significant additional oil reserves and production that can be
obtained through the use of CO2, and we have outlined certain of this potential
in our annual report and other public disclosures. In addition to its long-term
effect, this shift in focus impacts certain trends in our current and near-term
operating results. Please refer to "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the section entitled "CO2
Operations" contained in our 2004 Form 10-K for further information regarding
these matters.
Near the end of October 2005, we reached total depth and logged another CO2
source well. Preliminary analysis of the well logs indicate CO2 reserves in
excess of one Tcf, subject to confirmation through production tests, gas
composition analysis, and delineation of the reservoir. Additionally, we added
an estimated 130 Bcf of proved CO2 reserves that we added from another CO2
source well drilled in the first half of 2005. If preliminary estimates are
correct, this will give us additional CO2 reserves to further expand our
tertiary operations. We have in inventory two oil fields (Cranfield and Lake St
John fields) purchased earlier this year that will likely be part of a future
tertiary phase, and we are actively seeking to acquire additional oil properties
for this purpose.
During the first nine months of 2005, our CO2 production averaged 238
MMcf/d. We used 71% of this, or 170 MMcf/d, in our tertiary operations, and sold
the balance to our industrial customers or to Genesis pursuant to our volumetric
production payment. We believe that our current production capacity of CO2 is
approximately 400 MMcf/d prior to the completion of our latest well, and
anticipate that our latest well could increase our production capability to 450
or 500 MMcf/d. One more CO2 source well is expected to be started before the end
of 2005. These wells are intended not only to increase CO2 production, but also
to increase our CO2 reserves. We have completed a 3-D seismic shoot over the
Jackson Dome area and are currently processing and evaluating several prospects
for potential CO2 reserves.
Our oil production from our CO2 tertiary recovery activities in the third
quarter of 2005 decreased 6% over second quarter 2005 levels as a result of the
production lost from the hurricanes, but increased 27% over third quarter 2004
levels, to 8,850 Bbls/d in the third quarter of 2005, with production increases
at all three producing fields, Little Creek, Mallalieu and McComb Fields.
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Average Daily Production (BOE/d)
-------------------------------------------------------------------------------
First Second Third Fourth First Second Third
Quarter Quarter Quarter Quarter Quarter Quarter Quarter
Tertiary Oil Field 2004 2004 2004 2004 2005 2005 2005
- ------------------------------------- -------- -------- ------- ------- ------- -------- --------
Little Creek & Lazy Creek 3,192 3,288 3,125 2,989 3,709 3,847 3,357
Mallalieu (East and West) 3,105 3,172 3,410 3,712 4,235 4,582 4,565
McComb & Olive 21 143 432 541 700 988 928
-------- -------- ------- ------- ------- -------- --------
Total tertiary oil production 6,318 6,603 6,967 7,242 8,644 9,417 8,850
- ------------------------------------- ======== ======== ======= ======= ======= ======== ========
We are currently injecting CO2 into two other oil fields, Brookhaven and
Smithdale. The larger of the two, Brookhaven, has not responded to date and is
not expected to respond until early next year. During October 2005, we had our
first minor production response from Smithdale Field, but production from this
field is unlikely to be significant until 2006 or beyond, and due to the smaller
size of this field, its ultimate production rate is expected to be much less
than that at Little Creek or Mallalieu. On a consolidated basis, we expect our
tertiary oil production to continue to grow for the foreseeable future.
Our operations in this area, as well as others, have had minor delays
during 2005. These delays are caused by various factors: difficulties reentering
a few injection wells, which has required that some wells be redrilled; delays
in getting certain permits and right-of-ways; delays caused by the two
hurricanes; and a general tightening of available materials and equipment in the
industry. As a result of these delays and the lost production related to the
hurricanes, we have reduced our targeted 2005 average rate of oil production
from tertiary operations from our prior estimated range of 9,500 to 9,750 BOE/d
to a revised estimated range between 9,250 and 9,500 BOE/d. Generally, the
fields are performing as anticipated, but with the tertiary fields shut-in
briefly as a result of the hurricanes and the other delays, 2005 production will
not be as high as originally expected. In addition, the timing of specific well
responses is not always possible to accurately forecast, so we could experience
variances from our expected long-term oil production forecast.
We spent approximately $0.15 per Mcf to produce our CO2 during the first
nine months of 2005, slightly higher than the 2004 nine month average cost of
$0.12 per Mcf, principally as a result of higher commodity prices, which result
in higher royalty payments. Our estimated total cost per thousand cubic feet of
CO2 during the first nine months of 2005 was approximately $0.22, after
inclusion of depreciation and amortization expense, up slightly from the 2004
average of $0.21 per Mcf. On a quarterly basis, we spent approximately $0.17 per
Mcf to produce our CO2 during the third quarter of 2005, slightly higher than
the 2004 third quarter average of $0.14 per Mcf, but consistent with the nine
month trend, as a result of higher commodity prices. Our estimated total cost
per thousand cubic feet of CO2 during the third quarter of 2005 was
approximately $0.25, after inclusion of depreciation and amortization expense.
For the first nine months of 2005, our operating costs for our tertiary
properties averaged $11.04 per BOE, higher than the $9.84 per BOE average in the
first nine months of 2004 and our 2004 annual average of $9.90 per BOE. The
higher costs were a result of the higher fuel and energy costs (which represent
almost 38% of the total operating costs excluding the cost of CO2) and general
cost inflation in the industry, partially offset by higher oil production
levels.
Operating Results
As summarized in the "Overview" section above and discussed in more detail
below, higher commodity prices, and lower hedge payments more than offset lower
production levels and higher operating expenses, resulting in near-record
quarterly earnings and cash flow from operations. Included in the first nine
months of 2005 net income is the effect of approximately $12.0 million ($8.0
million after tax) of non-cash expense related to our decision to discontinue
hedge accounting in 2005 and the resultant mark-to-market adjustments and
amortization of other comprehensive income.
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------- ---------------------------- ---------------------------
Amounts in thousands, except per share amounts 2005 2004 2005 2004
- ------------------------------------------------------------- -------------- ------------- ------------- -------------
Net income $ 38,546 $ 18,274 $ 109,285 $ 59,967
Net income per common share - basic 0.34 0.17 0.98 0.55
Net income per common share - diluted 0.32 0.16 0.92 0.53
Adjusted cash flow from operations (see below) $ 87,346 $ 29,747 $ 238,708 $ 151,721
Net change in assets and liabilities relating to operations (11,059) 15,019 (7,407) (750)
- ------------------------------------------------------------- -------------- ------------- ------------- -------------
Cash flow from operations (1) $ 76,287 $ 44,766 $ 231,301 $ 150,971
- ------------------------------------------------------------- ============== ============= ============= =============
(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
calculated from our Unaudited Condensed Consolidated Statements of Cash Flows.
Cash flow from operations is the GAAP measure as presented in our Unaudited
Condensed Consolidated Statements of Cash Flows. In our discussion herein, we
have elected to discuss these two components of cash flow provided by operations
separately.
Adjusted cash flow from operations, the non-GAAP measure, measures the cash
flow earned or incurred from operating activities without regard to the
collection or payment of associated receivables or payables. We believe that
this is important to consider adjusted cash flow from operations separately, as
we believe it can often be a better way to discuss changes in operating trends
in our business caused by changes in production, prices, operating costs, and
related operational factors, without regard to whether the earned or incurred
item was collected or paid during that reporting period. We also use this
measure because the collection of our receivables or payment of our obligations
has not been a significant issue for our business, but merely a timing issue
from one period to the next, with fluctuations generally caused by significant
changes in commodity prices or significant changes in drilling activity.
The net change in assets and liabilities relating to operations is also
important as it does require or provide additional cash for use in our business;
however, we prefer to discuss its effect separately. During the first nine
months of 2005 our accrued production receivables and trade accounts receivable
increased as a result of higher revenue and increased spending, resulting in a
$14.3 million use of cash; however, this was partially offset by the increase in
our accounts payable, accrued liabilities and production payable which resulted
in additional cash resources of $7.5 million. During the third quarter of 2004,
we collected accrued production receivables related to offshore production that
existed as of the closing date of the sale of Denbury Offshore, Inc. that were
for the benefit of Newfield Exploration Company, the purchaser. As of September
30, 2004, we owed Newfield approximately $16.0 million for these receivables and
other sale adjustments, the primary reason for the $15.0 million net change in
assets and liabilities relating to operations above for the third quarter of
2004. During the first nine months of 2004, we spent $7.5 million (in the second
quarter) to acquire 7,500 Bbls/d of oil puts or floors for 2005 and to retire 20
MMcf/d of natural gas hedges for the balance of 2004, although this amount was
more than offset by the payable to Newfield at September 30, 2004.
Certain of our operating results and statistics for the comparative third
quarters and first nine months of 2005 and 2004 are included in the following
table.
25
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Nine Months Ended
September 30, September 30,
- ----------------------------------------------------------- ------------------------- -------------------------
2005 2004 2005 2004
- ----------------------------------------------------------- ------------ ------------ ------------ ------------
Average daily production volumes
Bbls/d 18,369 19,206 19,745 19,114
Mcf/d 53,854 62,708 56,556 91,028
BOE/d (1) 27,345 29,657 29,171 34,285
Operating revenues (Thousands)
Oil sales $ 95,987 $ 68,144 $ 264,337 $ 181,198
Natural gas sales 42,561 34,924 110,999 151,177
------------ ------------ ------------ ------------
Total oil and natural gas sales $ 138,548 $103,068 $ 375,336 $ 332,375
============ ============ ============ ============
Hedge Contracts (2) (Thousands)
Cash expense on settlements of hedge contracts $ 3,765 $ 22,243 $ 6,640 $ 54,750
Non-cash hedge expense 8,053 383 11,974 8,347
------------ ------------ ------------ ------------
Total expense from hedge contracts $ 11,818 $ 22,626 $ 18,614 $ 63,097
============ ============ ============ ============
Operating expenses (Thousands)
Lease operating expenses $ 25,983 $ 19,781 $ 75,702 $ 66,839
Production taxes and marketing expenses 7,018 4,900 19,726 13,481
------------ ------------ ------------ ------------
Total production expenses $ 33,001 $ 24,681 $ 95,428 $ 80,320
============ ============ ============ ============
CO2 sales and transportation fees (3) $ 2,594 $ 1,681 $ 5,841 $ 4,622
CO2 operating expenses 631 255 1,422 608
------------ ------------ ------------ ------------
CO2 operating margin $ 1,963 $ 1,426 $ 4,419 $ 4,014
============ ============ ============ ============
Unit prices - including impact of hedge settlements
Oil price per Bbl $ 56.80 $ 28.25 $ 49.04 $ 26.58
Gas price per Mcf 7.83 5.36 6.76 5.55
Unit prices - excluding impact of hedge settlements
Oil price per Bbl $ 56.80 $ 38.57 $ 49.04 $ 34.60
Gas price per Mcf 8.59 6.05 7.19 6.06
Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues $ 55.07 $ 37.78 $ 47.13 $ 35.38
============ ============ ============ ============
Oil and gas lease operating expenses $ 10.33 $ 7.25 $ 9.51 $ 7.11
Oil and gas production taxes and marketing expense 2.79 1.80 2.48 1.44
------------ ------------ ------------ ------------
Total oil and gas production expenses $ 13.12 $ 9.05 $ 11.99 $ 8.55
=========================================================== ============ ============ ============ ============
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the
Company's hedging transactions. Effective January 1, 2005, we elected to
discontinue hedge accounting for our oil and natural gas derivative
contracts, see Note 5 to the Condensed Consolidated Financial Statements.
(3) Includes deferred revenue of $0.7 million and $0.7 million for the three
months ended September 30, 2005 and 2004, respectively, and $2.0 million
and $1.8 million for the nine months ended September 30, 2005 and 2004,
respectively, associated with a volumetric production payment with Genesis.
Includes transportation income from Genesis of $0.8 million and $0.7
million for the three months ended September 30, 2005 and 2004,
respectively, and $2.3 million and $0.7 million for the nine months ended
September 30, 2005 and 2004, respectively.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PRODUCTION: Production by area for each of the quarters of 2004 and the
first, second, and third quarters of 2005 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 2004 2004 2004 2004 2005 2005 2005
- -------------------------------------------- ---------- --------- -------- --------- --------- -------- ---------
Mississippi - non-CO2 floods 12,754 13,048 12,969 13,564 13,057 12,788 10,998
Mississippi - CO2 floods 6,318 6,603 6,967 7,242 8,644 9,417 8,850
Onshore Louisiana 8,825 7,492 7,033 7,182 6,710 5,791 5,169
Barnett Shale 229 345 803 963 1,313 2,052 2,150
Other (1) - - - - - 421 178
---------- --------- -------- --------- --------- -------- ---------
Total production excluding offshore 28,126 27,488 27,772 28,951 29,724 30,469 27,345
Offshore Gulf of Mexico - sold July 2004 8,521 9,114 1,885 26 - - -
---------- --------- -------- --------- --------- -------- ---------
Total Company 36,647 36,602 29,657 28,977 29,724 30,469 27,345
========== ========= ======== ========= ========= ======== =========
- -------------------------------------
(1) Primarily represents production from an offshore property retained from the
sale in July 2004.
As discussed in the "Overview - Impact of Hurricanes Katrina and Rita"
above, we estimate that we lost approximately 350,000 BOE of production (or
approximately 3,800 BOE/d) as a result of Hurricanes Katrina and Rita during the
third quarter of 2005 as almost all of our fields were shut-in for periods
ranging from several days to a few weeks, primarily because of a lack of power
or flooding. As a result, production was lower in the third quarter of 2005 than
in the prior quarter in almost every operating area. We sold our offshore
properties in July 2004, contributing to an overall production decline on a
year-to-date basis. Such production is listed separately in the above table for
comparative purposes.
Production in the Mississippi non-CO2 floods decreased from the prior
quarter as a result of the shut-ins relating to the hurricanes, as otherwise
this area's production has remained relatively stable over the last several
quarters. Although most of the oil production in this area is on a gradual
decline, the natural gas drilling in the Selma Chalk formation at Heidelberg
Field has generally offset these declines. Even with the effects of the
hurricanes, natural gas production at Heidelberg averaged 13.2 MMcf/d in the
third quarter of 2005, almost the same as the 13.5 MMcf/d produced in the third
quarter of 2004.
As more fully discussed in "CO2 Operations" above, oil production from our
tertiary operations averaged 8,850 Bbls/d in the third quarter of 2005,
representing 48% of our third quarter corporate oil production and 32% of our
total corporate production on a BOE basis. Production in our CO2 floods was
higher year-over-year in spite of the storms, as the production growth from this
area was more than enough to overcome the lost production from the temporary
shut-ins.
Our onshore Louisiana production has generally declined over the last year
or two, partially offset by incremental production from occasional new wells,
with the most significant decreases at Thornwell and Lirette Fields. Production
at Thornwell averaged 975 BOE/d in the third quarter of 2005, as compared to
1,104 BOE/d in the third quarter of 2004, down only slightly as the production
from recent completions almost offset the otherwise declining production.
Thornwell Field was also one of the Louisiana Fields that was impacted the least
by the two hurricanes. Production at Lirette declined to 974 BOE/d in the third
quarter of 2005 from 2,133 BOE/d in the third quarter of 2004, decreasing from
both normal declines and production loss from the storms. Both of these fields
are characterized by natural gas wells that are relatively short-lived in
nature, and field production is expected to continue to decline unless offset by
new wells. Partially offsetting these declines was incremental production from
new wells in this area resulting from drilling in late 2004 and 2005, primarily
in the South Chauvin Field area.
Natural gas production in the Barnett Shale has increased as a result of
increased drilling activity in 2004 and early 2005 and the acquisition of
additional interests during the second quarter of 2005, increasing production
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
from 803 BOE/d (4.8 MMcf/d) in the third quarter of 2004 to 2,150 BOE/d (12.9
MMcf/d) in the third quarter of 2005. Approximately 1.5 MMcf/d of the increase
in the second quarter of 2005 is related to the acquisition of additional
interests. Our production in the Barnett area was also briefly shut-in as a
result of the two hurricanes, although the effect was minor. These wells are
characterized by steep decline rates in their first year of production (as much
as 50% to 60%), followed by a gradual leveling-off of production and a resultant
slow decline rate, giving them an overall long production life. Natural gas
production in this area is expected to further increase throughout 2005 as we
anticipate drilling twenty wells in this area during 2005. We currently have
three rigs running in this area, but expect to add another rig by early 2006.
Our production for the third quarter of 2005 was weighted toward oil (67%),
essentially the same oil to natural gas ratio that we have had since the sale of
our offshore properties in July 2004. Because of our emphasis on our tertiary
operations, we expect that our production will continue to be weighted toward
oil in the foreseeable future.
OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues for the third
quarter of 2005 increased $35.5 million, or 34%, from revenues in the comparable
quarter of 2004, primarily as a result of higher commodity prices, offset in
part by lower production primarily due to the effect of the two hurricanes. When
comparing the respective nine month periods, revenues increased $43.0 million,
or 13%, for the same reasons, partially offset by the lost production as a
result of the two hurricanes, coupled with decreased production as a result of
the sale of our offshore properties in July 2004. Cash payments on our hedges
were $3.8 million in the third quarter of 2005 and $6.6 million for the first
nine months of 2005, down from $22.2 million paid in the third quarter of 2004
and $54.8 million during the first nine months of 2004. See Note 5 to the
Condensed Consolidated Financial Statements and "Market Risk Management" for
additional information regarding our hedging activities.
When comparing the third quarters of 2005 and 2004, the 8% decrease in
production caused oil and natural gas revenues to decrease by $8.0 million, or
8%. This decrease was more than offset by the increase in commodity prices,
which caused oil and natural gas revenues to increase by $43.5 million, or 42%.
For the comparative first nine months of 2005 and 2004, the decrease in
production caused oil and natural gas revenues to decrease by $50.6 million, or
15%; however, the increase in commodity prices caused oil and natural gas
revenues to increase by $93.6 million, or 28%. Although both oil and natural gas
prices were higher in the current year periods than in the 2004 periods, oil
prices increased more than natural gas prices. Our realized oil prices
(excluding hedges) increased by 47% between the third quarters of 2005 and 2004
and by 42% between the comparable nine month periods, while our realized natural
gas prices (excluding hedges) increased by 42% between the third quarters of
2005 and 2004 and by 19% between the comparable nine month periods. On a
combined BOE basis, commodity prices were 46% higher for the comparative third
quarters and 33% higher for the comparative first nine months of 2005 and 2004.
Our net realized oil prices (excluding hedges) relative to NYMEX prices
were lower in the third quarter and first nine months of 2005 than in the
comparable 2004 periods as the NYMEX differential deteriorated significantly
during the latter half of 2004, and remained high during most of 2005,
particularly for the heavy, sour crude (which predominately applies to our
Eastern Mississippi production). Our average oil NYMEX differential for the
third quarter of 2005 was approximately $6.34 per Bbl, similar to the $6.48 per
Bbl NYMEX differential in the fourth quarter of 2004, but worse than the $5.19
per Bbl differential in the third quarter of 2004 and an average of $4.94 per
Bbl during 2004. While these differentials did narrow somewhat during the second
quarter of 2005, during the third quarter of 2005 they returned to a
differential similar to that in the fourth quarter of 2004. If market conditions
for heavy, sour crude were to remain consistent, we would expect to gradually
improve our overall NYMEX discount as the amount of light sweet oil production
from our tertiary operations is expected to increase, improving the overall
quality of our product mix. However, as evident in 2004, the oil market can
change substantially and rapidly and it is difficult to forecast these trends.
Our natural gas differentials also increased this quarter, averaging $0.97
per Mcf below NYMEX, while most prior quarters have generally been near NYMEX
prices. The variance increased this quarter, at least in part, due to increasing
natural gas prices during the quarter. Since most of our natural gas is sold on
an index price that is set near the first of each month, the variance will
increase if NYMEX natural gas prices consistently rise during the quarter.
Further, with the actual and anticipated incremental production from the Barnett
Shale area, which has usually sold for about $1.00 less than NYMEX prices, we
expect that our overall natural gas NYMEX differential will likely increase over
time.
PRODUCTION EXPENSES: Our operating expenses increased on both a per BOE
basis and in total dollars, primarily due to our emphasis on tertiary operations
discussed above. The reduced production as a result of the two hurricanes
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
further increased our operating costs on a per BOE basis. Operating expenses on
our tertiary operations increased from $17.9 million in the first nine months of
2004 to $27.0 million in the comparable period of 2005 (51%) as a result of
increased activity at Mallalieu, McComb and Brookhaven Fields. However, with the
35% higher production from these tertiary operations, the percentage increase in
operating expenses for our tertiary operations on a per BOE basis was less,
increasing from $9.84 per BOE in the first nine months of 2004 to $11.04 per BOE
in the first nine months of 2005 (12%). Workover expenses were also higher in
the first nine months of 2005 than in the comparable period of 2004,
particularly in the second quarter. Adjusted for the properties sold in the
offshore sale, during the second quarter alone, workover expenses were
approximately $2.0 million higher than during the second quarter of 2004,
primarily related to a mechanical failure on one onshore Louisiana well. The
balance of cost increases is generally attributable to higher energy and fuel
costs to operate the properties, the addition of operating leases on certain
facilities and equipment, and general cost inflation in our industry. In
general, we expect our operating costs per BOE to remain high and likely
increase throughout the next year as we expect to see continued cost inflation
throughout our industry, and the operating costs of our tertiary operations are
higher than for our other operations and these tertiary operations are becoming
more and more significant to us.
Production taxes and marketing expenses generally change in proportion to
commodity prices and therefore were higher in the third quarter and first nine
months of 2005 than in the comparable 2004 periods. The July 2004 sale of our
offshore properties also contributed to an increase in 2005 production taxes and
marketing expenses on a per BOE basis as most of our offshore properties were
not subject to severance taxes. We recognized $3.0 million of transportation
expenses paid to Genesis during the first nine months of 2005 as a result of a
change in the way we market a portion of our crude oil that commenced in
September 2004. As of September 1, 2004, we ceased selling most of our crude oil
at the wellhead to Genesis, choosing rather to use the Genesis pipeline to
transport our crude to market where we sell our own crude directly to
refineries. Overall, this has increased our aggregate net proceeds on our crude
oil sales, and increased our per unit price per barrel; however, the higher
sales proceeds are partially offset by the incremental transportation charges.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 44% between the
respective third quarters and 42% between the respective first nine months, as
set forth below:
Three Months Ended Nine Months Ended
September 30, September 30,
- ----------------------------------------------- ------------------------------ ------------------------------
2005 2004 2005 2004
- ----------------------------------------------- --------------- -------------- -------------- ---------------
Net G&A expense (thousands)
Gross G&A expenses $ 17,737 $ 13,562 $ 46,862 $ 38,015
State franchise taxes 447 295 1,065 783
Operator overhead charges (7,994) (6,465) (22,848) (19,959)
Capitalized exploration costs (1,238) (1,195) (3,640) (3,716)
--------------- -------------- -------------- ---------------
Net G&A expense $ 8,952 $ 6,197 $ 21,439 $ 15,123
=============== ============== ============== ===============
Average G&A cost per BOE $ 3.56 $ 2.27 $ 2.69 $ 1.61
Employees as of September 30 433 369 433 369
- ----------------------------------------------- --------------- -------------- -------------- ---------------
Gross G&A expenses increased $4.2 million, or 31%, between the respective
third quarters and $8.8 million or 23% between the respective first nine months.
These increases are generally attributable to higher compensation costs due to
additional employees (54 employees added between December 31, 2004 and September
30, 2005), wage increases and $1.0 million of non-cash compensation expense for
the third quarter and $3.1 million for the first nine months of 2005 for the
amortization of deferred compensation associated with the issuance of restricted
stock to officers and directors in 2004 and 2005 (as compared to $593,000 in the
third quarter of 2004). We also incurred approximately $1.6 million to provide
food, water, gasoline, power generators, and other essential supplies to our
employees and charitable organizations in Mississippi and Louisiana following
the hurricanes, of which all but approximately $243,000 was expensed. In
addition, we incurred higher professional service and consultant fees primarily
related to Sarbanes-Oxley compliance, investigation of hotline reports, audit
work, and documentation and testing of our new software system that we began
using in January 2005, as well as increased maintenance costs as a result of the
change to the new software system. These 2005 increases were offset by
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approximately $1.4 million and $2.4 million of employee severance payments paid
in 2004 related to the sale of our offshore properties in July 2004 that we
expensed in the third quarter and first nine months of 2004, respectively.
The increase in gross G&A was offset by an increase in operator overhead
recovery charges in the third quarter and first nine months of 2005. 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 to charge a monthly
fixed overhead rate for each producing well. As a result of our incremental
drilling and development activity during the third quarter and first nine months
of 2005, partially offset by the sale of our offshore properties, the amount we
recovered as operator overhead charges increased by 24% between the third
quarters of 2004 and 2005 and increased by 14% between the first nine months of
2004 and 2005. Capitalized exploration costs decreased slightly between the
comparable periods in 2004 and 2005 as a result of the 2004 termination of a
portion of our offshore exploration staff.
The net effect was a 44% increase in net G&A expense between the respective
third quarters and a 42% increase between the first nine months of 2005 and
2004. On a per BOE basis, G&A costs increased 57% in the third quarter of 2005
as compared to the level of those costs in third quarter of 2004, and increased
67% between the comparative first nine months of 2004 and 2005, both higher
percentage increases than the increase in gross costs, which resulted from lower
production caused by the July 2004 sale of our offshore properties and the
production lost due to the two hurricanes. Since virtually all the cost of our
personnel that worked directly on the offshore properties sold in 2004 was
charged to either operations or capitalized, the sale of our offshore properties
had minimal impact on net G&A.
Interest and Financing Expenses
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------- ------------------------------ ------------------------------
Amounts in thousands, except per BOE amounts 2005 2004 2005 2004
- ------------------------------------------------- -------------- --------------- --------------- --------------
Cash interest expense $ 4,658 $ 4,464 $ 13,694 $ 14,160
Non-cash interest expense 264 304 673 757
Less: Capitalized interest (415) - (1,049) -
-------------- --------------- --------------- --------------
Interest expense $ 4,507 $ 4,768 $ 13,318 $ 14,917
============== =============== =============== ==============
Interest and other income $ 716 $ 701 $ 2,026 $ 1,450
============== =============== =============== ==============
Average net cash interest expense per BOE (1) $ 1.43 $ 1.38 $ 1.34 $ 1.35
Average interest rate (2) 7.5% 7.3% 7.5% 6.6%
Average debt outstanding $ 249,711 $ 243,478 $ 242,711 $ 286,139
-------------- --------------- --------------- --------------
- ---------------------------------------
(1) Cash interest expense less capitalized interest less interest and other
income on BOE basis.
(2) Includes commitment fees but excludes amortization of discount and debt
issue costs.
Interest expense for the first nine months of 2005 decreased from levels in
the comparable periods of 2004 primarily due to lower average debt in 2005 as a
result of the sale of our offshore properties in July 2004, the proceeds from
which were used to retire our bank debt. Interest expense also decreased between
the comparable third quarters as we capitalized $415,000 of interest, primarily
relating to the construction of our CO2 pipeline to East Mississippi, which more
than offset higher interest rates on our bank debt and slightly higher debt
levels. As a result of the lower production because of the 2004 offshore sale
and production lost as a result of the two hurricanes, interest expense on a per
BOE basis was not as positive as it was on an absolute basis.
30
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 2005 2004 2005 2004
- ------------------------------------------------ --------------- -------------- -------------- ---------------
Depletion and depreciation $ 21,878 $ 18,658 $ 63,414 $ 69,357
Depletion and depreciation of CO2 assets 1,311 1,200 3,685 3,577
Accretion of asset retirement obligations 435 429 1,278 1,971
Depreciation of other fixed assets 716 493 1,896 1,360
--------------- -------------- -------------- ---------------
Total DD&A $ 24,340 $ 20,780 $ 70,273 $ 76,265
=============== ============== ============== ===============
DD&A per BOE:
Oil and natural gas properties $ 8.87 $ 7.00 $ 8.12 $ 7.59
CO2 assets and other fixed assets 0.81 0.62 0.70 0.53
- ------------------------------------------------ --------------- -------------- -------------- ---------------
Total DD&A cost per BOE $ 9.68 $ 7.62 $ 8.82 $ 8.12
================================================ =============== ============== ============== ===============
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis increased 27% between the respective third quarters, primarily due
to rising costs and increases in capital spending in the first nine months of
2005. During the first nine months of 2005, we spent approximately $71.2 million
on acquisitions, of which approximately $50.1 million was included in our full
cost pool, with the balance becoming part of our unevaluated properties. Due to
high commodity prices, the acquisition cost per BOE was around $12.00 per BOE,
contributing to the higher DD&A rate. In addition, most of our future
development cost estimates on our proved undeveloped reserves have been
increased to reflect the rising costs in the industry, contributing to the
increase in our 2005 DD&A rates over the rates last year. We booked
approximately 2.9 MMBbls of minor incremental oil reserves related to our
tertiary operations during the first nine months of 2005, less than we may be
able to recognize by year-end. Since we adjust our DD&A rate each quarter based
on any changes in our estimates of oil and natural gas reserves and costs, our
DD&A rate could significantly change in the future.
Income Taxes
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------ ------------------------------ ------------------------------
Amounts in thousands, except per BOE amounts and tax rates 2005 2004 2005 2004
- ------------------------------------------------------------ -------------- --------------- -------------- ---------------
Income tax provision
Current income tax expense $ 7,684 $ 18,949 $ 17,320 $ 22,045
Deferred income tax expense (benefit) 12,324 (11,117) 36,380 6,077
-------------- --------------- -------------- ---------------
Total income tax expense $ 20,008 $ 7,832 $ 53,700 $ 28,122
============== =============== ============== ===============
Average income tax expense per BOE $ 7.95 $ 2.87 $ 6.74 $ 2.99
Effective tax rate 34.2% 30.0% 32.9% 31.9%
- ------------------------------------------------------------ -------------- --------------- -------------- ---------------
Our income tax provision for the third quarter and first nine months of
2005 was based on an estimated statutory tax rate of 39%, and for the comparable
2004 periods was based on an estimated statutory tax rate of 38%. Our net
effective tax rate was lower than our estimated statutory rates due primarily to
our enhanced oil recovery ("EOR") tax credits we earn related to our tertiary
operations and to a lesser degree to a new manufacturing deduction that became
allowable in 2005 for oil and gas producing activities covered by the American
Jobs Creation Act of 2004. Our current income tax expense represents anticipated
alternative minimum cash taxes. As of December 31, 2004, we had utilized all of
our federal tax net operating loss carryforwards, but had an estimated $27.8
million of EOR credits to carryforward. We expect to generate additional net EOR
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
credits during 2005, although if oil prices remain at current levels or increase
further, we may not be able to generate additional credits in future years as
these EOR credits phase out if oil prices are above a certain threshold.
Per BOE Data
The following table summarizes our cash flow, DD&A and results of
operations on a per BOE basis for the comparative periods. Each of the
individual components are discussed above.
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------------------------------------- --------------------------- ---------------------------
Per BOE data 2005 2004 2005 2004
- --------------------------------------------------------------- ------------- ------------- ------------- -------------
Revenues $ 55.07 $ 37.78 $ 47.13 $ 35.38
Loss on settlements of derivative contracts (1.50) (8.15) (0.83) (5.83)
Lease operating expenses (10.33) (7.25) (9.51) (7.11)
Production taxes and marketing expenses (2.79) (1.80) (2.48) (1.44)
- --------------------------------------------------------------- ------------- ------------- ------------- -------------
Production netback 40.45 20.58 34.31 21.00
CO2 operating margin 0.78 0.55 0.55 0.43
General and administrative expenses (3.56) (2.27) (2.69) (1.61)
Net cash interest expense (1.43) (1.38) (1.34) (1.35)
Current income taxes and other (1.52) (6.57) (0.86) (2.32)
Changes in assets and liabilities relating to operations (4.40) 5.50 (0.93) (0.08)
- --------------------------------------------------------------- ------------- ------------- ------------- -------------
Cash flow from operations 30.32 16.41 29.04 16.07
DD&A (9.68) (7.62) (8.82) (8.12)
Deferred income taxes (4.90) 4.07 (4.57) (0.65)
Non-cash hedging adjustments (3.20) 0.14 (1.50) (0.89)
Changes in assets and liabilities and other non-cash items 2.78 (6.30) (0.43) (0.03)
- --------------------------------------------------------------- ------------- ------------- ------------- -------------
Net income $ 15.32 $ 6.70 $ 13.72 $ 6.38
=============================================================== ============= ============= ============= =============
MARKET RISK MANAGEMENT
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. The following table presents the carrying and fair
values of our debt, along with average interest rates. The fair value of our
bank debt is considered to be the same as the carrying value because the
interest rate is based on floating short-term interest rates. The fair value of
the subordinated debt is based on quoted market prices. None of our debt has any
triggers or covenants regarding our debt ratings with rating agencies.
Expected Maturity Dates
- ----------------------------------- ----------------------------------------------------- ------------- -----------
2005- Carrying Fair
Amounts in thousands 2006 2007 2008 2009 After Value Value
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ------------- -----------
Variable rate debt:
Bank debt....................... $ - $ - $ - $ 20,000 $ - $ 20,000 $ 20,000
The weighted-average interest rate on the bank debt at September 30, 2005 is 4.9%
Fixed rate debt:
7.5% subordinated debt,
net of discount, due 2013..... $ - $ - $ - $ - $225,000 $ 223,543 $ 233,438
The interest rate on the subordinated debt is a fixed rate of 7.5%
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
32
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Historically, we have generally attempted 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, although our
hedging percentage may vary relative to our debt levels. For 2005 and beyond, we
have hedged significantly less, primarily because of our strong financial
position, measured by our low levels of debt relative to our cash flow from
operations. When we make a significant acquisition, we have historically
attempted to hedge a large percentage, up to 100%, of the forecasted proved
production for the subsequent one to three years following the acquisition in
order to help provide us with a minimum return on our investment. We have not
made any large acquisitions during the last couple of years, so we do not have
any hedges in place at this time for prior acquisitions.
All of the mark-to-market valuations used for our financial derivatives are
provided by external sources and are based on prices that are actively quoted.
We manage and control market and counterparty credit risk through established
internal control procedures that are reviewed on an ongoing basis. We attempt to
minimize credit risk exposure to counterparties through formal credit policies,
monitoring procedures, and diversification. For a full description of our
hedging position at September 30, 2005, see Note 5 to the Condensed Consolidated
Financial Statements.
Effective January 1, 2005, we elected to de-designate our existing
derivative contracts from hedge accounting treatment and to account for them as
speculative contracts going forward. This means that any changes in the fair
value of these derivative contracts will be charged to earnings on a quarterly
basis instead of charging the effective portion to other comprehensive income
and the ineffective portion to earnings. This also means that any balance
remaining in other comprehensive income as of December 31, 2004 is being
amortized over the remaining life of the contracts (2005). During the third
quarter of 2005, we recognized total expense relating to our hedge contracts of
$11.8 million, consisting of $3.8 of cash payments, $6.2 million of expense
relating to a mark-to-market non-cash adjustment, and $1.8 million of expense
relating to the amortization of other comprehensive income related to deferred
hedge mark-to-market value losses that existed as of December 31, 2004 which are
being amortized as the contracts expire during 2005. For the first nine months
of 2005, we recognized total expense relating to our hedge contracts of $18.6
million, consisting of $6.6 million of cash payments, $6.5 million of expense
relating to a mark-to-market non-cash adjustment and $5.5 million of expense
relating to the amortization of other comprehensive income. Information
regarding our current hedging positions and historical hedging results is
included in Note 5 to the Condensed Consolidated Financial Statements.
At September 30, 2005, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $11.4 million, a larger
liability than the $6.5 million fair value liability recorded as of December 31,
2004. This change is the result of a decrease in the fair market value of our
remaining hedges (i.e. an increased obligation amount) due to an increase in oil
and natural gas commodity prices between December 31, 2004 and September 30,
2005, partially offset by the expiration of approximately 75% of our remaining
hedge contracts between January 1, 2005 and September 30, 2005.
Based on NYMEX crude oil futures prices at September 30, 2005, oil prices
were considerably higher than the floor price of $27.50 per barrel in our
hedges, so we would not expect to receive any funds even if oil prices were to
drop 10%. Since the oil hedges are puts or price floors, we do not have to make
any payments on the hedges regardless of how high oil prices go. Based on NYMEX
natural gas futures prices at September 30, 2005, we would expect to make future
cash payments of $11.4 million on our natural gas commodity hedges. If natural
gas futures prices were to decline by 10%, the amount we would expect to pay
under our natural gas commodity hedges would decrease to $9.5 million, and if
futures prices were to increase by 10% we would expect to pay $13.3 million.
CRITICAL ACCOUNTING POLICIES
For a discussion of our critical accounting policies, which are related to
property, plant and equipment, depletion and depreciation, oil and natural gas
reserves, asset retirement obligations, income taxes and hedging activities, and
which remain unchanged, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in our annual report on Form 10-K for the
year ended December 31, 2004.
33
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RECENT ACCOUNTING PRONOUNCEMENTS
On December 16, 2004, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R)
supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally,
the approach in SFAS No. 123(R) is similar to the approach described in SFAS No.
123. However, SFAS No. 123(R) will require all share-based payments to
employees, including grants of employee stock options, to be recognized in our
Consolidated Statements of Operations based on their estimated fair values. Pro
forma disclosure is no longer an alternative.
SFAS No. 123(R) must be adopted at the beginning of our next fiscal year
(i.e., January 1, 2006) and permits public companies to adopt its requirements
using one of two methods:
o A "modified prospective" method in which compensation cost is
recognized based on the requirements of SFAS No. 123(R) for all
share-based payments granted prior to the effective date of SFAS No.
123(R) that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of
the modified prospective method described above, but also permits
entities to restate either all prior periods presented or prior
interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
As permitted by SFAS No. 123, we currently account for share-based payments
to employees using the intrinsic value method prescribed by APB 25 and related
interpretations. As such, we generally do not recognize compensation expense
associated with employee stock options. Accordingly, the adoption of SFAS No.
123(R)'s fair value method could have a significant impact on Denbury's future
results of operations, although it will have no impact on our overall financial
position. We currently plan to adopt the provisions of SFAS No. 123(R) on
January 1, 2006 using the modified prospective approach. We have not completed
evaluating the impact the adoption of SFAS No. 123(R) will have on our future
results of operations.
SFAS No. 123(R) also requires the tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce Denbury's future cash provided by operating activities and
increase future cash provided by financing activities, to the extent of
associated tax benefits that may be realized in the future; however, it will not
have an impact on the Company's overall cash flows.
FORWARD-LOOKING INFORMATION
The statements contained in this Quarterly Report on Form 10-Q 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, forecasted capital expenditures, transportation
charges, drilling activity or methods, acquisition plans and proposals and
dispositions, development activities, cost savings, production rates and volumes
or forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve
quantities and values, potential reserves from tertiary operations or particular
fields, hydrocarbon prices, pricing assumptions based upon current and projected
oil and gas prices, liquidity, regulatory matters, mark-to-market values,
competition, long-term forecasts of production, finding costs, rates of return,
estimated costs, future capital expenditures and overall economics and other
variables surrounding our tertiary operations and future plans. Such
forward-looking statements generally are accompanied by words such as "plan,"
"estimate," "expect," "predict," "anticipate," "projected," "should," "assume,"
"believe," "target" 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 the Company's 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 the Company's oil and natural gas,
inaccurate cost estimates, fluctuations in the prices of goods and services
(especially in periods of high demand and/or drilling activity), the uncertainty
of drilling results and reserve estimates, operating hazards, acquisition risks,
34
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
requirements for capital or its availability, the availability of equipment and
personnel, general economic conditions, competition and government regulations,
unexpected delays, as well as the risks and uncertainties inherent in oil and
gas drilling and production activities or which are otherwise discussed in this
annual 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.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- -------------------------------------------------------------------
The information required by Item 3 is set forth under "Market Risk
Management" in Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Item 4. Controls and Procedures
- --------------------------------
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our chief executive officer and chief financial
officer have evaluated our disclosure controls and procedures 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 ensuring that
material information required to be disclosed in this quarterly report is
accumulated and communicated to them and our management to allow timely
decisions regarding required disclosure.
In January 2005, we began processing our transactions on a newly
implemented accounting software system. We changed systems in order (i) to
integrate and automate more of our functions, which will also allow us to have
more information in one integrated database, (ii) to provide operating
efficiencies, (iii) to enable us to close our books in a more timely manner
without sacrificing quality, (iv) to review and improve our processes and (v)
improve the internal control surrounding our computer systems. As a result of
moving to a new system in January 2005, certain control procedures are still
being changed, documented, and evaluated in order to conform to our new system.
While we believe that our new accounting system will ultimately strengthen our
internal control system, there are inherent weaknesses in implementing any new
system and we are still testing these control changes in order to enable us to
provide certification as of year-end of the effectiveness in all material
respects of our internal controls over financial reporting that are affected by
this new software system. While we have not found any reason to believe that our
internal controls over financial reporting are not effective in all material
respects, we are continuing to evaluate the impact and effect of a new
accounting system on our internal controls and procedures and it is possible
that we may find weaknesses in the future.
During 2005, information was reported on our whistleblower hotline
regarding misconduct by oilfield vendors and certain employees, including
alleged improper billings and payments by certain vendors to, or on behalf of
employees, misuse of Company property and operational information, and the
failure by employees to report transactions entered into with the Company. At
the direction of the audit committee of our board of directors, and in
conjunction with outside counsel retained by the Audit Committee, investigations
have been undertaken to (1) gain an understanding of both the facts and
circumstances surrounding these matters, (2) review our management practices and
internal controls as they relate to these areas, (3) ascertain whether, in fact,
there were violations of the Company's Code of Conduct and Ethics, (4) make
recommendations as to necessary improvements in such practices and controls, and
(5) recommend other corrective actions, as deemed appropriate. As a result of
our investigations, to date we have dismissed two employees, taken disciplinary
action against another employee, and terminated all future business with vendors
identified to date as making improper billings and payments. The estimated
amount of improper vendor billings and payments discovered to date is
inconsequential to our previously issued financial statements and to the
financial statements contained in this report on Form 10-Q. We expect to recover
a portion of the improper vendor billings from our vendors. We further believe
that the ultimate resolution of these matters will not materially adversely
affect our financial condition, results of operations or business. We believe
that our whistleblower hotline was effective in alerting us to improper vendor
and employee conduct and allowing us to remedy the matter.
Controls and policies in place to prevent these occurrences were overridden
by employee misconduct in the vendor approval and payment process and in
adherence to the Company's Code of Conduct and Ethics. As a result of our
35
DENBURY RESOURCES INC.
investigation, we plan to implement certain improvements to strengthen our
management practices and policies and internal controls, as set forth below:
1. Heighten authorization and documentation requirements for purchasing,
including plans to implement a centralized purchasing function;
2. Contact our vendors to inform them of the changes in our procurement
practices and pursue their cooperation and assistance in complying
with and assisting us in enforcing our new policies;
3. Increase our internal audit reviews in the area of purchasing,
bidding, and invoice approval; and
4. Review, refine, emphasize and enforce our Code of Conduct and Ethics
and purchasing policies and procedures with employees and vendors.
Part II. Other Information
Item 1. Legal Proceedings
- -------------------------
Information with respect to this item has been incorporated by reference
from our Form 10-K for the year ended December 31, 2004. There have been no
material developments in such legal proceedings since the filing of such Form
10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
- --------------------------------------------------------------------
ISSUER PURCHASES OF EQUITY SECURITIES
- ----------------------------------------------------------------------------------------------------------
(c) Total Number of (d) Maximum Number
(a) Total Shares Purchased of Shares that May
Number of (b) Average as Part of Publicly Yet Be Purchased
Shares Price Paid Announced Plans or Under the Plan Or
Period Purchased per Share Programs Programs
- ------------------------------- ----------- ------------ -------------------- -----------------------
July 1 through 31, 2005 - - - -
August 1 through 31, 2005 84,574 $ 23.11 - -
September 1 through 30, 2005 - - - -
- ------------------------------- ----------- ------------ -------------------- -----------------------
Total 84,574 $ 23.11 - -
- ------------------------------- ----------- ------------ -------------------- -----------------------
The numbers above have been adjusted for the 2-for-1 stock split effective
October 31, 2005. These shares were purchased from officers of Denbury who
delivered shares to the Company to satisfy their minimum tax withholding
requirements related to the vesting of restricted shares that were originally
granted in August 2004, as permitted under the Company's 2004 Omnibus Stock and
Incentive Plan.
Item 3. Defaults Upon Senior Securities
- ----------------------------------------
None.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
None.
Item 5. Other Information
- --------------------------
None.
36
Item 6. Exhibits
- -----------------
Exhibits:
--------
3(a)* Certificate of Amendment of Restated Certificate of
Incorporation of Denbury Resources Inc. filed with the
Delaware Secretary of State on October 20, 2005.
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.
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 7, 2005
37