UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
---------
(Mark One)
[X] Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 2005
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 1-12935
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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 July 31, 2005
----- ----------------------------
Common Stock, $.001 par value 57,130,767
INDEX
Page
Part I. Financial Information
- -----------------------------
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at June 30, 2005 and
December 31, 2004 3
Unaudited Condensed Consolidated Statements of Operations for the Three and Six
Months Ended June 30, 2005 and 2004 4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Six
Months Ended June 30, 2005 and 2004 5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for
the Three and Six Months Ended June 30, 2005 and 2004 6
Notes to Unaudited Condensed Consolidated Financial Statements 7-19
Item 2. Management's Discussion and Analysis of Financial Condition 20-33
and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk 34
Item 4. Controls and Procedures 34
Part II. Other Information
- ---------------------------
Item 1. Legal Proceedings 35
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 35
Item 3. Defaults Upon Senior Securities 35
Item 4. Submission of Matters to a Vote of Security Holders 35
Item 5. Other Information 36
Item 6. Exhibits 36
Signatures 37
2
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
June 30, December 31,
2005 2004
------------- ---------------
Assets
Current assets
Cash and cash equivalents $ 25,316 $ 33,039
Short-term investments 2,000 57,171
Accrued production receivables 52,445 44,790
Related party receivable - Genesis 484 745
Trade and other receivables 19,474 10,963
Deferred tax asset 28,629 25,189
Derivative assets - 949
------------- ---------------
Total current assets 128,348 172,846
------------- ---------------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,516,229 1,326,401
Unevaluated 42,017 20,253
CO2 properties and equipment 167,750 132,685
Other 31,322 25,929
Less accumulated depletion and depreciation (752,885) (707,906)
------------- ---------------
Net property and equipment 1,004,433 797,362
------------- ---------------
Investment in Genesis 6,856 6,791
Other assets 10,868 15,707
------------- ---------------
Total assets $ 1,150,505 $ 992,706
============= ===============
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 73,258 $ 49,429
Current deferred revenue and other - Genesis 2,432 2,431
Oil and gas production payable 29,153 24,856
Derivative liabilities 5,212 5,815
Short-term capital lease obligations - Genesis 547 375
------------- ---------------
Total current liabilities 110,602 82,906
------------- ---------------
Long-term liabilities
Capital lease obligations - Genesis 6,163 4,184
Long-term debt 233,494 223,397
Asset retirement obligations 22,788 18,944
Deferred revenue - Genesis 22,086 23,378
Deferred tax liability 125,995 97,125
Other 2,517 1,100
------------- ---------------
Total long-term liabilities 413,043 368,128
------------- ---------------
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized,
none issued and outstanding - -
Common stock, $.001 par value, 100,000,000 shares authorized;
57,234,182 and 56,607,877 shares issued at June 30, 2005 and
December 31, 2004, respectively 57 57
Paid-in capital in excess of par 453,686 441,023
Deferred compensation (19,891) (21,678)
Retained earnings 199,843 129,104
Accumulated other comprehensive loss (2,547) (4,788)
Treasury stock, at cost, 157,726 and 93,072 shares at June 30,
2005 and December 31, 2004, respectively (4,288) (2,046)
------------- ---------------
Total stockholders' equity 626,860 541,672
------------- ---------------
Total liabilities and stockholders' equity $ 1,150,505 $ 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 Six Months Ended
June 30, June 30,
--------------------------- ----------------------------
2005 2004 2005 2004
------------- ------------- ------------- -------------
Revenues and other income
Oil, natural gas and related product sales
Unrelated parties $ 124,277 $ 95,706 $ 234,810 $ 186,980
Related party - Genesis 1,495 23,365 1,978 42,327
CO2 sales and transportation fees
Unrelated parties 72 319 464 603
Related party - Genesis 1,445 1,261 2,783 2,338
Loss on effective hedge contracts - (14,724) - (28,992)
Interest income and other 694 330 1,310 749
------------- ------------- ------------- --------------
Total revenues and other income 127,983 106,257 241,345 204,005
------------- ------------- ------------- --------------
Expenses
Lease operating expenses 26,757 24,530 49,719 47,058
Production taxes and marketing expenses 5,528 4,514 10,718 8,581
Transportation expense - Genesis 1,054 - 1,990 -
CO2 operating expenses 445 209 791 353
General and administrative expenses 5,992 4,178 12,487 8,926
Interest, net of amounts capitalized of $373,
none, $635 and none, respectively 4,335 5,068 8,811 10,149
Depletion and depreciation 24,405 28,161 45,933 55,485
Commodity derivative expense (income) (1,025) 10,661 6,796 11,479
------------- ------------- ------------- --------------
Total expenses 67,491 77,321 137,245 142,031
------------- ------------- ------------- --------------
Equity in net income of Genesis 44 102 331 9
------------- ------------- ------------- --------------
Income before income taxes 60,536 29,038 104,431 61,983
Income tax provision
Current income taxes 4,354 977 9,636 3,096
Deferred income taxes 15,510 8,672 24,056 17,194
------------- ------------- ------------- --------------
Net income $ 40,672 $ 19,389 $ 70,739 $ 41,693
============= ============= ============= ==============
Net income per common share - basic $ 0.73 $ 0.35 $ 1.27 $ 0.76
Net income per common share - diluted $ 0.69 $ 0.34 $ 1.20 $ 0.73
Weighted average common shares outstanding
Basic 55,653 54,744 55,557 54,566
Diluted 58,972 57,102 59,035 56,739
(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 Six Months Ended
June 30, June 30,
----------------------- -----------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Cash flow from operating activities:
Net income $ 40,672 $ 19,389 $ 70,739 $ 41,693
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation and depletion 24,405 28,161 45,933 55,485
Non-cash hedging adjustments (2,801) 7,146 3,921 7,964
Deferred income taxes 15,510 8,672 24,056 17,194
Deferred revenue - Genesis (670) (599) (1,292) (1,110)
Deferred compensation - restricted stock 1,031 - 2,059 -
Current income tax benefit from stock options 3,354 - 5,434 -
Amortization of debt issue costs and other 450 285 512 748
Changes in assets and liabilities:
Accrued production receivable (1,475) (3,410) (7,394) (10,836)
Trade and other receivables (5,422) (546) (8,510) (1,773)
Derivative assets and liabilities - (7,518) - (7,518)
Other assets - - 130 -
Accounts payable and accrued liabilities 8,574 (1,012) 15,818 711
Oil and gas production payable 4,981 3,230 4,298 5,028
Other liabilities (224) (588) (690) (1,381)
----------- ----------- ----------- -----------
Net cash provided by operations 88,385 53,210 155,014 106,205
----------- ----------- ----------- -----------
Cash flow used for investing activities:
Oil and natural gas expenditures (81,685) (42,014) (138,880) (89,764)
Acquisitions of oil and gas properties (37,763) (2,035) (68,544) (2,198)
Change in accrual for capital expenditures (2,249) - 8,990 -
Acquisitions of CO2 assets and capital expenditures (7,155) (6,938) (35,118) (27,141)
Purchases of other assets (1,169) (850) (3,099) (1,154)
Proceeds from oil and gas property sales (5) 634 (23) 1,146
Deposits on oil and gas property acquisitions - - 4,507 -
Sales of short-term investments 12,558 - 55,133 -
Increase in restricted cash (62) (148) (110) (351)
----------- ----------- ----------- -----------
Net cash used for investing activities (117,530) (51,351) (177,144) (119,462)
----------- ----------- ----------- -----------
Cash flow from financing activities:
Bank repayments (5,800) - (19,800) (3,000)
Bank borrowings 15,800 5,000 29,800 13,000
Payments on capital lease obligations - Genesis (129) - (254) -
Issuance of common stock 3,464 4,795 7,825 8,674
Purchase of treasury stock (1,616) (918) (3,164) (1,661)
Costs of debt financing - (4) - (4)
----------- ----------- ----------- -----------
Net cash provided by financing activities 11,719 8,873 14,407 17,009
----------- ----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents (17,426) 10,732 (7,723) 3,752
Cash and cash equivalents at beginning of period 42,742 17,208 33,039 24,188
----------- ----------- ----------- -----------
Cash and cash equivalents at end of period $ 25,316 $ 27,940 $ 25,316 $ 27,940
=========== =========== =========== ===========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 8,647 $ 514 $ 8,906 $ 9,463
Cash paid during the period for income taxes 7,500 600 7,500 327
(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 Six Months Ended
June 30, June 30,
----------------------- -----------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Net income $ 40,672 $ 19,389 $ 70,739 $ 41,693
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts, net of tax of
$(5,926) and $(12,671), respectively - (9,669) - (20,673)
Reclassification adjustments related to settlements of derivative
contracts, net of tax of $669, $10,348, $1,359, and $15,770, respectively 1,092 16,884 2,217 25,730
Unrealized gain on securities available for sale 22 - 24 -
----------- ----------- ----------- -----------
Comprehensive income $ 41,786 $ 26,604 $ 72,980 $ 46,750
=========== =========== =========== ===========
(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 June 30, 2005 and the consolidated results
of its operations and cash flows for the three and six month periods ended June
30, 2005 and 2004. Certain prior period items have been reclassified to make the
classification consistent with the classification in the most recent quarter.
Net Income Per Common Share
Basic net income per common share is computed by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
Diluted net income per common share is calculated in the same manner but also
considers the impact on net income and common shares for the potential dilution
from stock options and any other convertible securities outstanding. For the
three and six month periods ended June 30, 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 six month periods ended June 30, 2005 and 2004.
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
(shares in thousands) 2005 2004 2005 2004
----------- ----------- ----------- -----------
Weighted average common shares - basic......... 55,653 54,744 55,557 54,566
Potentially dilutive securities:
Stock options............................... 2,873 2,358 3,068 2,173
Restricted stock............................ 446 - 410 -
----------- ----------- ----------- -----------
Weighted average common shares - diluted....... 58,972 57,102 59,035 56,739
=========== =========== =========== ===========
The weighted average common shares - basic amount in 2005 excludes
1,160,000 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
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 June 30, 2005 and 2004, stock options to
purchase approximately 62,000 and 32,000 shares of common stock, and for the six
months ended June 30, 2005 and 2004, stock options to purchase approximately
90,000 and 361,000 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
7
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
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 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 Six Months Ended
June 30, June 30,
----------------------- -----------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Net income: (thousands)
Net income, as reported........................................... $ 40,672 $ 19,389 $ 70,739 $ 41,693
Add: stock-based compensation included in reported
net income, net of related tax effects......................... 693 - 1,394 -
Less: stock-based compensation expense applying fair
value based method, net of related tax effects................. 1,874 592 3,490 1,085
----------- ----------- ----------- -----------
Pro-forma net income.............................................. $ 39,491 $ 18,797 $ 68,643 $ 40,608
=========== =========== =========== ===========
Net income per common share
As reported:
Basic.......................................................... $ 0.73 $ 0.35 $ 1.27 $ 0.76
Diluted........................................................ 0.69 0.34 1.20 0.73
Pro forma:
Basic.......................................................... $ 0.71 $ 0.34 $ 1.24 $ 0.74
Diluted........................................................ 0.68 0.33 1.17 0.72
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 six months of 2005, we sold all of our available-for-sale
securities except for $2.0 million of certificates of deposit that we held at
June 30, 2005.
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.
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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. Had the Company adopted SFAS No.123(R) in prior periods, we estimate
that the impact would have approximated the impact of SFAS No. 123 as described
in the pro forma net income and earnings per share disclosures above. The
adoption of SFAS No. 123(R) will have no effect on the accounting for the
Company's unvested outstanding restricted stock awards. We currently plan to
adopt the provisions of SFAS No. 123(R) on January 1, 2006 using the modified
prospective approach. Although we have not completed evaluating the impact the
adoption of SFAS No. 123(R) will have on our future results of operations, we
currently estimate the impact on an annual basis will be similar to that in our
pro forma disclosures for SFAS No. 123 above.
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. While we cannot
estimate what those amounts will be in the future (because they depend, among
other things, upon when employees exercise stock options), the amount of
operating cash flows recognized for such excess tax deductions was approximately
$5.4 million for the six months ended June 30, 2005.
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.
The following table summarizes the changes in our asset retirement
obligations for the six months ended June 30, 2005.
Six Months Ended
June 30, 2005
--------------------
(in thousands)
Beginning asset retirement obligation, as of 12/31/2004.......... $ 21,540
Liabilities incurred during period............................... 1,815
Revisions in estimated cash flows................................ 597
Liabilities settled during period................................ (389)
Accretion expense................................................ 843
--------------------
Ending asset retirement obligation............................... $ 24,406
====================
9
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At June 30, 2005, $1.6 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
$6.5 million at June 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 50,000 shares of
Denbury's common stock per fiscal quarter over a period of approximately twelve
months, or a total of 200,000 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 200,000 shares at an average cost
of $19.89 per share and reissued 115,090 treasury shares under the ESPP. In the
first six months of 2005, we repurchased into treasury 100,000 shares at an
average cost of $31.64 per share and reissued 35,346 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 for the three months ended June 30, 2005 and 2004 was $44,000 and
$102,000, and for the six months ended June 30, 2005 and 2004 was $331,000 and
$9,000, respectively. Genesis Energy, Inc., the general partner of which we own
100%, has guaranteed the bank debt of Genesis, which as of June 30, 2005 was
$34.4 million, plus $9.7 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
trucking services. For the three and six months ended June 30, 2005, we expensed
$1.1 million and $2.0 million, respectively, for these transportation services.
We recorded oil sales to Genesis of $1.5 million and $23.4 million for the
respective quarters ended June 30, 2005 and 2004, and $2.0 million and $42.3
million for the respective six months ended June 30, 2005 and 2004. Denbury
received other miscellaneous payments from Genesis for the six months ended June
30, 2005 and 2004, including $60,000 in each period of director fees for certain
executive officers of Denbury that are board members of Genesis, and $255,000
and $253,000, 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
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2005, we had $6.7
million of capital lease obligations recorded as liabilities in our Condensed
Consolidated Balance Sheet, of which $547,000 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 June 30, 2005 and
December 31, 2004, $24.5 million and $25.8 million, respectively, was recorded
as deferred revenue of which $2.4 million was included in current liabilities at
June 30, 2005 and December 31, 2004. We recognized deferred revenue of $0.7
million and $0.6 million during the three months ended June 30, 2005 and 2004
and $1.3 and $1.1 million for the six months ended June 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 June 30, 2005 and 2004 and $1.5 million and $1.2
million for the six months ended June 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 June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2005 2004 2005 2004
------------- ------------- ------------- -------------
Revenues........................................ $ 257,144 $ 232,107 $ 513,744 $ 431,019
Cost of sales................................... 252,129 227,045 503,873 421,858
Other expenses ................................. 4,263 3,902 6,631 8,783
Income (loss) from discontinued operations...... (9) (61) 273 (284)
------------- ------------- ------------- -------------
Net income.................................... $ 743 $ 1,099 $ 3,513 $ 94
============= ============= ============= =============
June 30, December 31,
2005 2004
------------- -------------
Current assets.................................. $ 100,247 $ 77,396
Non-current assets.............................. 80,869 65,758
------------- -------------
Total assets.................................. $ 181,116 $ 143,154
============= =============
Current liabilities ............................ $ 100,106 $ 81,938
Non-current liabilities......................... 34,592 15,460
Partners' capital............................... 46,418 45,756
------------- -------------
Total liabilities and partners' capital...... $ 181,116 $ 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. 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 Six Months Ended
(In Thousands) June 30, 2004 June 30, 2004
- -------------------------------------------------- --------------------- ---------------------
Settlements of hedge contracts - Oil.............. $ (9,795) $ (20,316)
Settlements of hedge contracts - Gas.............. (4,929) (8,676)
--------------------- ----------------------
Loss on effective hedge contracts.............. $ (14,724) $ (28,992)
===================== ======================
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following is a summary of "Commodity Derivative Expense (Income)"
included in our Condensed Consolidated Statements of Operations:
Three Months Six Months
(In Thousands) Ended June 30, Ended June 30,
- --------------------------------------------------------------------------------------------------- ------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Settlements of derivative contracts not designated as hedges - Oil..... $ - $ 3,515 $ - $ 3,515
Settlements of derivative contracts not designated as hedges - Gas..... 1,776 - 2,875 -
Hedge ineffectiveness on contracts qualifying for hedge
accounting.......................................................... - (785) - 33
Reclassification of accumulated other comprehensive income
balance............................................................. 1,761 8,993 3,575 8,993
Adjustments to fair value associated with contracts no longer
designated as hedges................................................. (4,562) 468 346 468
Adjustment to fair value associated with contracts transferred in
sale of offshore production.......................................... - (1,530) - (1,530)
----------- ----------- ----------- -----------
Commodity derivative expense (income).............................. $ (1,025) $ 10,661 $ 6,796 $ 11,479
=========== =========== =========== ===========
Derivative Contracts at June 30, 2005
Crude Oil Contracts:
- -------------------
NYMEX Contract Prices Per Bbl
-----------------------------------------------
Collar Prices Fair Value at
---------------------- June 30, 2005
Type of Contract and Period Bbls/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ----------- ------------ ---------- ---------- -----------------
Floor Contracts
July 2005 - Dec. 2005 7,500 $ 27.50 - - $ -
Natural Gas Contracts:
- ---------------------
NYMEX Contract Prices Per MMBtu
-----------------------------------------------
Collar Prices Fair Value at
---------------------- June 30, 2005
Type of Contract and Period MMBtu/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ----------- ------------ ---------- ---------- -----------------
Collar Contracts
July 2005 - Dec. 2005 15,000 - $ 3.00 $ 5.50 $ (5,212)
At June 30, 2005, our derivative contracts were recorded at their fair
value, which was a net liability of $5.2 million. The balance in accumulated
other comprehensive loss of $2.5 million at June 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 $2.5 million in accumulated other comprehensive loss as of
June 30, 2005 will expire by December 31, 2005.
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
June 30, December 31,
(In Thousands) 2005 2004
- ------------------------------------------------- ------------- -------------
Accounts payable................................. $ 37,329 $ 26,262
Accrued compensation............................. 3,622 5,613
Accrued exploration and development costs........ 14,429 5,439
Accrued interest ................................ 4,235 4,219
Asset retirement obligations - current........... 1,618 2,596
Other............................................ 12,025 5,300
-------------- -------------
Total.......................................... $ 73,258 $ 49,429
================================================= ============== =============
7. 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
June 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................................. $ 216,002 $ 126,640 $ 2,992 $ (217,286) $ 128,348
Property and equipment ........................ - 1,004,372 61 - 1,004,433
Investment in subsidiaries (equity method)..... 408,527 - 407,092 (808,763) 6,856
Other assets................................... 2,331 10,868 213 (2,544) 10,868
---------------- --------------- ------------ -------------- ---------------
Total assets................................. $ 626,860 $ 1,141,880 $ 410,358 $ (1,028,593) $ 1,150,505
================ =============== ============ ============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities............................ $ - $ 326,286 $ 1,602 $ (217,286) $ 110,602
Long-term liabilities ......................... - 415,358 229 (2,544) 413,043
Stockholders' equity .......................... 626,860 400,236 408,527 (808,763) 626,860
---------------- --------------- ------------ -------------- ---------------
Total liabilities and stockholders' equity... $ 626,860 $ 1,141,880 $ 410,358 $ (1,028,593) $ 1,150,505
================ =============== ============ ============== ===============
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 June 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.................................... $ - $ 127,983 $ - $ - $ 127,983
Expenses.................................... 41 67,198 252 - 67,491
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (41) 60,785 (252) - 60,492
Equity in net earnings of subsidiaries.... 40,697 - 40,868 (81,521) 44
---------------- --------------- ------------ -------------- ---------------
Income before income taxes.................. 40,656 60,785 40,616 (81,521) 60,536
Income tax provision (benefit).............. (16) 19,961 (81) - 19,864
---------------- --------------- ------------ -------------- ---------------
Net income.................................. $ 40,672 $ 40,824 $ 40,697 $ (81,521) $ 40,672
================ =============== ============ ============== ===============
Three Months Ended June 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Revenues.................................... $ - $ 75,443 $ 30,814 $ - $ 106,257
Expenses.................................... 88 59,840 17,393 - 77,321
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (88) 15,603 13,421 - 28,936
Equity in net earnings of subsidiaries.... 19,448 - 10,510 (29,856) 102
---------------- --------------- ------------ -------------- ---------------
Income before income taxes.................. 19,360 15,603 23,931 (29,856) 29,038
Income tax provision (benefit).............. (29) 5,195 4,483 - 9,649
---------------- --------------- ------------ -------------- ---------------
Net income.................................. $ 19,389 $ 10,408 $ 19,448 $ (29,856) $ 19,389
================ =============== ============ ============== ===============
17
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations (continued)
Six Months Ended June 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.................................... $ - $ 241,345 $ - $ - $ 241,345
Expenses.................................... 82 136,684 479 - 137,245
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (82) 104,661 (479) - 104,100
Equity in net earnings of subsidiaries.... 70,789 - 71,210 (141,668) 331
---------------- --------------- ------------ -------------- ---------------
Income before income taxes.................. 70,707 104,661 70,731 (141,668) 104,431
Income tax provision (benefit).............. (32) 33,782 (58) - 33,692
---------------- --------------- ------------ -------------- ---------------
Net income.................................. $ 70,739 $ 70,879 $ 70,789 $ (141,668) $ 70,739
================ =============== ============ ============== ===============
Six Months Ended June 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Revenues.................................... $ - $ 146,527 $ 57,478 $ - $ 204,005
Expenses.................................... 88 109,393 32,550 - 142,031
---------------- --------------- ------------ -------------- ---------------
Income (loss) before the following: (88) 37,134 24,928 - 61,974
Equity in net earnings of subsidiaries.... 41,752 - 25,118 (66,861) 9
---------------- --------------- ------------ -------------- ---------------
Income before income taxes.................. 41,664 37,134 50,046 (66,861) 61,983
Income tax provision (benefit).............. (29) 12,025 8,294 - 20,290
---------------- --------------- ------------ -------------- ---------------
Net income.................................. $ 41,693 $ 25,109 $ 41,752 $ (66,861) $ 41,693
================ =============== ============ ============== ===============
18
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Cash Flows
Six Months Ended June 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................... $ (4,661) $ 159,430 $ 245 $ - $ 155,014
Cash flow from investing activities......... - (177,138) (6) - (177,144)
Cash flow from financing activities......... 4,661 9,746 - - 14,407
---------------- --------------- ------------ -------------- ---------------
Net increase (decrease) in cash............. - (7,962) 239 - (7,723)
Cash, beginning of period................... 1 32,881 157 - 33,039
---------------- --------------- ------------ -------------- ---------------
Cash, end of period......................... $ 1 $ 24,919 $ 396 $ - $ 25,316
================ =============== ============ ============== ===============
Six Months Ended June 30, 2004
----------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Obligor) Obligor) Subsidiaries Eliminations Consolidated
Amounts in thousands ---------------- --------------- ------------ -------------- ---------------
Cash flow from operations................... $ (7,013) $ 87,668 $ 25,550 $ - $ 106,205
Cash flow from investing activities......... - (93,975) (25,487) - (119,462)
Cash flow from financing activities......... 7,013 9,996 - - 17,009
---------------- --------------- ------------ -------------- ---------------
Net increase in cash........................ - 3,689 63 - 3,752
Cash, beginning of period................... 1 24,174 13 - 24,188
---------------- --------------- ------------ -------------- ---------------
Cash, end of period......................... $ 1 $ 27,863 $ 76 $ - $ 27,940
================ =============== ============ ============== ===============
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. 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
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.
During the first half of 2005, we drilled one additional CO2 source well
which added an estimated 130 Bcf of proved CO2 reserves and further increased
our estimated daily CO2 production capability to approximately 400 MMcf/d, up
from approximately 350 MMcf/d at year-end 2004. As of July 31, 2005, another CO2
source well was drilling, with plans to start a third CO2 source well before
year-end.
Oil production from our tertiary operations increased to 9,417 BOE/d in the
second quarter of 2005, a 9% increase over the first quarter 2005 tertiary
production level of 8,644 BOE/d and a 43% increase over the second quarter of
2004 average tertiary production level of 6,603 BOE/d. Our operations in this
area, as well as others, have had minor delays for reasons detailed under
"Results of Operations--CO2 Operations" below. As a result of these delays, we
have reduced our targeted 2005 average rate of oil production from tertiary
operations from our prior estimate of 10,000 BOE/d to a revised estimated range
between 9,500 and 9,750 BOE/d. The individual tertiary oil wells are performing
much as anticipated, but overall operations are a few months behind schedule.
OPERATING RESULTS. Earnings and cash flow from operations were at record or
near-record quarterly and six month levels for the first half of 2005, primarily
as a result of record high commodity prices. Primarily as a result of the sale
of our offshore properties early in the third quarter of 2004, our total
production, when comparing the respective second quarters, decreased 17% in the
2005 period. Adjusting for the offshore sale, our total production was up 11%
between the respective second quarters.
Higher commodity prices more than offset the lower production, resulting in
net income of $40.7 million during the second quarter of 2005 as compared to
$19.4 million of net income during the second quarter of 2004. Included in
second quarter of 2005 net income is the effect of approximately $2.8 million
($1.9 million after tax) of non-cash income related to our decision to
discontinue hedge accounting in 2005 and the resultant mark-to-market
adjustments and amortization of other comprehensive income (see "Market Risk
Management").
Cash payments on our commodity hedges were significantly lower in the
second quarter of 2005 than in the second 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 $1.8 million in the second quarter of 2005 as compared
to $18.2 million paid during the second quarter of 2004.
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Adjusted for the properties sold in the offshore sale,
workover expenses were approximately $2.0 million higher in the 2005 period,
primarily related to a mechanical failure on one onshore Louisiana well. See
"Results of Operations" for a more thorough discussion of our operating results
and "Market Risk Management" for more information regarding our hedging
positions at June 30, 2005. We are 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 six months of 2005 and 2004
were generally consistent with the summary discussed above for the respective
second 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 2004. Most
expenses on a per BOE basis increased in the 2005 period for the reasons noted
above.
CAPITAL RESOURCES AND LIQUIDITY
Our current capital budget for 2005, excluding any potential acquisitions,
is $350 million, which at commodity futures prices as of the end of July 2005
will be reasonably close to our anticipated cash flow from operations. The
capital budget includes an estimated $50 million 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. 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 often increased our capital
budget during the year. As a result of the recent cost inflation in our
industry, it is likely that we will have to either increase our capital budget
before the end of 2005 or eliminate a portion of our planned projects. In
addition to our capital exploration and development budget, during the first
half of 2005 we also spent approximately $68.7 million on acquisitions,
primarily for interests in other oil fields that may be tertiary flood
candidates and additional acreage and interests in the Barnett Shale play near
Fort Worth, Texas. It is likely that we will attempt to make additional
acquisitions of a similar nature during the remainder of 2005, although it is
not practical to forecast in what amounts.
At June 30, 2005, we had used our remaining cash and short-term investments
from the 2004 sale of our offshore properties and had borrowed $10 million on
our bank credit line, primarily to fund acquisitions. We borrowed an additional
$10 million on our bank line during July 2005. 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 depending on the timing of such
expenditures. If we are successful in making further acquisitions, these would
likely be funded under our bank credit line.
At June 30, 2005, we had outstanding $225 million (principal amount) of
7.5% subordinated notes due in 2013, approximately $6.2 million of long-term
capital lease commitments, $10.0 million of bank debt, and working capital of
$17.7 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.
SOURCES AND USES OF CAPITAL RESOURCES
During the first six months of 2005, we incurred $138.9 million on oil and
natural gas exploration and development expenditures, $35.1 million on CO2
exploration and development expenditures (including $22.4 million on our CO2
pipeline being constructed to East Mississippi), and approximately $68.5 million
21
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
on property acquisitions, for total capital expenditures of approximately $242.5
million. Our exploration and development expenditures included approximately
$64.9 million incurred on drilling, $11.6 million on geological, geophysical and
acreage expenditures and $62.4 million incurred on facilities and recompletion
costs. We funded these expenditures with $155.0 million of cash flow from
operations, $10.0 million of net bank borrowings, a $9.0 million increase in our
accrued capital expenditures and 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 $151.4 million for the first six months of 2005, while cash flow from
operations for the same period, the GAAP measure, was $155.0 million.
During the first six months of 2004, we spent $89.8 million on oil and
natural gas exploration and development expenditures, $19.7 million on CO2
exploration and development expenditures, and approximately $9.6 million on
property acquisitions (virtually all CO2 related) for total capital expenditures
of approximately $119.1 million. We funded these expenditures with $106.2
million of cash flow from operations and $10.0 million of net bank borrowings,
with the balance funded from cash and other sources. Adjusted cash flow from
operations (a non-GAAP measure defined as cash flow from operations before
changes in assets and liabilities as discussed below under "Results of
Operations-Operating Results") was $122.0 million for the first six months of
2004, while cash flow from operations for the same period, the GAAP measure, was
$106.2 million.
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 June 30, 2005, consisted of $34.4 million
of debt and $9.7 million in letters of credit), and we have delivery obligations
to deliver CO2 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 issues.
During the first half of 2005, we drilled and completed one additional CO2
source well that added an estimated 130 Bcf of additional CO2 reserves and as
much as 50 MMcf/d of incremental production capability. During the first half of
2005, our CO2 production averaged 257 MMcf/d. We used 67% of this, or 173
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
with the completion of our latest well, and expect to increase this production
capability to as much as 450 to 500 MMcf/d by the end of 2005. Two more CO2
source wells (one of which is currently drilling) are planned for the remainder
of 2005, which are intended to not only increase CO2 production, but also
increase our CO2 reserves as well. We have completed our 3-D seismic shoot over
the Jackson Dome area and are currently processing and evaluating several
prospects for potential CO2 reserves.
22
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Our oil production from our CO2 tertiary recovery activities in the second
quarter of 2005 increased 9% over first quarter 2005 levels and 43% over second
quarter 2004 levels, to 9,417 Bbls/d in the second quarter of 2005, with the
most significant increases coming from Mallalieu and McComb Fields. Production
at Mallalieu averaged 4,582 Bbls/d during the second quarter of 2005, as
compared to 4,235 Bbls/d in the prior quarter and 3,172 Bbls/d during the second
quarter of 2004. At McComb Field, production averaged 986 Bbls/d in the second
quarter of 2005, as compared to 699 Bbls/d in the prior quarter and 121 Bbls/d
in the second quarter of 2004. We expect our tertiary oil production to continue
to grow during 2005, with additional increases expected at all three of our
ongoing tertiary operations at Mallalieu, Little Creek and McComb Fields.
Although we have commenced CO2 injections at Brookhaven Field, we do not
anticipate any significant production increases from this field during 2005. Our
operations in this area, as well as others, have had minor delays. These delays
are caused by various factors which include, difficulties reentering a few
injection wells which has required that some wells be redrilled, delays in
getting certain permits and rights-of-ways, and a general tightening of
materials and equipment in the industry. As a result of these delays, we have
reduced our targeted 2005 average rate of oil production from tertiary
operations from our prior estimate of 10,000 BOE/d to a revised estimated range
between 9,500 and 9,750 BOE/d. The individual tertiary oil wells are performing
much as anticipated, but overall operations are a few months behind schedule.
We spent approximately $0.14 per Mcf to produce our CO2 during the first
half of 2005, slightly higher than the 2004 six month average of $0.11 per Mcf,
principally as a result of higher commodity prices, which results in higher
royalty payments. Our estimated total cost per thousand cubic feet of CO2 during
the first half of 2005 was approximately $0.21, after inclusion of depreciation
and amortization expense, up slightly from the 2004 average of $0.20 per Mcf. On
a quarterly basis, we spent approximately $0.15 per Mcf to produce our CO2
during the second quarter of 2005, slightly higher than the 2004 second quarter
average of $0.14 per Mcf, consistent with the six month trends, as a result of
higher commodity prices. Our estimated total cost per thousand cubic feet of CO2
during the second quarter of 2005 was approximately $0.22, after inclusion of
depreciation and amortization expense.
For the first half of 2005, our operating costs for our tertiary properties
averaged $10.58 per BOE, higher than the $9.94 per BOE average in the first half
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 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 and higher cash operating expenses, resulting in near-record
quarterly earnings and cash flow from operations. Included in the first half of
2005 net income is the effect of approximately $3.9 million ($2.7 million after
tax) of non-cash charges related to our decision to discontinue hedge accounting
in 2005 and the resultant mark-to-market adjustments and amortization of other
comprehensive income.
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------------------------------ ------------------------- -------------------------
Amounts in thousands, except per share amounts 2005 2004 2005 2004
- ------------------------------------------------------------ ----------- ----------- ----------- -----------
Net income $ 40,672 $ 19,389 $ 70,739 $ 41,693
Net income per common share - basic 0.73 0.35 1.27 0.76
Net income per common share - diluted 0.69 0.34 1.20 0.73
Adjusted cash flow from operations (see below) $ 81,951 $ 63,054 $ 151,362 $ 121,974
Net change in assets and liabilities relating to operations 6,434 (9,844) 3,652 (15,769)
- ------------------------------------------------------------ ----------- ----------- ----------- -----------
Cash flow from operations (1) $ 88,385 $ 53,210 $ 155,014 $ 106,205
- ------------------------------------------------------------ =========== =========== =========== ===========
(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.
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 six months
of 2005 our accrued production receivables and trade accounts receivable
increased as a result of higher revenue and increased spending, resulting in a
$15.9 million use of cash; however, this was more than offset by the increase in
our accounts payable, accrued liabilities and production payable which resulted
in additional cash resources of $20.1 million. During the first six months of
2004, we spent $7.5 million (in the second quarter) to acquire 7,500 Bbls/d of
oil puts or floors for 2005 and to retire 20 MMcf/d of natural gas hedges for
the balance of 2004, and funded a $10.8 million increase in accrued production
receivables as a result of the higher commodity prices during the second quarter
of 2004, partially offset by changes in other assets and liabilities.
Certain of our operating results and statistics for the comparative second
quarters and first six months of 2005 and 2004 are included in the following
table.
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------------- ---------------------------- ----------------------------
2005 2004 2005 2004
- ---------------------------------------------------------- ------------- ------------- ------------- -------------
Average daily production volumes
Bbls/d 20,623 18,730 20,444 19,067
Mcf/d 59,080 107,230 57,929 105,344
BOE/d (1) 30,469 36,602 30,099 36,624
Operating revenues (Thousands)
Oil sales $ 89,169 $ 58,529 $ 168,351 $ 113,054
Natural gas sales 36,603 60,542 68,437 116,253
------------- ------------- ------------- -------------
Total oil and natural gas sales $ 125,772 $ 119,071 $ 236,788 $ 229,307
============= ============= ============= =============
Hedge Contracts (2) (Thousands)
Cash income (expense) on hedge contracts $ (1,776) $ (18,239) $ (2,875) $ (32,507)
Non-cash hedge income (expense) 2,801 (7,146) (3,921) (7,964)
------------- ------------- ------------- -------------
Total income (expense) from hedge contracts $ 1,025 $ (25,385) $ (6,796) $ (40,471)
============= ============= ============= =============
Operating expenses (Thousands)
Lease operating expenses $ 26,757 $ 24,530 $ 49,719 $ 47,058
Production taxes and marketing expenses 6,582 4,514 12,708 8,581
------------- ------------- ------------- -------------
Total production expenses $ 33,339 $ 29,044 $ 62,427 $ 55,639
============= ============= ============= =============
CO2 sales and transportation fees (3) $ 1,517 $ 1,580 $ 3,247 $ 2,941
CO2 operating expenses 445 209 791 353
------------- ------------- ------------- -------------
CO2 operating margin $ 1,072 $ 1,371 $ 2,456 $ 2,588
============= ============= ============= =============
Unit prices - including impact of hedges
Oil price per Bbl $ 47.51 $ 26.56 $ 45.50 $ 25.72
Gas price per Mcf 6.48 5.69 6.25 5.61
Unit prices - excluding impact of hedges (2)
Oil price per Bbl $ 47.51 $ 34.34 $ 45.50 $ 32.58
Gas price per Mcf 6.81 6.20 6.53 6.06
Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues $ 45.36 $ 35.75 $ 43.46 $ 34.40
============= ============= ============= =============
Oil and gas lease operating expenses $ 9.65 $ 7.36 $ 9.12 $ 7.06
Oil and gas production taxes and marketing expense 2.37 1.36 2.33 1.29
------------- ------------- ------------- -------------
Total oil and gas production expenses $ 12.02 $ 8.72 $ 11.45 $ 8.35
========================================================== ============= ============= ============= =============
(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 $0.6 million for the three months ended June 30, 2005 and 2004,
respectively, and $1.3 and $1.1 million for the six months ended June 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 twelve months ended June 30, 2005 and 2004, respectively, and $1.5
million and $1.2 million for the six months ended June 30, 2005 and 2004, respectively.
25
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
and second quarters of 2005 is listed in the following table.
Average Daily Production (BOE/d)
--------------------------------------------------------------------
First Second Third Fourth First Second
Quarter Quarter Quarter Quarter Quarter Quarter
Operating Area 2004 2004 2004 2004 2005 2005
- ----------------------------------------- ---------- ----------- ----------- ----------- ---------- ----------
Mississippi - non-CO2 floods 12,754 13,048 12,969 13,564 13,057 12,788
Mississippi - CO2 floods 6,318 6,603 6,967 7,242 8,644 9,417
Onshore Louisiana 8,825 7,492 7,033 7,182 6,710 5,791
Barnett Shale 229 345 803 963 1,313 2,052
Other (1) - - - - - 421
---------- ----------- ----------- ----------- ---------- ----------
Total production excluding offshore 28,126 27,488 27,772 28,951 29,724 30,469
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
========== =========== =========== =========== ========== ==========
__________________________________________
(1) Primarily represents production from an offshore property retained from the sale in July 2004.
As a result of the sale of our offshore properties in July 2004, overall
production on a BOE/d basis decreased 17% between the second quarters of 2005
and 2004, and 18% between the comparative first six months of 2005 and 2004.
Adjusting for the offshore sale, overall production increased 11% and 9%,
respectively, on a BOE/d basis, between the comparative second quarters and
first six months of 2005 and 2004, anchored by the increased production from our
tertiary operations and Barnett Shale play, offset in part by declines in our
onshore Louisiana natural gas production.
As more fully discussed in "CO2 Operations" above, oil production from our
tertiary operations continued to increase in the second quarter of 2005,
averaging 9,417 Bbls/d, representing 46% of our second quarter corporate oil
production and 31% of our total corporate production on a BOE basis. Production
in the Mississippi non- CO2 floods decreased slightly but overall has remained
relatively stable over the last six quarters. Although most of the 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. Natural gas
production at Heidelberg averaged 15.6 MMcf/d in the second quarter of 2005, up
from 14.8 MMcf/d in the second quarter of 2004.
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 declined to 649 BOE/d in the second quarter of 2005, as compared to
1,403 BOE/d in the second quarter of 2004. Production at Lirette declined to
1,451 BOE/d in the second quarter of 2005 from 2,593 BOE/d in the second quarter
of 2004. Both of these fields have natural gas wells that are relatively
short-lived in nature and are expected to continue to decline in production.
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 activity in 2004 and early 2005 and the acquisition of additional
interests during the second quarter of 2005, increasing production from 345
BOE/d (2.1 MMcf/d) in the second quarter of 2004 to 2,052 BOE/d (12.3 MMcf/d) in
the second quarter of 2005. Approximately 1.5 MMcf/d of this increase is related
to the acquisition of additional interests in the second quarter of 2005.
Natural gas production in this area is expected to further increase throughout
2005 as we expect to drill twenty to twenty-five wells in this area during 2005.
We currently have three rigs running in this area, and by the end of 2005 we
expect to add one more.
Our production for the second quarter of 2005 was weighted toward oil
(68%), 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.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues for the second
quarter of 2005 increased $6.7 million, or 6%, 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 sale of offshore properties in
July 2004. When comparing the respective six month periods, revenues increased
$7.5 million, or 3%, for the same reasons. Cash payments on our hedges were $1.8
million in the second quarter of 2005 and $2.9 million for the first six months
of 2005, down from $18.2 million paid in the second quarter of 2004 and $32.5
million during the first six months of 2004. See "Market Risk Management" for
additional information regarding our hedging activities.
When comparing the second quarters of 2005 and 2004, the 17% decrease in
production caused oil and natural gas revenues to decrease by $20.0 million, or
20%. This decrease was more than offset by the increase in commodity prices,
which caused oil and natural gas revenues to increase by $26.7 million, or 26%.
For the comparative first six months of 2005 and 2004, the 18% decrease in
production caused oil and natural gas revenues to decrease by $41.9 million, or
21%; however, the increase in commodity prices caused oil and natural gas
revenues to increase by $49.4 million, or 25%. Although both oil and natural gas
prices were higher in the current year periods than in the 2004 periods, oil
prices increased significantly more than natural gas prices. Our realized oil
prices (excluding hedges) increased by 38% between the second quarters of 2005
and 2004 and by 40% between the comparable six month periods, while our realized
natural gas prices (excluding hedges) increased by 10% between the second
quarters of 2005 and 2004 and by 8% between the comparable six month periods. On
a combined BOE basis, commodity prices were 27% higher for the comparative
second quarters and 26% higher for the comparative first six months of 2005 and
2004.
Our net realized oil prices (excluding hedges) relative to NYMEX prices
were lower in the second quarter and first six 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 the first part of 2005,
particularly for the heavy, sour crude (which predominately applies to our
Eastern Mississippi production). Our average oil NYMEX differential for the
second quarter of 2005 was approximately $5.72 per Bbl, which is an improvement
over the $6.54 per Bbl NYMEX differential in the first quarter of 2005, but
significantly less than the $3.93 per Bbl differential in the second quarter of
2004 and an average of $3.60 per Bbl during 2003. While these differentials did
narrow somewhat during the second quarter of 2005 as compared to the prior two
quarters, it is not possible to predict whether this trend will continue. If
market conditions for the heavy, sour crude remain consistent, we would expect
to gradually improve the 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. Our natural gas differentials have not changed as
significantly, as generally we get near NYMEX prices. However, with the
anticipated incremental production from the Barnett Shale area, which has sold
for about $1.00 less than NYMEX prices during the last two quarters, we expect
that our overall natural gas NYMEX differential will likely increase.
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. Operating expenses on our tertiary operations increased from
$11.7 million in the first half of 2004 to $17.3 million in the comparable
period of 2005 as a result of increased activity at Mallalieu, McComb and
Brookhaven Fields. However, with the 39% higher production from these tertiary
operations, the increase in operating expenses for our tertiary operations on a
per BOE basis on a percentage basis was significantly less, increasing from
$9.94 per BOE in the first half of 2004 to $10.58 per BOE in the first half of
2005 (6%). Workover expenses were also higher in the second quarter of 2005 than
in the comparable period of 2004. Adjusted for the properties sold in the
offshore sale, the workover expenses were approximately $2.0 million higher in
the 2005 period, primarily related to a mechanical failure on one onshore
Louisiana well. The balance of cost increases is generally attributable to
higher energy costs to operate the properties and general cost inflation in our
industry. In general, adjusting for the workover expenses noted above, we expect
our operating costs per BOE to increase throughout 2005 as the operating costs
of our tertiary operations are higher than for our other operations and these
tertiary operations are becoming more and more significant, combined with
significant cost inflation in our industry.
Production taxes and marketing expenses generally change in proportion to
commodity prices and therefore were higher in the second quarter and first six
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 $2.0 of transportation expenses
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
paid to Genesis during the first six 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 at the wellhead most of our cruide
oil historically sold to Genesis, choosing rather to use Genesis 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 were
partially offset by the incremental transportation charges.
General and Administrative Expenses
General and administrative ("G&A") expenses increased 43% between the
respective second quarters and 40% between the respective first six months, as
set forth below:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------- ---------------------------- ----------------------------
2005 2004 2005 2004
- -------------------------------------------- ------------- ------------- ------------- -------------
Net G&A expense (thousands)
Gross G&A expenses $ 14,747 $ 11,773 $ 29,125 $ 24,453
State franchise taxes 309 242 618 488
Operator overhead charges (7,868) (6,714) (14,854) (13,494)
Capitalized exploration costs (1,196) (1,123) (2,402) (2,521)
------------- ------------- ------------- -------------
Net G&A expense $ 5,992 $ 4,178 $ 12,487 $ 8,926
============= ============= ============= =============
Average G&A cost per BOE $ 2.16 $ 1.25 $ 2.29 $ 1.34
Employees as of June 30 417 395 417 395
- ---------------------------------------------------------------------------------------------------------
Gross G&A expenses increased $3.0 million, or 25%, between the respective
second quarters and $4.7 million or 19% between the respective first six months.
These increases are generally attributable to higher compensation costs due to
additional employees, wage increases and $1.0 million of non-cash compensation
expense for the second quarter and $2.1 million for the first six months of 2005
for the amortization of deferred compensation associated with the issuance of
restricted stock to officers and directors in 2004. In addition, we incurred
higher professional service and consultant fees primarily related to
Sarbanes-Oxley compliance and audit work for year-end 2004, and for
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 approximately
$475,000 and $975,000 of employee severance payments paid only in 2004 related
to the sale of our offshore properties in July 2004 that we expensed in the
second quarter and first six months of 2004, respectively.
The increase in gross G&A was offset by an increase in operator overhead
recovery charges in the second quarter and first six 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 second quarter and first six months
of 2005, partially offset by the sale of our offshore properties, the amount we
recovered as operator overhead charges increased by 17% between the second
quarters of 2004 and 2005 and increased by 10% between the first six 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 43% increase in net G&A expense between the respective
second quarters and a 40% increase between the first six months of 2005 and
2004. On a per BOE basis, G&A costs increased 73% in the second quarter of 2005
as compared to the second quarter of 2004, and increased 71% for the comparative
first six months of 2005 and 2004, 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. Since virtually all of 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 the offshore properties
had minimal impact on net G&A.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest and Financing Expenses
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------- ---------------------------- ----------------------------
Amounts in thousands, except per BOE amounts 2005 2004 2005 2004
- -------------------------------------------- ------------- ------------- ------------- -------------
Cash interest expense $ 4,504 $ 4,841 $ 9,037 $ 9,695
Non-cash interest expense 204 227 409 454
Less: Capitalized interest (373) - (635) -
------------- ------------- ------------- -------------
Interest expense $ 4,335 $ 5,068 $ 8,811 $ 10,149
============= ============= ============= =============
Interest and other income $ 694 $ 330 $ 1,310 $ 749
============= ============= ============= =============
Average net cash interest expense per BOE (1) $ 1.24 $ 1.35 $ 1.30 $ 1.34
Average interest rate (2) 7.6% 6.3% 7.6% 6.3%
Average debt outstanding $ 237,113 $ 309,286 $ 239,153 $ 307,703
============================================ ============= ============= ============= =============
(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 second quarter and first six months of 2005
decreased from levels in the comparable periods of 2004 primarily due to lower
average debt in 2005 as a result of our offshore properties in July 2004, the
proceeds from which were used to retire our bank debt. Interest and other income
for the second quarter and first six months of 2005 increased from the
comparable 2004 periods due to higher cash and investment balances, also related
to the sale of our offshore properties.
Depletion, Depreciation and Amortization
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------- ---------------------------- ----------------------------
Amounts in thousands, except per BOE amounts 2005 2004 2005 2004
- -------------------------------------------- ------------- ------------- ------------- -------------
Depletion and depreciation $ 22,126 $ 25,694 $ 41,536 $ 50,698
Depletion and depreciation of CO2 assets 1,168 1,240 2,374 2,378
Accretion of asset retirement obligations 522 774 843 1,541
Depreciation of other fixed assets 589 453 1,180 868
------------- ------------- ------------- -------------
Total DD&A $ 24,405 $ 28,161 $ 45,933 $ 55,485
============= ============= ============= =============
DD&A per BOE:
Oil and natural gas properties $ 8.17 $ 7.95 $ 7.78 $ 7.83
CO2 assets and other fixed assets 0.63 0.51 0.65 0.49
------------- ------------- ------------- -------------
Total DD&A cost per BOE $ 8.80 $ 8.46 $ 8.43 $ 8.32
============================================ ============= ============= ============= =============
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis increased 4% between the respective second quarters, primarily due
to rising costs and increases in capital spending in the first half of 2005.
During the first half of 2005, we spent approximately $68.5 million on
acquisitions, of which approximately $45.6 million was included in our full cost
pool with the balance becoming part of our unevaluated costs. 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, certain of our future
development cost estimates have increased to reflect the rising costs in the
industry, contributing to the increase in our DD&A rate over the first quarter
2005 rate of $8.05. We did not book any incremental oil reserves related to our
tertiary operations during the first six months of 2005. 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.
29
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
Three Months Ended Six Months Ended
June 30, June 30,
- ---------------------------------------------------------- ---------------------------- ----------------------------
Amounts in thousands, except per BOE amounts and tax rates 2005 2004 2005 2004
- ---------------------------------------------------------- ------------- ------------- ------------- -------------
Income tax provision
Current income tax expense $ 4,354 $ 977 $ 9,636 $ 3,096
Deferred income tax expense 15,510 8,672 24,056 17,194
------------- ------------- ------------- -------------
Total income tax expense $ 19,864 $ 9,649 $ 33,692 $ 20,290
============= ============= ============= =============
Average income tax expense per BOE $ 7.16 $ 2.90 $ 6.18 $ 3.04
Effective tax rate 32.8% 33.2% 32.3% 32.7%
========================================================== ============= ============= ============= =============
Our income tax provision for the second quarter and first six 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 receipt of enhanced oil recovery tax credits 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 enhanced oil recovery ("EOR") credits to carryforward. We expect to
generate additional net EOR 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 Six Months Ended
June 30, June 30,
- ------------------------------------------------------------ ---------------------------- ----------------------------
Per BOE data 2005 2004 2005 2004
- ------------------------------------------------------------ ------------- ------------- ------------- -------------
Revenues $ 45.36 $ 35.75 $ 43.46 $ 34.40
Loss on settlements of derivative contracts (0.64) (5.48) (0.53) (4.88)
Lease operating expenses (9.65) (7.36) (9.12) (7.06)
Production taxes and marketing expenses (2.37) (1.36) (2.33) (1.29)
- ------------------------------------------------------------ ------------- ------------- ------------- -------------
Production netback 32.70 21.55 31.48 21.17
CO2 operating margin 0.39 0.41 0.45 0.39
General and administrative expenses (2.16) (1.25) (2.29) (1.34)
Net cash interest expense (1.24) (1.35) (1.30) (1.34)
Current income taxes and other (0.13) (0.42) (0.56) (0.58)
Changes in assets and liabilities relating to operations 2.32 (2.96) 0.67 (2.37)
- ------------------------------------------------------------ ------------- ------------- ------------- -------------
Cash flow from operations 31.88 15.98 28.45 15.93
DD&A (8.80) (8.46) (8.43) (8.32)
Deferred income taxes (5.59) (2.60) (4.42) (2.58)
Non-cash hedging adjustments 1.01 (2.15) (0.72) (1.19)
Changes in assets and liabilities and other non-cash items (3.83) 3.05 (1.90) 2.42
- ------------------------------------------------------------ ------------- ------------- ------------- -------------
Net income $ 14.67 $ 5.82 $ 12.98 $ 6.26
============================================================ ============= ============= ============= =============
30
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MARKET RISK MANAGEMENT
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. The following table presents the carrying and fair
values of our debt, along with average interest rates. The fair value of our
bank debt is considered to be the same as the carrying value because the
interest rate is based on floating short-term interest rates. The fair value of
the subordinated debt is based on quoted market prices. None of our debt has any
triggers or covenants regarding our debt ratings with rating agencies.
Expected Maturity Dates
- ----------------------------------- ----------------------------------------------------- ------------- -----------
2005- Carrying Fair
Amounts in thousands 2006 2007 2008 2009 After Value Value
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ------------- -----------
Variable rate debt:
Bank debt....................... $ - $ - $ - $ 10,000 $ - $ 10,000 $ 10,000
The weighted-average interest rate on the bank debt at June 30, 2005 is 4.4%
Fixed rate debt:
7.5% subordinated debt,
net of discount, due 2013..... $ - $ - $ - $ - $225,000 $ 223,494 $ 227,003
The interest rate on the subordinated debt is a fixed rate of 7.5%
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. 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 resulted 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 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. For 2005, all of our oil
hedges are puts or price floors, allowing us to retain any price upside, while
still providing protection in the event of lower prices at a fixed and
determinable price (i.e. the cost of the put). We anticipate using more price
floors in the future. 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 June 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 will be
amortized over the remaining life of the contracts. During the second quarter of
2005, we recognized total income relating to our hedge contracts of $1.0
million, consisting of $1.8 of cash payments, $4.6 million of income 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 six months of 2005,
we recognized total expense relating to our hedge contracts of $6.8 million,
consisting of $2.9 million of cash payments, $346,000 of expense relating to a
mark-to-market non-cash adjustment and $3.6 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. Information regarding our current
hedging positions and historical hedging results is included in Note 5 to the
Condensed Consolidated Financial Statements.
31
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2005, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $5.2 million, an increase from
the $4.9 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 June 30, 2005,
partially offset by the expiration of approximately one-half of our remaining
hedge contracts between January 1, 2005 and June 30, 2005.
Based on NYMEX crude oil futures prices at June 30, 2005, oil prices were
considerably higher than the floor price of $27.50 per barrel, 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 June 30, 2005, we would expect to make future cash payments of $5.2
million on our natural gas commodity hedges. If natural gas futures prices were
to decline by 10%, the amount we would expect to pay under our natural gas
commodity hedges would decrease to $3.2 million, and if futures prices were to
increase by 10% we would expect to pay $7.2 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.
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. Had the Company adopted SFAS No. 123(R) in prior periods, we estimate
that the impact would have approximated the impact of SFAS No. 123 as described
in the pro forma net income and earnings per share disclosures shown in Note 1
to our Condensed Consolidated Financial Statements. The adoption of SFAS No.
123(R) will have no effect on the accounting for the Company's unvested
outstanding restricted stock awards. We currently plan to adopt the provisions
of SFAS No. 123(R) on January 1, 2006 using the modified prospective approach.
Although we have not completed evaluating the impact the adoption of SFAS No.
123(R) will have on our future results of operations, we currently estimate the
impact on an annual basis will be similar to that in our pro forma disclosures
for SFAS No. 123.
32
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND 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. While we cannot
estimate what those amounts will be in the future (because they depend, among
other things, upon when employees exercise stock options), the amount of
operating cash flows recognized for such excess tax deductions was approximately
$5.4 million for the six months ended June 30, 2005.
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, 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, 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, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital or its availability, 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.
33
DENBURY RESOURCES INC.
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 the second quarter of 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 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, an
investigation was 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
this ongoing investigation, to date we have dismissed one employee, 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 are currently
pursuing financial recovery of improper vendor billings. 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
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;
34
DENBURY RESOURCES INC.
3. Increase our internal audit reviews in the area of purchasing, bidding, and
invoice approval; and
4. Review, refine and emphasize 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
- ------------------------------- ----------- ------------ -------------------- -----------------------
January 1 through 31, 2005 15,000 $ 25.36 15,000 85,000
February 1 through 28, 2005 25,000 $ 33.29 25,000 60,000
March 1 through 31, 2005 10,000 $ 33.51 10,000 50,000
April 1 through 30, 2005 35,000 $ 33.51 35,000 15,000
May 1 through 31, 2005 15,000 $ 29.58 15,000 -
June 1 through 30, 2005 - - - -
- ------------------------------- ----------- ------------ -------------------- -----------------------
Total 100,000 $ 31.64 100,000 -
In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase
shares of our common stock on the NYSE in order for such repurchased shares to
be reissued to our employees who participate in Denbury's Employee Stock
Purchase Plan. The Plan originally provided for purchases through an independent
broker of 50,000 shares of Denbury's common stock per fiscal quarter for a
period of approximately twelve months, or a total of 200,000 shares, beginning
August 13, 2003 and ending on July 31, 2004. The Board of Directors renewed the
Plan through June 2005 at the same 50,000 shares per quarter rate and 100,000
shares were purchased in the first half of 2005. We currently do not plan to
renew the Plan until we have used a significant portion of our treasury shares.
Purchases were made at prices and times determined at the discretion of the
independent broker, provided however that no purchases were made during the last
ten business days of a fiscal quarter.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
- ---------------------------------------
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- -----------------------------------------------------------
Denbury's Annual Meeting of Stockholders was held on May 11, 2005 for the
purposes of: (1) electing seven Directors, each to serve until their successor
is elected and qualified, and (2) to extend the term of our employee stock
purchase plan. At the record date, March 31, 2005, 56,848,733 shares of common
stock were outstanding and entitled to one vote per share upon all matters
submitted at the meeting. Holders of 53,776,662 shares of common stock,
representing approximately 95% of the total issued and outstanding shares of
common stock, were present in person or by proxy at the meeting to cast their
vote.
35
DENBURY RESOURCES INC.
With respect to the election of directors, all seven director nominees were
re-elected. All of the directors are elected on an annual basis. The votes were
cast as follows:
Nominees for Directors For Withheld
- -------------------------- ------------- -----------
Ronald G. Greene 52,072,771 1,703,891
- -------------------------- ------------- -----------
David I. Heather 52,756,105 1,020,557
- -------------------------- ------------- -----------
Greg McMichael 52,391,513 1,385,149
- -------------------------- ------------- -----------
Gareth Roberts 53,724,158 52,504
- -------------------------- ------------- -----------
Randy Stein 53,070,765 705,897
- -------------------------- ------------- -----------
Wieland F. Wettstein 50,883,455 2,893,207
- -------------------------- ------------- -----------
Donald D. Wolf 52,391,538 1,385,124
- -------------------------- ------------- -----------
The extension of the employee stock purchase plan by five years, from
August 2005 to August 2010 was also approved. The votes were cast as follows:
For Against Abstentions Broker Non-Votes
- ------------ ------------ ------------- --------------------
30,689,056 18,057,371 6,687 5,023,548
ITEM 5. OTHER INFORMATION
- -------------------------
None.
ITEM 6. EXHIBITS
- -----------------
EXHIBITS:
31(a)* Certification of Chief Executive Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial
Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
* Filed herewith.
36
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DENBURY RESOURCES INC.
(Registrant)
By: /s/ Phil Rykhoek
-----------------------------------
Phil Rykhoek
Sr. Vice President and
Chief Financial Officer
By: /s/ Mark C. Allen
-----------------------------------
Mark C. Allen
Vice President and
Chief Accounting Officer
Date: August 8, 2005
37