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 March 31, 2005
Transition report pursuant to Section 13 or 15(d) of the Securities
- --- Exchange Act of 1934
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 20-0467835
(State or other jurisdictions of (I.R.S. Employer
incorporation or organization) Identification No.)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No__
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes X No__
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at April 30, 2005
----- -----------------------------
Common Stock, $.001 par value 56,760,657
INDEX
Page
----
Part I. Financial Information
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at March 31,
2005 and December 31, 2004 3
Unaudited Condensed Consolidated Statements of Operations
for the Three Months Ended March 31, 2005 and 2004 4
Unaudited Condensed Consolidated Statements of Cash Flows
for the Three Months Ended March 31, 2005 and 2004 5
Unaudited Condensed Consolidated Statements of Comprehensive
Operations for the Three Months Ended March 31, 2005
and 2004 6
Notes to Unaudited Condensed Consolidated Financial
Statements 7-16
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17-29
Item 3. Quantitative and Qualitative Disclosures about Market Risk 30
Item 4. Controls and Procedures 30
Part II. Other Information
Item 1. Legal Proceedings 30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 30
Item 3. Defaults Upon Senior Securities 31
Item 4. Submission of Matters to a Vote of Security Holders 31
Item 5. Other Information 31
Item 6. Exhibits 31
Signatures 32
2
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
March 31, December 31,
2005 2004
--------------- ---------------
Assets
Current assets
Cash and cash equivalents $ 42,742 $ 33,039
Short-term investments 14,572 57,171
Accrued production receivable 51,454 44,790
Related party receivable - Genesis - 745
Trade and other receivables 14,052 10,963
Deferred tax asset 31,452 25,189
Derivative assets 5 949
--------------- ---------------
Total current assets 154,277 172,846
--------------- ---------------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved 1,394,274 1,326,401
Unevaluated 41,771 20,253
CO2 properties and equipment 160,594 132,685
Other 30,177 25,929
Less accumulated depletion and depreciation (729,027) (707,906)
--------------- ---------------
Net property and equipment 897,789 797,362
--------------- ---------------
Investment in Genesis 6,945 6,791
Other assets 10,963 15,707
--------------- ---------------
Total assets $ 1,069,974 $ 992,706
=============== ===============
Current liabilities
Accounts payable and accrued liabilities $ 70,955 $ 51,860
Accounts payable - Genesis 190 -
Oil and gas production payable 24,173 24,856
Derivative liabilities 9,779 5,815
Short-term capital lease obligations - Genesis 534 375
--------------- ---------------
Total current liabilities 105,631 82,906
--------------- ---------------
Long-term liabilities
Capital lease obligations - Genesis 6,305 4,184
Long-term debt 223,446 223,397
Asset retirement obligations 19,641 18,944
Deferred revenue - Genesis 22,756 23,378
Deferred tax liability 112,625 97,125
Other 757 1,100
--------------- ---------------
Total long-term liabilities 385,530 368,128
--------------- ---------------
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;
56,915,476 and 56,607,877 shares issued at March 31, 2005 and
December 31, 2004, respectively 57 57
Paid-in capital in excess of par 447,297 441,023
Deferred compensation (20,922) (21,678)
Retained earnings 159,172 129,104
Accumulated other comprehensive loss (3,661) (4,788)
Treasury stock, at cost, 124,594 and 93,072 shares at March 31, 2005 and
December 31, 2004, respectively (3,130) (2,046)
--------------- ---------------
Total stockholders' equity 578,813 541,672
--------------- ---------------
Total liabilities and stockholders' equity $ 1,069,974 $ 992,706
=============== ===============
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except shares)
Three Months Ended
March 31,
-------------------------
2005 2004
------------ ------------
Revenues
Oil, natural gas and related product sales:
Unrelated parties $ 111,016 $ 91,274
Related party - Genesis - 18,962
CO2 sales and transportation fees:
Unrelated parties 392 284
Related party - Genesis 1,338 1,077
Loss on effective hedge contracts - (14,268)
Interest income and other 616 419
------------ ------------
Total revenues 113,362 97,748
------------ ------------
Expenses
Lease operating expenses 22,962 22,528
Production taxes and marketing expenses 5,190 4,067
Transportation expense - Genesis 936 -
CO2 operating expenses 346 144
General and administrative expenses 6,495 4,748
Interest, net of interest capitalized of $262 and none 4,476 5,081
Depletion and depreciation 21,528 27,324
Commodity derivative expense 7,821 818
------------ ------------
Total expenses 69,754 64,710
------------ ------------
Equity in net income (loss) of Genesis 287 (93)
------------ ------------
Income before income taxes 43,895 32,945
Income tax provision
Current income taxes 5,282 2,119
Deferred income taxes 8,546 8,522
------------ ------------
Net income $ 30,067 $ 22,304
============ ============
Net income per common share - basic $ 0.54 $ 0.41
Net income per common share - diluted $ 0.51 $ 0.40
Weighted average common shares outstanding
Basic 55,459 54,388
Diluted 58,604 56,313
(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
March 31,
----------------------------
2005 2004
------------- -------------
Cash flow from operating activities:
Net income $ 30,067 $ 22,304
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 21,528 27,324
Non-cash hedging adjustments 6,722 818
Deferred income taxes 8,546 8,522
Deferred revenue - Genesis (622) (511)
Deferred compensation - restricted stock 1,028 -
Current income tax benefit from stock options 2,080 -
Amortization of debt issue costs and other 62 463
Changes in assets and liabilities:
Accrued production receivable (5,919) (7,426)
Trade and other receivables (3,088) (1,227)
Other assets 130 -
Accounts payable and accrued liabilities 7,244 1,723
Oil and gas production payable (683) 1,798
Other liabilities (466) (793)
------------- -------------
Net cash provided by operations 66,629 52,995
------------- -------------
Cash flow used for investing activities:
Oil and natural gas expenditures (57,195) (47,750)
Acquisitions of oil and gas properties (30,781) (163)
Change in accrual for capital expenditures 11,239 -
Acquisitions of CO2 assets and capital expenditures (27,963) (20,203)
Purchases of other assets (1,930) (304)
Proceeds from oil and gas property sales (18) 512
Deposits on oil and gas property acquisitions 4,507 -
Maturities of short-term investments 42,575 -
Increase in restricted cash (48) (203)
------------- -------------
Net cash used for investing activities (59,614) (68,111)
------------- -------------
Cash flow from financing activities:
Bank repayments (14,000) (3,000)
Bank borrowings 14,000 8,000
Payments on capital lease obligations - Genesis (125) -
Issuance of common stock 4,361 3,879
Purchase of treasury stock (1,548) (743)
------------- -------------
Net cash provided by financing activities 2,688 8,136
------------- -------------
Net increase (decrease) in cash and cash equivalents 9,703 (6,980)
Cash and cash equivalents at beginning of period 33,039 24,188
------------- -------------
Cash and cash equivalents at end of period $ 42,742 $ 17,208
============= =============
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 259 $ 8,950
Cash paid (refunded) during the period for income taxes - (273)
(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
March 31,
---------------------------
2005 2004
------------- ------------
Net income $ 30,067 $ 22,304
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative contracts, net of tax of ($6,744) - (11,004)
Reclassification adjustments related to settlements of derivative contracts,
net of tax of $689 and $5,422, respectively 1,125 8,846
Unrealized gain on securities available for sale 2 -
------------- ------------
Comprehensive income $ 31,194 $ 20,146
============= ============
(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 March 31, 2005 and the consolidated results
of its operations and cash flows for the three month periods ended March 31,
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 month periods ended March 31, 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 month
periods ended March 31, 2005 and 2004.
Three Months Ended
March 31,
--------------------------------
2005 2004
---------------- ---------------
(shares in thousands)
Weighted average common shares - basic....... 55,459 54,388
Potentially dilutive securities:
Stock options.............................. 2,828 1,925
Restricted stock........................... 317 -
---------------- ---------------
Weighted average common shares - diluted.... 58,604 56,313
================ ===============
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 March 31, 2005 and 2004, common stock options to
purchase approximately 18,000 and 425,000 shares of common stock, respectively,
were outstanding but excluded from the diluted net income per common share
calculations, as the exercise prices of the options exceeded the average market
price of the Company's common stock during these periods and would be
anti-dilutive to the calculations.
7
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
March 31,
--------------------------
2005 2004
------------ ------------
Net income: (thousands)
Net income, as reported.......................................... $ 30,067 $ 22,304
Add: stock-based compensation included in reported net
income, net of related tax effects............................. 627 -
Less: stock-based compensation expense applying fair value
based method, net of related tax effects ...................... 1,544 499
------------ ------------
Pro-forma net income .............................................. $ 29,150 $ 21,805
============ ============
Net income per common share
As reported:
Basic ......................................................... $ 0.54 $ 0.41
Diluted........................................................ 0.51 0.40
Pro forma:
Basic ......................................................... $ 0.53 $ 0.40
Diluted ....................................................... 0.50 0.39
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 6 for further discussion
regarding this change.
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
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 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 in prior periods for such excess tax deductions
were $4.8 million during the year ended December 31, 2004.
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 three months ended March 31, 2005.
Three Months Ended
March 31, 2005
-----------------------
(in thousands)
Beginning asset retirement obligation, as of 12/31/2004.... $ 21,540
Liabilities incurred during period......................... 1,343
Liabilities settled during period.......................... (166)
Accretion expense.......................................... 321
-----------------------
Ending asset retirement obligation......................... $ 23,038
=======================
At March 31, 2005, $3.4 million of our asset retirement obligation was
classified in "Accounts payable and accrued liabilities" under current
liabilities in our Condensed Consolidated Balance Sheets. We hold cash and
liquid investments in escrow accounts that are legally restricted for certain of
our asset retirement obligations. The balances of these escrow accounts were
$6.5 million at March 31, 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
Since August 2003, Denbury has 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
9
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Stock Purchase Plan ("ESPP"). The Plan provides for purchases through an
independent broker of 50,000 shares of Denbury's common stock per fiscal quarter
over a period of approximately twelve months, or a total of 200,000 shares per
year. Purchases are to be made at prices and times determined at the discretion
of the independent broker, provided however that no purchases may be made during
the last ten business days of a fiscal quarter. 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 quarter of 2005, we
repurchased into treasury 50,000 shares at an average cost of $30.95 per share
and reissued 18,478 treasury shares under the ESPP. Our current repurchase
program extends through June 2005.
4. RELATED PARTY TRANSACTIONS - GENESIS
Interest in and Transactions with Genesis
Denbury is the general partner and owns an aggregate 9.25% interest in
Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership.
Genesis has three primary lines of business: crude oil gathering and marketing,
pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida,
and wholesale marketing of carbon dioxide.
We are accounting for our 9.25% ownership in Genesis under the equity
method of accounting as we have significant influence over the limited
partnership; however, our control is limited under the limited partnership
agreement and therefore we do not consolidate Genesis. Our equity in Genesis'
net income (loss) for the three months ended March 31, 2005 and 2004 was
$287,000 and $(93,000), respectively. Genesis Energy, Inc., the general partner
of which we own 100%, has guaranteed the bank debt of Genesis, which as of March
31, 2005 was $17.5 million, plus $9.5 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 elected to sell our own crude oil to independent third
parties rather than to Genesis. As such, we discontinued our direct sales to
Genesis and began to transport our crude oil to our sales point using Genesis'
common carrier pipeline. For these transportation services, we pay Genesis a fee
for the use of their pipeline and trucking services. In the first three months
of 2005, we expensed $936,000 for these transportation services. We recorded oil
sales to Genesis of $19.0 million for the three months ended March 31, 2004.
Denbury received other miscellaneous payments from Genesis for the three months
ended March 31, 2005 and 2004, including $30,000 in each period of director fees
for certain executive officers of Denbury that are board members of Genesis, and
$130,000 and $125,000, respectively, in pro rata dividend distributions from
Genesis as part of Genesis' cash distributions to all of its public holders.
Transportation Leases
In late 2004 and early 2005, we entered into pipeline transportation
agreements with Genesis to transport in its pipelines our crude oil from Olive,
Brookhaven, and McComb Fields in Southwest Mississippi to Genesis' main crude
oil pipeline in order to improve our ability to market our crude oil, and to
transport CO2 from our main CO2 pipeline to Brookhaven Field for our tertiary
operations. As part of these arrangements, we entered into three transportation
agreements. The first agreement, entered into in November 2004, was to transport
crude oil from Olive Field. This agreement is for 10 years and has a minimum
payment of approximately $18,000 per month. In December 2004, we entered into a
second transportation agreement, to transport CO2 to Brookhaven Field in
Southwest Mississippi. This agreement is for an eight-year period and has
minimum payments of approximately $49,000 per month. In January 2005, we entered
into a third transportation agreement, to transport crude oil from Brookhaven
Field. This agreement is for 10 years and has a minimum payment of approximately
$32,000 per month. The minimum monthly payment in each agreement will increase
for any volumes transported in excess of the stated monthly volume in the
contract. Genesis will operate and maintain 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 March 31, 2005, we had $6.8
million of capital lease obligations recorded as liabilities in our Condensed
Consolidated Balance Sheet, of which $534,000 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.
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
CO2 Volumetric Production Payments
In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million
($23.9 million as adjusted for interim cash flows from the September 1, 2003
effective date and for transaction costs) under a volumetric production payment
("VPP"), 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 March 31, 2005 and
December 31, 2004, $25.2 million and $25.8 million, respectively, was recorded
as deferred revenue of which $2.4 million was included in current liabilities at
March 31, 2005 and December 31, 2004. During the three months ended March 31,
2005 and 2004, we recognized deferred revenue of $622,000 and $511,000,
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 $717,000 and $566,000 in revenue to
Denbury for the three months ended March 31, 2005 and 2004, respectively.
Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
Three Months Ended March 31,
---------------------------------------
2005 2004
------------------ ------------------
Revenues.................................... $ 256,600 $ 198,912
Cost of sales............................... 251,744 194,813
Other expenses ............................. 2,086 4,881
Loss from discontinued operations........... - 223
------------------ ------------------
Net income (loss) ........................ $ 2,770 $ (1,005)
================== ==================
March 31, December 31,
2005 2004
------------------ ------------------
Current assets.............................. $ 99,262 $ 77,396
Non-current assets.......................... 67,395 65,758
------------------ ------------------
Total assets ............................. $ 166,657 $ 143,154
================== ==================
Current liabilities ........................ $ 101,901 $ 81,938
Non-current liabilities..................... 17,656 15,460
Partners' capital........................... 47,100 45,756
------------------ ------------------
Total liabilities and partners' capital... $ 166,657 $ 143,154
================== ==================
11
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5. SHORT-TERM INVESTMENTS
The following is a summary of current available-for-sale marketable
securities at March 31, 2005 (in thousands):
March 31, 2005
------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
------------ ---------- ---------- ------------
Certificate of deposits......................... $ 2,000 $ - $ - $ 2,000
Government and agency obligations............... 4,994 - (13) 4,981
Other debt securities........................... 7,614 - (23) 7,591
------------ ---------- --------- ------------
Total current available-for-sale securities.. $ 14,608 $ - $ (36) $ 14,572
============ ========== ========= ============
6. 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 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 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:
(In Thousands) Three Months Ended
March 31, 2004
- -------------------------------------------------------------------------------------
Settlement of hedge contracts - Oil.................... $ (10,521)
Settlement of hedge contracts - Gas.................... (3,747)
------------------------
Loss on effective hedge contracts.................... $ (14,268)
========================
12
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following is a summary of "Commodity Derivative Expense" included in
our Condensed Consolidated Statements of Operations:
(In Thousands) Three Months Ended March 31,
- -------------------------------------------------------------------------------------------------------------------
2005 2004
------------------ -----------------
Settlements of derivative contracts accounted for as speculative - Gas .... $ 1,099 $ -
Hedge ineffectiveness on contracts qualifying for hedge
accounting............................................................... - 818
Reclassification of accumulated other comprehensive income
balance and adjustments to fair value associated with contracts
no longer designated as hedges........................................... 6,722 -
------------------ -----------------
Commodity Derivative Expense........................................... $ 7,821 $ 818
================== =================
Hedging Contracts at March 31, 2005
Crude Oil Contracts:
- --------------------
NYMEX Contract Prices Per Bbl
-----------------------------------------------
Collar Prices Fair Value at
---------------------- March 31, 2005
Type of Contract and Period Bbls/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ----------- ------------ ---------- ---------- -----------------
Floor Contracts
April 2005 - Dec. 2005 7,500 $ 27.50 - - $ 5
Natural Gas Contracts:
- ----------------------
NYMEX Contract Prices Per MMBtu
-----------------------------------------------
Collar Prices Fair Value at
---------------------- March 31, 2005
Type of Contract and Period MMBtu/d Floor Price Floor Ceiling (In Thousands)
- -------------------------------- ----------- ------------ ---------- ---------- -----------------
Swap Contracts
April 2005 - Dec. 2005 15,000 - $ 3.00 $ 5.50 $ (9,779)
At March 31, 2005, our derivative contracts were recorded at their fair
value, which was a net liability of $9.8 million. The balance in accumulated
other comprehensive loss of $3.6 million at March 31, 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 $3.6 million in accumulated other comprehensive loss as of
March 31, 2005 will expire by December 31, 2005.
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. Prior to this restructure, Denbury Resources Inc. was the
sole obligor. Our subordinated debt is fully and unconditionally guaranteed by
Denbury Resources Inc.'s significant subsidiaries. Genesis Energy, Inc., the
subsidiary that holds the Company's investment in Genesis Energy, L.P., is not a
guarantor of our subordinated debt. The results of our equity interest in
Genesis is reflected through the equity method by one of our significant
subsidiaries, Denbury Gathering & Marketing. The following is condensed
consolidating financial information for Denbury Resources Inc., Denbury Onshore,
LLC, and significant subsidiaries:
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Balance Sheets
Ended March 31, 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.................................. $ 209,773 $ 152,747 $ 2,758 $ (211,001) $ 154,277
Property and equipment ......................... - 897,719 70 - 897,789
Investment in subsidiaries (equity method)...... 366,717 - 365,244 (725,016) 6,945
Other assets.................................... 2,323 10,963 167 (2,490) 10,963
-------------- ------------- ----------- ------------- --------------
Total assets ................................. $ 578,813 $ 1,061,429 $ 368,239 $ (938,507) $ 1,069,974
============== ============= =========== ============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities............................. $ - $ 315,334 $ 1,298 $ (211,001) $ 105,631
Long-term liabilities .......................... - 387,796 224 (2,490) 385,530
Stockholders' equity ........................... 578,813 358,299 366,717 (725,016) 578,813
-------------- ------------- ----------- ------------- --------------
Total liabilities and stockholders' equity.... $ 578,813 $ 1,061,429 $ 368,239 $ (938,507) $ 1,069,974
============== ============= =========== ============= ==============
December 31, 2004
---------------------------------------------------------------------------
Denbury Denbury
Resources Inc. Onshore, LLC Denbury
(Parent and Co- (Issuer and Co- Guarantor Resources Inc.
Amounts in thousands Obligor) Obligor) Subsidiaries Eliminations Consolidated
---------------- --------------- ------------ -------------- ---------------
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
============== ============= =========== ============= ==============
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
Three Months Ended March 31, 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................................... $ - $ 113,362 $ - $ - $ 113,362
Expenses .................................. 41 69,486 227 - 69,754
-------------- -------------- ----------- ------------- --------------
Income before the following: (41) 43,876 (227) - 43,608
Equity in net earnings of subsidiaries .. 30,092 - 30,342 (60,147) 287
-------------- -------------- ----------- ------------- --------------
Income before income taxes................. 30,051 43,876 30,115 (60,147) 43,895
Income tax provision ...................... (16) 13,821 23 - 13,828
-------------- -------------- ----------- ------------- --------------
Net income ................................ $ 30,067 $ 30,055 $ 30,092 $ (60,147) $ $ 30,067
============== ============== =========== ============= ==============
Three Months Ended March 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 ---------------- --------------- ------------ -------------- ---------------
Revenues................................... $ - $ 71,084 $ 26,664 $ - $ 97,748
Expenses................................... - 49,553 15,157 - 64,710
--------------- -------------- ------------ ------------- ---------------
Income before the following: - 21,531 11,507 - 33,038
Equity in net earnings of subsidiaries... 22,304 - 14,608 (37,005) (93)
--------------- -------------- ------------ ------------- ---------------
Income before income taxes................. 22,304 21,531 26,115 (37,005) 32,945
Income tax provision....................... - 6,830 3,811 - 10,641
--------------- -------------- ------------ ------------- ---------------
Net income................................. $ 22,304 $ 14,701 $ 22,304 $ (37,005) $ 22,304
=============== ============== ============ ============= ===============
15
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Cash Flows
Three Months Ended March 31, 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............... $ (2,813) $ 69,316 $ 126 $ - $ 66,629
Cash flow from investing activities..... - (59,614) - - (59,614)
Cash flow from financing activities..... 2,813 (125) - - 2,688
---------------- --------------- ------------ -------------- ---------------
Net increase in cash.................... - 9,577 126 - 9,703
Cash, beginning of period............... 1 32,881 157 - 33,039
---------------- --------------- ------------ -------------- ---------------
Cash, end of period..................... $ 1 $ 42,458 $ 283 $ - $ 42,742
================ =============== ============ ============== ===============
Three Months Ended March 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 ---------------- --------------- ------------ -------------- ---------------
Cash flow from operations............... $ (3,136) $ 37,741 $ 18,390 $ - $ 52,995
Cash flow from investing activities..... - (49,718) (18,393) - (68,111)
Cash flow from financing activities..... 3,136 5,000 - - 8,136
---------------- --------------- ------------- -------------- --------------
Net increase (decrease) in cash......... - (6,977) (3) - (6,980)
Cash, beginning of period............... 1 24,174 13 - 24,188
---------------- --------------- ------------- -------------- --------------
Cash, end of period..................... $ 1 $ $ 17,197 $ 10 $ - $ 17,208
================ =============== ============= ============== ==============
16
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 a growing independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi and own the largest reserves
east of the Mississippi River of carbon dioxide ("CO2") used for tertiary oil
recovery, and hold significant operating acreage onshore Louisiana and in the
Barnett Shale play in Texas. Our goal is to increase the value of acquired
properties through a combination of exploitation, drilling, and proven
engineering extraction processes, including secondary and tertiary recovery
operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas),
and we have two primary field offices located in Houma, Louisiana, and Laurel,
Mississippi.
OVERVIEW
CONTINUED EXPANSION OF OUR TERTIARY OPERATIONS. Since we acquired our first
carbon dioxide tertiary flood in Mississippi over five years ago, we have
gradually increased our emphasis on these types of operations. We particularly
like this play because of its risk profile, rate of return and lack of
competition in our operating area. Generally, from East Texas to Florida, there
are no known significant natural sources of carbon dioxide except our own, and
these large volumes of CO2 that we own drive the play. Please refer to
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 three months 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. We plan to drill an
additional two or three CO2 source wells during 2005.
Oil production from our tertiary operations increased to 8,644 BOE/d in the
first quarter of 2005, a 19% increase over the prior fourth quarter 2004
tertiary production level of 7,242 BOE/d and a 37% increase over the first
quarter of 2004 average tertiary production level of 6,318 BOE/d. This increase
is generally on track to achieve our targeted average rate of 10,000 BOE/d of
oil production from tertiary operations during 2005.
OPERATING RESULTS. Earnings and cash flow from operations were at record or
near-record levels for the first quarter of 2005, primarily as a result of high
commodity prices. As a result of the sale of our offshore properties early in
the third quarter of 2004, our total production, when comparing the respective
first quarters, was significantly reduced, the primary reason for a 19% decline
in production levels. However, higher commodity prices more than offset the
lower production, resulting in net income of $30.1 million during the first
quarter of 2005 as compared to $22.3 million of net income during the first
quarter of 2004. Included in first quarter of 2005 net income is the effect of
approximately $6.7 million ($4.6 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 (see
"Market Risk Management"). Excluding these non-cash charges, net income for the
first quarter of 2005 would have been approximately $34.7 million.
Cash payments on our commodity hedges were significantly lower in the first
quarter of 2005 than in the first 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 $1.1 million in the first quarter of 2005 as compared
to $14.3 million during the first quarter of 2004.
Most of our expenses increased on a per BOE basis during the first quarter
of 2005 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 the
offshore sale in July 2004. 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 March 31, 2005.
17
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAPITAL RESOURCES AND LIQUIDITY
For 2005, our current capital budget, excluding any potential acquisitions,
is $305 million, which at commodity futures prices as of the end of April 2005
will be significantly less than our anticipated cash flow from operations. That
budget includes an estimated $45 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 the cash 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.
Based on current commodity prices and the resultant expected cash flow, we may
increase our capital budget for 2005 by as much as $30 million to $50 million in
the near future to fund additional projects and to provide for rising industry
costs. In addition to our capital exploration and development budget, in the
first quarter of 2005, we also spent approximately $30.8 million on
acquisitions, primarily for interests in other oil fields that may be tertiary
flood candidates and additional undeveloped acreage 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 2005, although it is not practical to
forecast in what amounts.
At March 31, 2005, we had approximately $35 million in cash and short-term
investments remaining from the sale of our offshore properties, over and above
our normal month-end cash balances. We plan to invest this remaining cash and
any cash potentially generated from operations in excess of our capital budget
(such amount being highly dependent on commodity prices) over the next one to
two years on property acquisitions, particularly those that have future tertiary
potential. We also may seek conventional development and exploration projects in
our areas of operations or tertiary operations in other areas of the country. In
addition to our cash and short-term investments which may be used for the
potential aforementioned projects, we have all of our bank credit line available
to us if we were to need additional capital.
At March 31, 2005, we had outstanding $225 million (principal amount) of
7.5% subordinated notes due in 2013, approximately $6.8 million of capital lease
commitments, no bank debt, and working capital of $48.6 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 quarter of 2005, we incurred $57.2 million on oil and
natural gas exploration and development expenditures, $28.0 million on CO2
exploration and development expenditures (including $19.0 million on our CO2
pipeline being constructed to East Mississippi), and approximately $30.8 million
on property acquisitions, for total capital expenditures of approximately $116.0
million. Our exploration and development expenditures included approximately
$24.1 million incurred on drilling, $6.4 million on geological, geophysical and
acreage expenditures and $26.7 million incurred on facilities and recompletion
costs. We funded these expenditures with $66.6 million of cash flow from
operations, an $11.2 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") was $69.4 million for the first
quarter of 2005, while cash flow from operations for the same period, the GAAP
measure, was $66.6 million.
During the first quarter of 2004, we spent $47.8 million on oil and natural
gas exploration and development expenditures, $12.6 million on CO2 exploration
and development expenditures, and approximately $7.7 million on property
acquisitions (virtually all CO2 related), for total capital expenditures of
approximately $68.1 million. We funded these expenditures with $53.0 million of
cash flow from operations and $5.0 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 $58.9 million for the first quarter of 2004, while cash flow from
operations for the same period, the GAAP measure, was $53.0 million.
18
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OFF-BALANCE SHEET ARRANGEMENTS
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet
consist of our operating leases and various obligations for development and
exploratory expenditures arising from purchase agreements, our capital
expenditure program, or other transactions common to our industry. In addition,
in order to recover our undeveloped proved reserves, we must also fund the
associated future development costs as forecasted in the proved reserve reports.
Further, one of our subsidiaries, the general partner of Genesis Energy, L.P.,
has guaranteed the bank debt of Genesis (which as of March 31, 2005, consisted
of $17.5 million of debt and $9.5 million in letters of credit) and we have
delivery obligations to deliver CO2 to our industrial customers. Our hedging
obligations are discussed in Note 6 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, including inherent delays between the time of capital
expenditures and realizing incremental increased production, higher operating
costs for tertiary operations, and for current operations an improvement in our
overall realized price differential as compared to NYMEX prices. 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 items.
During the first quarter 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
quarter, our CO2 production averaged 221 MMcf/d. We used 77% of this, or 170
MMcf/d, in our tertiary operations, and sold the balance to our industrial
customers or to Genesis pursuant to our volumetric production payment. We
believe that our current production capacity of CO2 is approximately 400 MMcf/d
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 or three more
CO2 source wells are planned for the remainder of 2005, which are intended to
not only increase CO2 production, but 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.
Our oil production from our CO2 tertiary recovery activities increased 19%
over fourth quarter 2004 levels to 8,644 Bbls/d in the first quarter of 2005,
with increases occurring at all three producing tertiary fields, Mallalieu,
Little Creek and McComb. We expect our tertiary oil production to further
increase during 2005 to an estimated average of approximately 10,000 Bbls/d for
the year, with most of the incremental production expected from the ongoing
operations at Mallalieu 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.
We spent approximately $0.13 per Mcf to produce our CO2 during the first
quarter of 2005, slightly higher than the 2004 average of $0.12 per Mcf 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 quarter of
2005 was approximately $0.20, after inclusion of depreciation and amortization
expense, down slightly from the 2004 average of $0.21 per Mcf.
For the first quarter of 2005, our operating costs for our tertiary
properties averaged $10.07 per BOE, slightly higher than the prior year average
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of $9.90 per BOE. Even though our average operating costs of approximately
$10.00 per BOE for our tertiary operations are near expectations, with the
increased emphasis on tertiary operations, it is a primary factor in the higher
total corporate average operating cost per BOE (see "Operating Results -
Production Expenses" below).
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 quarter
of 2005 net income is the effect of approximately $6.7 million ($4.6 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. Excluding these non-cash charges, net income for
the first quarter of 2005 would have been approximately $34.7 million.
Three Months Ended
March 31,
- ------------------------------------------------------------------ ----------------------------
Amounts in thousands, except per share amounts 2005 2004
- ------------------------------------------------------------------ ------------- -------------
Net income $ 30,067 $ 22,304
Net income per common share - basic 0.54 0.41
Net income per common share - diluted 0.51 0.40
Adjusted cash flow from operations (see below) $ 69,411 $ 58,920
Net change in assets and liabilities relating to operations (2,782) (5,925)
- ------------------------------------------------------------------ ------------- -------------
Cash flow from operations (1) $ 66,629 $ 52,995
- ------------------------------------------------------------------ ============= =============
(1) Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements of Cash Flows.
Adjusted cash flow from operations is a non-GAAP measure that represents
cash flow provided by operations before changes in assets and liabilities, as
calculated from our Unaudited Condensed Consolidated Statements of Cash Flows.
Cash flow from operations is the GAAP measure as presented in our Unaudited
Condensed Consolidated Statements of Cash Flows. In our discussion herein, we
have elected to discuss these two components of cash flow provided by operations
separately.
Adjusted cash flow from operations, the non-GAAP measure, measures the
cash flow earned or incurred from operating activities without regard to the
collection or payment of associated receivables or payables. We believe that
this is important to consider adjusted cash flow from operations separately, as
we believe it can often be a better way to discuss changes in operating trends
in our business caused by changes in production, prices, operating costs, and
related operational factors, without regard to whether the earned or incurred
item was collected or paid during that year. We also use this measure because
the collection of our receivables or payment of our obligations has not been a
significant issue for our business, but merely a timing issue from one period to
the next, with fluctuations generally caused by significant changes in commodity
prices or significant changes in drilling activity.
The net change in assets and liabilities relating to operations is also
important as it does require or provide additional cash for use in our business;
however, we prefer to discuss its effect separately. For instance, as noted
above, during the first quarter of both years, we used cash to fund a net
increase in our working capital. This was primarily caused by an increase in our
accrued production receivables during each first quarterly period caused
primarily by rising commodity prices. In the first quarter of 2005, this was
partially offset by higher accounts payables and accrued liabilities which
helped conserve our cash. The higher liabilities were a result of the increased
activity level compared to that of year end.
Certain of our operating results and statistics for the comparative first
quarters of 2005 and 2004 are included in the following table.
20
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended
March 31,
- ------------------------------------------------------------------------------------------------
2005 2004
- ------------------------------------------------------------------------------------------------
Average daily production volume
Bbls/d 20,263 19,404
Mcf/d 56,766 103,457
BOE/d (1) 29,724 36,647
Operating revenues (Thousands)
Oil sales $ 79,182 $ 54,525
Natural gas sales 31,834 55,711
------------- --------------
Total oil and natural gas sales $ 111,016 $ 110,236
============= ==============
Hedge Contracts(2) (Thousands)
Cash gain (loss) on hedge contracts $ (1,099) $ (14,268)
Non-cash hedging adjustments (6,722) (818)
------------- --------------
Total gain (loss) on hedge contracts $ (7,821) $ (15,086)
============= ==============
Operating expenses (Thousands)
Lease operating expenses $ 22,962 $ 22,528
Production taxes and marketing expenses 6,126 4,067
------------- --------------
Total production expenses $ 29,088 $ 26,595
============= ==============
CO2 sales and transportation fees (3) $ 1,730 $ 1,361
CO2 operating expenses (346) (144)
------------- --------------
CO2 operating margin $ 1,384 $ 1,217
============= ==============
Unit prices - including impact of hedges
Oil price per Bbl $ 43.42 $ 24.92
Gas price per Mcf 6.02 5.52
Unit prices - excluding impact of hedges
Oil price per Bbl $ 43.42 $ 30.88
Gas price per Mcf 6.23 5.92
Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues $ 41.50 $ 33.06
============= ==============
Oil and gas lease operating expenses $ 8.58 $ 6.76
Oil and gas production taxes and marketing expense 2.29 1.22
------------- --------------
Total oil and gas production expenses $ 10.87 $ 7.98
================================================================================================
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the Company's hedging transactions.
(3) For 2005 and 2004, includes deferred revenue of $622,000 and $511,000, respectively, associated with a volumetric
production payment and $717,000 and $566,000, respectively, of transportation income, both from Genesis.
21
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
- ---------- quarter of 2005 is listed in the following table.
Average Daily Production (BOE/d)
----------------------------------------------------------
First Second Third Fourth First
Quarter Quarter Quarter Quarter Quarter
Operating Area 2004 2004 2004 2004 2005
- ---------------------------------- ---------------------------------------------------------
Mississippi - non-CO2 floods 12,754 13,048 12,969 13,564 13,057
Mississippi - CO2 floods 6,318 6,603 6,967 7,242 8,644
Onshore Louisiana 8,825 7,492 7,033 7,182 6,710
Barnett Shale and other 229 345 803 963 1,313
---------------------------------------------------------
Total production excl. offshore 28,126 27,488 27,772 28,951 29,724
Offshore Gulf of Mexico 8,521 9,114 1,885 26 -
---------------------------------------------------------
Total Company 36,647 36,602 29,657 28,977 29,724
- ---------------------------------- =========================================================
As a result of the sale of our offshore properties in July 2004, overall
production was lower in the first quarter of 2005 than in the comparable quarter
of 2004. Adjusting for the offshore sale, overall production increased 6% on a
BOE basis in the first quarter of 2005 as compared to the first quarter of 2004,
and 3% over the prior 2004 fourth quarter level, anchored by the increased
production from our tertiary operations and Barnett Shale play, generally offset
by overall declines in our onshore natural gas wells in Louisiana.
As more fully discussed in "CO2 Operations" above, oil production from our
tertiary operations increased 19% in the first quarter of 2005 over tertiary
production in the prior quarter and 37% over first quarter of 2004 tertiary
production. Production in the Mississippi non-CO2 floods increased slightly over
levels in the prior year comparable quarter, but has been relatively stable at
around 13,000 BOE/d over the last five quarters. Although most of the production
in this area is on a gradual decline, the natural gas drilling in the Selma
Chalk at Heidelberg Field has been sufficient to generally offset these
declines. Natural gas production at Heidelberg averaged 14.7 MMcf/d in the first
quarter of 2005, up from 11.0 MMcf/d in the first quarter of 2004.
Our onshore Louisiana production has generally declined over the last year,
partially offset by incremental production from an occasional new well, with the
most significant decreases at the Thornwell and Lirette Fields. Production at
Thornwell declined to 930 BOE/d in the first quarter of 2005 as compared to
2,526 BOE/d in the first quarter of 2004. Similarly, although not as
significant, production at Lirette Field declined to 1,951 BOE/d in the first
quarter of 2005 as compared to 2,736 BOE/d in the first 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 early 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, increasing from 229 BOE/d (1.4
MMcf/d) in the first quarter of 2004 to 1,313 BOE/d (7.9 MMcf/d) in the first
quarter of 2005. Natural gas production in this area is expected to further
increase throughout 2005 as we expect to drill twenty to thirty wells in this
area during 2005.
Our production for the first quarter of 2005 was weighted toward oil (68%),
essentially the same oil/natural gas ratio that we had in the fourth quarter of
2004 following the sale of our offshore properties in July 2004. Because of our
emphasis on our tertiary operations, we expect to remain weighted toward oil in
the foreseeable future.
22
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
first quarter of 2005 increased $780,000, or 1%, from revenues in the comparable
quarter of 2004, as a result of higher commodity prices, almost entirely offset
by lower production resulting from the July 2004 sale of our offshore
properties. Cash payments on our hedges were $1.1 million in the first quarter
of 2005, down 92% from the $14.3 million paid during the first quarter of 2004,
as most of our out-of-the-money hedges expired at December 31, 2004. See "Market
Risk Management" for additional information regarding our hedging activities.
The 19% decrease in production in the first quarter of 2005 as a result of
the offshore sale decreased oil and natural gas revenues, when comparing the two
first quarters, by $21.8 million, or 23%. This decrease was more than offset by
an increase in overall commodity prices, increasing revenue by $22.6 million, or
24%, in the first quarter of 2005 as compared to the prior year first quarter.
Our realized natural gas prices (excluding hedges) for the first quarter of 2005
averaged $6.23 per Mcf, an 5% increase from the average of $5.92 per Mcf
realized during the first quarter of 2004, and our realized oil prices
(excluding hedges) for the first quarter of 2005 averaged $43.42 per Bbl, a 41%
increase from the $30.88 per Bbl average realized in the first quarter of 2004.
On a combined BOE basis, commodity prices were 26% higher in the first quarter
of 2005 as compared to prices in the first quarter of 2004.
Our net realized oil prices (excluding hedges) relative to NYMEX prices
were lower in the first quarter of 2005 than in the first quarter of 2004 as the
NYMEX differential deteriorated significantly during 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
differential for the first quarter of 2005 was approximately $6.54 per Bbl as
compared to $4.24 per Bbl during the first quarter of 2004 and an average of
$3.60 per Bbl during 2003. As of the last part of April, 2005, it appears that
these differentials may be beginning to narrow, although 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, which has sold for about $1.00 less than NYMEX prices during the
last two quarters, our overall natural gas NYMEX differential will likely
increase.
PRODUCTION EXPENSES: While lease operating expenses were approximately the
same in the respective first quarters, on a per BOE basis operating expenses
increased 27%, from $6.76 per BOE in the first quarter of 2004 to $8.58 per BOE
in the first quarter of 2005. These per BOE operating expenses compare to an
average of $7.60 per BOE in the fourth quarter of 2004. The single biggest
factor for the increase relates to the increasing emphasis on tertiary
operations, with operating costs that averaged $9.90 per BOE during 2004 and
$10.07 per BOE during the first quarter of 2005, higher than the operating costs
for our other operations. The balance of the cost increases is generally
attributable to higher energy costs to operate our properties and general cost
inflation in the industry.
Production taxes and marketing expenses generally change in proportion to
commodity prices and therefore were higher in the first quarter of 2005 than in
the comparable quarter of 2004. 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 $936,000 of transportation expenses paid to
Genesis during the first quarter 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 crude oil to Genesis at the wellhead,
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.
23
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General and Administrative Expenses
General and administrative ("G&A") expenses increased 37% between the
respective first quarters as set forth below:
Three Months Ended
March 31,
- ------------------------------------------------- -----------------------------------
2005 2004
- ------------------------------------------------- ---------------- ----------------
Net G&A expense (thousands)
Gross G&A expenses $ 14,378 $ 12,680
State franchise taxes 309 246
Operator overhead charges (6,986) (6,780)
Capitalized exploration costs (1,206) (1,398)
---------------- ----------------
Net G&A expense $ 6,495 $ 4,748
================ ================
Average G&A cost per BOE $ 2.43 $ 1.42
Employees as of March 31 400 378
- ------------------------------------------------- ---------------- ----------------
Gross G&A expenses increased $1.7 million, or 13%, between the first
quarters of 2005 and 2004. The largest increase in the first quarter of 2005
relates to approximately $1.0 million of non-cash compensation expense
associated with the amortization of deferred compensation resulting from the
issuance of restricted stock to officers and directors during 2004 and an
increase of approximately $950,000 in incremental consultant fees, primarily
related to compliance costs associated with, or audit work related to, the
Sarbanes-Oxley Act. These 2005 increases were partially offset by approximately
$500,000 of severance payments in the first quarter of 2004 for a portion of the
offshore professional and technical staff that were severed in March 2004 in
conjunction with the sale of our offshore properties.
The increase in gross G&A was offset in part by a slight increase in
operator overhead recovery charges in the first quarter 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 first quarter of 2005, partially
offset by the sale of our offshore properties, the amount we recovered as
operator overhead charges increased by 3% between the respective first quarters
of 2005 and 2004. Capitalized exploration costs decreased slightly between the
comparable periods in 2005 and 2004 as a result of the 2004 termination of a
portion of our offshore exploration staff.
The net effect was a 37% increase in net G&A expense between the respective
first quarters. On a per BOE basis, G&A costs increased 71% in the first quarter
of 2005 as compared to those costs in the first quarter of 2004, which is a
higher percentage increase than the increase in gross costs; this 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.
24
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest and Financing Expenses
Three Months Ended
March 31,
- ---------------------------------------------------- ----------------------------------
Amounts in thousands, except per BOE amounts 2005 2004
- ---------------------------------------------------- -------------- ----------------
Interest expense, including capitalized interest $ 4,738 $ 5,081
Non-cash interest expense (205) (227)
-------------- ----------------
Cash interest expense 4,533 4,854
Interest and other income (616) (419)
Capitalized interest (262) -
-------------- ----------------
Net cash interest expense $ 3,655 $ 4,435
============== ================
Average net cash interest expense per BOE $ 1.37 $ 1.33
Average interest rate (1) 7.5% 6.3%
Average debt outstanding $ 240,632 $ 306,121
- ---------------------------------------------------- ============== ================
(1) Includes commitment fees but excludes amortization of discount and debt issue costs.
Interest expense for the first quarter of 2005 decreased from levels in the
comparable prior year period primarily due to lower average debt levels in 2005
as a result of the sale of our offshore properties in July 2004, the proceeds of
which were used to retire our bank debt. Interest and other income increased in
the first quarter of 2005 as compared to levels of interest and other income in
the first quarter of 2004 as a result of higher average cash balances, also
related to the offshore sale. Interest expense increased slightly in the first
quarter of 2005 as compared to the fourth quarter of 2004 level of such
expenses, as a result of approximately $6.8 million of capital leases entered
into late in 2004 and in early 2005.
Depletion, Depreciation and Amortization
Three Months Ended
March 31,
- --------------------------------------------------- ---------------------------------
Amounts in thousands, except per BOE amounts 2005 2004
- --------------------------------------------------- --------------- --------------
Depletion and depreciation $ 19,410 $ 25,004
Depletion and depreciation of CO2 assets 1,206 1,138
Accretion of asset retirement obligations 321 768
Depreciation of other fixed assets 591 414
--------------- --------------
Total DD&A $ 21,528 $ 27,324
=============== ==============
DD&A per BOE:
Oil and natural gas properties $ 7.38 $ 7.73
CO2 assets and other fixed assets 0.67 0.46
- --------------------------------------------------- --------------- --------------
Total DD&A cost per BOE $ 8.05 $ 8.19
- --------------------------------------------------- =============== ==============
In total, our depletion, depreciation and amortization ("DD&A") rate on a
per BOE basis decreased 2% between the respective first quarters, primarily due
to the offshore property sale in July 2004 which lowered our DD&A rate,
partially offset by an increase in certain of our future development costs
estimates to reflect the rising costs in the industry, causing our DD&A rate to
increase during the latter half of 2004. Our first quarter of 2005 DD&A rate of
$8.05 was only slightly higher than the fourth quarter 2004 DD&A rate of $7.98
per BOE, as we recognized incremental reserves in the first quarter of 2005 in
25
the Barnett Shale in Texas and Selma Chalk at Heidelberg, both from our
increased drilling activity in those areas, and in Southern Louisiana from our
late 2004 and early 2005 exploratory drilling success there. We did not book any
incremental oil reserves related to our tertiary operations during the first
quarter 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
change significantly in the future.
Our DD&A rate for our CO2 and other fixed assets increased in 2005 as a
result of additional depreciation of fixed assets acquired during 2004 and 2005.
Income Taxes
Three Months Ended
March 31,
- ------------------------------------------------------------- ---------------------------------
Amounts in thousands, except per BOE amounts and tax rates 2005 2004
- ------------------------------------------------------------- -------------- ---------------
Income tax provision
Current income tax expense $ 5,282 $ 2,119
Deferred income tax expense 8,546 8,522
-------------- ---------------
Total income tax expense $ 13,828 $ 10,641
============== ===============
Average income tax expense per BOE $ 5.17 $ 3.19
Effective tax rate 31.5% 32.3%
- ------------------------------------------------------------- -------------- ---------------
Our income tax provision for the first quarter of 2005 and 2004 was based
on an estimated statutory tax rate of 39% and 38% respectively. Our net
effective tax rates are lower than the statutory rates, primarily due to the
recognition of enhanced oil recovery credits which lowered our overall tax
expense. The current income tax expense represents our anticipated alternative
minimum cash taxes that we cannot offset with regular tax net operating loss
carryforwards or enhanced oil recovery credits. 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.
26
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended
March 31,
- --------------------------------------------------------------- --------------------------
Per BOE data 2005 2004
- --------------------------------------------------------------- ------------ ------------
Revenues $ 41.50 $ 33.06
Loss on settlements of derivative contracts (0.41) (4.28)
Lease operating expenses (8.58) (6.76)
Production taxes and marketing expenses (2.29) (1.22)
- --------------------------------------------------------------- ------------ ------------
Production netback 30.22 20.80
CO2 operating margin 0.52 0.37
General and administrative expenses (2.43) (1.42)
Net cash interest expense (1.37) (1.33)
Current income taxes and other (0.99) (0.75)
Changes in assets and liabilities relating to operations (1.04) (1.78)
- --------------------------------------------------------------- ------------ ------------
Cash flow from operations 24.91 15.89
DD&A (8.05) (8.19)
Deferred income taxes (3.19) (2.56)
Non-cash hedging adjustments (2.51) (0.25)
Changes in assets and liabilities and other non-cash items 0.08 1.80
- --------------------------------------------------------------- ------------ ------------
Net income $ 11.24 $ 6.69
- --------------------------------------------------------------- ============ ============
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. We had no bank debt
outstanding as of March 31, 2005 or December 31, 2004. 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 Value Value
- ----------------------------------------- ------------ ------------ ------------ ------------ ------------- -----------
Fixed rate debt:
7.5% subordinated debt,
net of discount, due 2013......... $ - $ - $ - $ - $ 223,446 $ 228,803
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. Much of our historical
hedging activity has been done with collars, although for the 2002 COHO
acquisition, we also used swaps in order to lock in the prices used in our
economic forecasts. 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
27
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
procedures, and diversification. For a full description of our hedging position
at March 31, 2005, see Note 6 to the Condensed Consolidated Financial
Statements.
Effective January 1, 2005, we elected to de-designate our existing
derivative contracts as hedges 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 balance 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 first quarter of 2005, we recognized total expenses relating to our
hedge contracts of $7.8 million consisting of $1.1 of cash payments, $4.9
million relating to a mark-to-market non-cash adjustment attributable to higher
commodity prices and the resultant decrease in value, and $1.8 million 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 6 to the
Condensed Consolidated Financial Statements.
At March 31, 2005, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $9.8 million, an increase of
approximately $4.9 million 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 hedges due to an increase in oil and natural gas commodity
prices between December 31, 2004 and March 31, 2005.
Based on NYMEX crude oil futures prices at March 31, 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 would go. Based on NYMEX natural gas
futures prices at March 31, 2005, we would expect to make future cash payments
of $9.8 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 $6.6 million, and if futures
prices were to increase by 10% we would expect to pay $13.1 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.
28
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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.
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 the 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 in prior periods for such excess tax deductions
were $4.8 million during the year ended December 31, 2004.
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.
29
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 all material
respects in providing to them on a timely basis material information required to
be disclosed in this quarterly report.
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 being
changed 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 until we have fully
tested all changes to our controls, we may not be able to provide assurance that
our internal controls over financial reporting are effective in all material
respects. 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.
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
- ----------------------------------------------------------------------------------------------------------
Total 50,000 $ 30.95 50,000 50,000
- ----------------------------------------------------------------------------------------------------------
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
30
DENBURY RESOURCES INC.
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. In May 2004, the Board of Directors
renewed the Plan for another year beginning July 1, 2004 and ending June 30,
2005, covering another 200,000 shares at the same 50,000 shares per quarter
rate. Purchases are to be made at prices and times determined at the discretion
of the independent broker, provided however that no purchases may be made during
the last ten business days of a fiscal quarter.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
- ----------------------------------------
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------------------------------------------------------------
None.
ITEM 5. OTHER INFORMATION
- --------------------------
None.
ITEM 6. EXHIBITS
- -----------------
Exhibits:
10* First Amendment to Fifth Amended and Restated Credit
Agreement among Denbury Onshore, LLC, as Borrower, Denbury
Resources Inc, as Parent Guarantor, Bank One, N.A. as
Administrative Agent, and certain other financial
institutions dated as of April 1, 2005.
31(a)* Certification of Chief Executive Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial
Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
* Filed herewith.
31
DENBURY RESOURCES INC.
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: May 9, 2005
32