UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
---------------------
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
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
(State or other
jurisdiction of 75-2815171
incorporation or (I.R.S. Employer
organization) Identification No.)
5100 TENNYSON PARKWAY
SUITE 3000
PLANO, TX
(Address of principal 75024
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 the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
CLASS OUTSTANDING AT OCTOBER 31, 2000
----- -------------------------------
Common Stock, $.001 par value 45,906,776
<PAGE>
DENBURY RESOURCES INC.
INDEX
Page
----
Part I. Financial Information
-----------------------------
Item 1. Financial Statements 3
Independent Accountants' Report 3
Condensed Consolidated Balance Sheets at
September 30, 2000 (Unaudited)and December 31, 1999 4
Condensed Consolidated Statements of Operations for
the Three and Nine Months ended September 30, 2000
and 1999 (Unaudited) 5
Condensed Consolidated Statements of Cash Flows for the
Nine Months ended September 30, 2000
and 1999 (Unaudited) 6
Notes to Condensed Consolidated Financial Statements 7-9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 10-19
Item 3. Quantitative and Qualitative Disclosures about Market Risk 19
Part II. Other Information
---------------------------
Item 6. Exhibits and Reports on Form 8-K 20
Signatures 21
2
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
-----------------------------
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Directors of Denbury Resources Inc.:
We have reviewed the accompanying condensed consolidated balance sheet of
Denbury Resources Inc. and subsidiaries (the "Company") as of September 30,
2000, and the related condensed consolidated statements of operations for the
three and nine-month periods ended September 30, 2000 and 1999 and cash flows
for the nine-month periods ended September 30, 2000 and 1999. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to such condensed consolidated financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of
Denbury Resources Inc. and subsidiaries as of December 31, 1999 and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year then ended (not presented herein); and in our report dated February 22,
2000, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
condensed consolidated balance sheet as of December 31, 1999 is fairly stated,
in all material respects, in relation to the consolidated balance sheet from
which it has been derived.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Dallas, Texas
November 10, 2000
3
<PAGE>
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of U.S. dollars except share amounts)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
---------------- ---------------
(Unaudited)
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 14,200 $ 11,768
Accrued production receivable 26,663 15,836
Trade and other receivables 6,071 2,942
------------ ------------
Total current assets 46,934 30,546
------------ ------------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and gas properties 680,356 587,412
Unevaluated oil and gas properties 9,469 41,371
Less accumulated depreciation and depletion (440,151) (417,828)
------------ ------------
Net property and equipment 249,674 210,955
------------ ------------
OTHER ASSETS 11,651 11,065
------------ ------------
TOTAL ASSETS $ 308,259 $ 252,566
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 30,685 $ 18,042
Oil and gas production payable 10,681 7,120
------------ ------------
Total current liabilities 41,366 25,162
------------ ------------
LONG-TERM LIABILITIES
Long-term debt 146,000 152,500
Provision for site reclamation costs 2,657 1,820
Other liabilities 655 656
------------ ------------
Total long-term liabilities 149,312 154,976
------------ ------------
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;
45,906,776 and 45,718,486 shares issued and outstanding at September
30, 2000 and December 31, 1999, respectively 46 46
Paid-in capital in excess of par 328,825 327,829
Accumulated deficit (211,290) (255,447)
------------ ------------
Total stockholders' equity 117,581 72,428
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 308,259 $ 252,566
============ ============
</TABLE>
(See accompanying notes to Condensed Consolidated Financial Statements)
4
<PAGE>
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
(Unaudited - U.S. dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2000 1999 2000 1999
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
REVENUES
Oil, gas and related product sales $ 44,053 $ 22,040 $ 116,440 $ 54,601
Interest and other income 696 338 1,626 1,069
------------ ------------- ------------ ------------
Total revenues 44,749 22,378 118,066 55,670
------------ ------------- ------------ ------------
EXPENSES
Operating costs 9,737 6,742 27,873 17,655
Production taxes 2,059 1,139 5,370 2,568
General and administrative 1,960 1,773 5,835 5,333
Interest 3,545 3,492 10,763 12,170
Depletion and depreciation 8,228 6,704 23,558 17,649
Franchise taxes 100 124 389 428
------------ ------------- ------------ ------------
Total expenses 25,629 19,974 73,788 55,803
------------ ------------- ------------ ------------
Income (loss) before income taxes 19,120 2,404 44,278 (133)
Income tax provision 81 - 121 -
------------ ------------- ------------ ------------
NET INCOME (LOSS) $ 19,039 $ 2,404 $ 44,157 $ (133)
============ ============= ============ ============
NET INCOME (LOSS) PER COMMON SHARE
Basic $ 0.42 $ 0.05 $ 0.96 $ 0.00
Diluted 0.41 0.05 0.96 0.00
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic 45,856 45,587 45,792 38,001
Diluted 46,505 45,589 46,127 38,085
</TABLE>
(See accompanying notes to Condensed Consolidated Financial Statements)
5
<PAGE>
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of U.S. dollars)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
----------------------------------
2000 1999
--------------- -------------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss) $ 44,157 $ (133)
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization 23,558 17,649
Other 689 1,126
--------------- -------------
68,404 18,642
Changes in working capital items relating to operations:
Accrued production receivable (10,827) (7,796)
Trade and other receivables (2,709) 11,852
Accounts payable and accrued liabilities 12,643 (2,915)
Oil and gas production payable 3,561 1,630
Other assets (1,392) -
--------------- -------------
NET CASH PROVIDED BY OPERATIONS 69,680 21,413
--------------- -------------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and gas expenditures (59,132) (22,281)
Acquisitions of oil and gas properties (3,300) (18,995)
Net purchases of other assets (841) (1,109)
Proceeds from dispositions of oil and gas properties 1,390 395
(Increase) decrease in restricted cash 264 (1,798)
--------------- -------------
NET CASH USED FOR INVESTING ACTIVITIES (61,619) (43,788)
--------------- -------------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments (6,500) (100,000)
Bank borrowings - 27,500
Issuance of common stock 996 99,802
Other (125) (527)
--------------- -------------
NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES (5,629) 26,775
--------------- -------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 2,432 4,400
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 11,768 2,049
--------------- -------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 14,200 $ 6,449
=============== =============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest $ 12,908 $ 9,813
=============== =============
</TABLE>
(See accompanying notes to Condensed Consolidated Financial Statements)
6
<PAGE>
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Interim Financial Statements
The accompanying condensed consolidated financial statements of Denbury
Resources Inc. (the "Company" or "Denbury") have been prepared in accordance
with generally accepted accounting principles and pursuant to the rules and
regulations of the Securities and Exchange Commission ("SEC"). These financial
statements and the notes thereto should be read in conjunction with the
Company's annual report on Form 10-K for the year ended December 31, 1999. Any
capitalized terms used but not defined in these Notes to Condensed Consolidated
Financial Statements have the same meaning given to them in the Form 10-K.
The financial data for the three and nine month periods ended September 30,
2000 and 1999, included herein, have been subjected to a limited review by
Deloitte & Touche LLP, Denbury's independent accountants. 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 the opinion of management of Denbury, the accompanying unaudited
condensed consolidated financial statements include all adjustments (of a normal
recurring nature) necessary to present fairly the consolidated financial
position of the Company as of September 30, 2000 and the consolidated results of
its operations for the three and nine months ended September 30, 2000 and 1999
and its cash flows for the nine months ended September 30, 2000 and 1999.
2. NET INCOME (LOSS) PER COMMON SHARE
Basic net income (loss) per common share is computed by dividing net income
or loss by the weighted average number of shares of common stock outstanding
during the period. Diluted net income (loss) 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, stock warrants, and any other
convertible securities outstanding. For the three and nine month periods ended
September 30, 2000 and 1999, there were no adjustments to net income for
purposes of calculating diluted net income (loss) per common share. The
following is a reconciliation of the weighted average common shares used in the
basic and diluted net income (loss) per common share calculations for the three
and nine month periods ended September 30, 2000 and 1999 (shares in thousands).
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2000 1999 2000 1999
------------ ------------ ----------- -----------
<S> <C> <C> <C> <C>
Weighted average common shares - basic 45,856 45,587 45,792 38,001
Potentially dilutive securities:
Stock options 649 2 335 84
------------ ------------ ----------- -----------
Weighted average common shares - diluted 46,505 45,589 46,127 38,085
============ ============ =========== ===========
</TABLE>
For the three and nine month periods ended September 30, 2000,
approximately 1.5 million and 1.6 million shares represented by stock options,
respectively, were excluded from the diluted net income per common share
calculation as the exercise prices of these options exceeded the average market
price of the Company's common stock for these periods. For the three and nine
month periods ended September 30, 1999, approximately 3.2 million and 1.7
million shares represented by stock options, respectively, were excluded from
the diluted net income (loss) per common share calculation as the exercise
prices of these options exceeded the average market price of the Company's
common stock for these periods.
7
<PAGE>
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
--------------- ---------------
(Unaudited)
(Amounts in thousands)
<S> <C> <C>
9% Senior Subordinated Notes Due 2008 $ 125,000 $ 125,000
Senior bank loan 21,000 27,500
--------------- ---------------
Total long-term debt $ 146,000 $ 152,500
=============== ===============
</TABLE>
The Company's bank credit facility provides for a semi-annual
redetermination of the borrowing base on April 1st and October 1st. At the
October 1, 2000 redetermination, the Company's conforming borrowing base was
increased from $60 million to $110 million and the total borrowing base remained
at $110 million. In June 2000, the Company repaid $4.0 million of its
outstanding bank debt and in September 2000 repaid an additional $2.5 million,
which leaves the Company with a total borrowing capacity of $89.0 million as of
September 30, 2000. The next scheduled borrowing base redetermination is as of
April 1, 2001.
On October 13, 2000, the Company amended and restated its bank credit
facility with Bank of America, as agent for a group of seven other banks. Among
other things, the amendment (i) extended the credit line for one additional
year, to December 31, 2003, (ii) increased the interest rate on the loan by
increasing the LIBOR margin for Eurodollar loans by 0.25%, (iii) reduced the
number of banks in the line by one and re-allocated the loan among the remaining
eight banks, (iv) increased the Company's conforming borrowing base from $60
million to $110 million, and (v) included various other minor changes. The total
borrowing base of $110 million was not changed.
4. PRODUCT PRICE HEDGING CONTRACTS
The Company has financial contracts that hedge its exposure to commodity
price risk on a portion of its oil and natural gas production. The Company has a
contract on its oil production that hedges 3,000 Bbls/d with a price floor of
$14.00 per Bbl and a price ceiling of $18.05 per Bbl. This contract has been in
effect since April 1999, expires as of December 31, 2000, and hedges
approximately 19% of the Company's oil production based on the third quarter of
2000 average oil production. The Company also has a contract that hedges 24
million cubic feet of natural gas per day with a price floor of $1.90 per MMBtu
and a price ceiling of $2.58 per MMBtu. This contract has been in effect since
1998, expires as of December 31, 2000, and hedges approximately 78% of the
Company's natural gas production based on the third quarter of 2000 average
natural gas production.
During the third quarter of 2000 the Company paid approximately $3.7
million on the oil hedge contract and $3.8 million on the natural gas hedge
contract. Through the first nine months of 2000 the Company paid approximately
$9.5 million on the oil hedge contract and $5.7 million on the natural gas hedge
contract. Based on futures market prices at September 30, 2000, the Company
would expect to pay approximately $3.5 million on the oil hedge contract and
$5.9 million on the natural gas hedge contract through their expiration at the
end of 2000.
For years 2001 and 2002 the Company has entered into puts or floors to
hedge a portion of its anticipated oil and natural gas production. See "Market
Risk Management" in Management's Discussion and Analysis of Financial Condition
and Results of Operations for further discussion regarding these contracts and
the Company's other derivative financial instruments.
8
<PAGE>
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5. SIGNIFICANT INCREASE IN RESERVES
As of June 30, 2000, the engineering firm of DeGolyer and MacNaughton
prepared a reserve report for the Company on its four largest fields,
Heidelberg, Eucutta, Little Creek and Lirette, which as of December 31, 1999
comprised 78% of the Company's total value on both a BOE and PV10 (estimated
future net revenues discounted at 10%) basis. For comparative purposes, the June
30, 2000 reserve report was prepared using the same unescalated price scenario
used in the December 31, 1999 SEC report, which was based on a NYMEX oil price
of $25.60 per barrel ("Bbl") and a NYMEX natural gas price of $2.12 per million
British thermal units ("MMBtu"). Using these prices, following are the
comparative values of proved reserves at December 31, 1999 and June 30, 2000 for
these four fields:
<TABLE>
<CAPTION>
Jan. to June,
December 31, 1999 June 30, 2000 2000
------------------------- ------------------------ Production
Field MBOE PV10 MBOE PV10 (MBOE)
--------------------- ---------- ------------ ---------- ------------ ------------------
<S> <C> <C> <C> <C> <C>
Heidelberg 32,789 $ 238,192 47,470 $ 270,475 1,236
Eucutta 4,902 41,672 6,303 52,905 401
Little Creek 6,146 58,440 8,505 86,554 353
Lirette 2,890 21,027 2,062 14,736 240
---------- ------------ ---------- ------------ ------------------
Four Field Total 46,727 $ 359,331 64,340 $ 424,670 2,230
========== ============ ========== ============ ==================
</TABLE>
The PV10 value of these same four fields using unescalated oil and natural
gas prices as of June 30, 2000 was $657.8 million based on a NYMEX oil price of
$32.50 per barrel and a NYMEX natural gas price of $4.46 per MMBtu.
6. SIGNIFICANT PROPERTY ACQUISITIONS (SUBSEQUENT EVENT)
During October, 2000, the Company purchased, or signed purchase and sale
agreements to purchase, interests in three fields located in southwestern
Louisiana for a total consideration of $66.5 million, less interim net revenue
and expenses from August 1, 2000, the effective date of the purchases (the
"Recent Acquisitions"). The transactions consist of 42 producing wells located
in Thornwell, Iberia and Port Barre Fields. The two acquisitions in the
Thornwell Field have been completed at a total cost of $57 million and the
remaining $9.5 million acquisition in the Iberia and Port Barre Fields is
expected to close by the end of November, subject to normal closing conditions.
These acquisitions are being funded through the Company's existing bank credit
facility.
The current daily production from these acquisitions is approximately 80%
natural gas. Based on preliminary estimates by the Company, these acquisitions
are expected to add net proved reserves of approximately 30 billion cubic feet
of natural gas (5 MMBOE) as of August 1, 2000. The Company has purchased price
floors (i.e. puts) for $2.5 million covering 100% of the forecasted proven
natural gas production from these acquisitions for 2001 and 2002. The price
floors vary by quarter but range from $2.94 to $4.25 for 2001 and from $2.93 to
$3.65 for 2002, with a weighted average price of $3.51 for 2001 and $3.23 for
2002.
9
<PAGE>
DENBURY RESOURCES INC.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
--------------------------------------------------------------------------------
OF OPERATIONS
-------------
The following should be read in conjunction with the Company's financial
statements contained herein and in the Form 10-K for the year ended December 31,
1999, along with Management's Discussion and Analysis of Financial Condition and
Results of Operations contained in such Form 10-K. Any capitalized terms used
but not defined in the following discussion have the same meaning given to them
in the Form 10-K.
Denbury is a growing independent oil and gas company engaged in
acquisition, development and exploration activities in the U.S. Gulf Coast
region. The Company is the largest oil and natural gas operator in Mississippi
and holds key operating acreage in the onshore Louisiana and offshore Gulf of
Mexico areas. The Company increases the value of acquired properties through a
combination of exploitation, drilling, and proven engineering extraction
processes.
SIGNIFICANT 2000 EVENTS
PROPERTY ACQUISITIONS
During October, 2000, the Company purchased, or signed purchase and sale
agreements to purchase, interests in three fields located in southwestern
Louisiana for a total consideration of $66.5 million, less interim net revenue
and expenses from August 1, 2000, the effective date of the purchases (the
"Recent Acquisitions"). The transactions consist of 42 producing wells located
in Thornwell, Iberia and Port Barre Fields. The two acquisitions in the
Thornwell Field have been completed at a total cost of $57 million and the
remaining $9.5 million acquisition in the Iberia and Port Barre Fields is
expected to close by the end of November, subject to normal closing conditions.
These acquisitions are being funded through the Company's existing bank credit
facility.
The current daily production from these acquisitions is approximately 80%
natural gas. Based on preliminary estimates by the Company, these acquisitions
are expected to add net proved reserves of approximately 30 billion cubic feet
of natural gas (5 MMBOE) as of August 1, 2000. The Company has purchased price
floors (i.e. puts) for $2.5 million covering approximately 100% of the
forecasted proven natural gas production from these acquisitions for 2001 and
2002. The price floors vary by quarter but range from $2.94 to $4.25 for 2001
and from $2.93 to $3.65 for 2002, with a weighted average price of $3.51 for
2001 and $3.23 for 2002.
AMENDMENT TO BANK CREDIT FACILITY
On October 13, 2000, the Company amended and restated its bank credit
facility with Bank of America, as agent for a group of seven other banks. Among
other things, the amendment (i) extended the credit line for one additional
year, to December 31, 2003, (ii) increased the interest rate on the loan by
increasing the LIBOR margin for Eurodollar loans by 0.25%, (iii) reduced the
number of banks in the line by one and re-allocated the loan among the remaining
eight banks, (iv) increased the Company's conforming borrowing base from $60
million to $110 million, and (v) included various other minor changes. The total
borrowing base of $110 million was not changed.
CAPITAL RESOURCES AND LIQUIDITY
As more fully described under "Results of Operations" below, the Company's
results of operations, cash flows and financial position improved throughout
1999 and have continued to improve through the first nine months of 2000,
primarily as a result of increasing oil prices and increasing oil and natural
gas production. Oil prices have improved from the 1998 year-end NYMEX oil price
of approximately $12.00 per Bbl to $17.51 per Bbl for the first nine months of
1999 and to $29.70 per Bbl for the first nine months of 2000. In addition, the
Company's average daily production has increased for the sixth consecutive
quarter, with average daily production of 20,553 barrels of oil equivalent
produced per day ("BOE/d") for the third quarter of 2000, a 21% increase from
the third quarter of 1999 average of 17,034 BOE/d and a 5% increase from the
second quarter of 2000 average of 19,580 BOE/d. As a result of the improved
product prices and increased production, the Company posted record quarterly
earnings and cash flow generated from operations in the third quarter and first
nine months of 2000, up sharply from the financial results for the comparable
periods of 1999.
10
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
During the first nine months of 2000 the Company spent $59.1 million on
exploration and development expenditures and is on track to spend approximately
$80 to $85 million for the full year 2000. The Company has increased its 2000
budget, from its initial estimate of $60 million, three times during the year as
new projects were added as a result of increased cash flow and additional
spending anticipated on the Recent Acquisitions (see "Recent Acquisitions"
above). Although the level of the Company's projected cash flow is highly
variable and difficult to predict due to volatility in product prices, the
success of its drilling and other developmental work and other factors, the
Company has attempted to keep development and exploration spending at or near
the level of available cash flow from operations. During the first nine months
of 2000, the Company spent approximately $9.3 million less than cash flow from
operations (before the changes in working capital balances) on development and
exploration expenditures. These excess funds were used to fund the Company's
minor acquisitions, which aggregated $3.3 million during the first nine months
of 2000, and to reduce bank debt during the period by $6.5 million.
The Company's bank credit facility provides for a semi-annual
redetermination of the borrowing base on April 1st and October 1st. At the
October 1, 2000 redetermination, the Company's conforming borrowing base was
increased from $60 million to $110 million and the total borrowing base of $110
million was re-affirmed. As of September 30, 2000, the Company had not borrowed
any additional funds on its bank credit facility since the third quarter of
1999, when it acquired Little Creek Field in Mississippi for approximately $12
million. The Company repaid $4.0 million on its credit line in the second
quarter of 2000 and an additional $2.5 million in the third quarter of 2000,
which leaves the Company with a total borrowing capacity of $89.0 million at the
end of the third quarter. Subsequent to September 30, 2000, the Company has
borrowed $61 million on its bank credit facility to fund the Recent Acquisitions
(see "Recent Acquisitions" above) that have closed to date and the $5.1 million
cost of puts or floors acquired for 2001 and 2002 (see "Market Risk Management"
below), leaving it with a current availability on its bank line of $28 million.
The Company plans to continue to reserve this credit line primarily for
potential acquisitions. The next scheduled borrowing base redetermination will
be as of April 1, 2001. Although the Company anticipates that the borrowing base
will either increase or remain unchanged as a result of the additional
collateral that has been provided by the Recent Acquisitions, there can be no
assurance that the banks will not reduce the borrowing base at that time, as
such redetermination will depend on current and expected oil and natural gas
prices at that time, the Company's development and acquisition results during
2000 and its then current level of debt and other factors, some of which are
beyond the Company's control.
During the last year, the Company's production has grown at an annual rate
of 20-25%. At the Company's current capital spending levels and with the current
level of commodity prices, the Company expects that this trend should continue
into 2001. If commodity prices were to significantly decline, the Company could
adjust its capital spending levels accordingly. The Company has purchased puts
or floors which cover approximately 78% of its expected 2001 production (See
"Market Risk Management") and which helps assure that at least a majority of the
Company's capital program can be implemented and that it can achieve a minimum
rate of return on its Recent Acquisitions, assuming that its proved reserve
forecast and other assumptions related to the Recent Acquisitions are correct.
The Company is also continuing to pursue acquisitions which, if accomplished,
should be accretive to the Company's operating results. There can be no
assurance that suitable acquisitions will be identified in the future or that
such acquisitions will be successful in achieving desired profitability
objectives. The Company's future growth could be limited or even eliminated if
the Company is unable to complete suitable acquisitions or is unable to fund
such acquisitions over an extended period of time.
SOURCES AND USES OF FUNDS
During the first three quarters of 2000, the Company spent approximately
$59.1 million on exploration and development expenditures and approximately $3.3
million on acquisitions. The exploration and development expenditures included
approximately $30.4 million spent on drilling, $6.5 million on geological,
geophysical and acreage expenditures and $22.2 million on facilities and
workover costs. These expenditures were funded primarily by cash flow from
operations.
11
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
In contrast, during the first three quarters of 1999 the Company spent
approximately $22.3 million on oil and natural gas development expenditures and
approximately $19.0 million on acquisitions. The development expenditures
included approximately $3.3 million spent on drilling, $4.8 million on
geological, geophysical and acreage expenditures and $14.2 million spent on
facilities and workover costs. These expenditures were funded by cash flow from
operations and bank debt.
RESULTS OF OPERATIONS
The Company's operating results for the third quarter and nine months ended
September 30, 2000 improved significantly over the comparable prior year periods
due to the improved oil and natural gas prices and the Company's sixth
consecutive quarterly increase in production, partially offset by an increase in
operating expenses, as further set forth below.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------------------- ------------------------------ ----------------------------
2000 1999 2000 1999
------------------------------------------------- ------------- ------------ ------------ -----------
<S> <C> <C> <C> <C>
AVERAGE DAILY PRODUCTION VOLUME
Bbls 15,405 12,500 14,867 11,449
Mcf 30,885 27,204 29,324 28,270
BOE(1) 20,553 17,034 19,754 16,160
OPERATING REVENUES AND EXPENSES(THOUSANDS)
Oil sales $ 34,827 $ 15,673 $ 93,016 $ 36,649
Natural gas sales 9,226 6,367 23,424 17,952
------------- ------------ ------------ -----------
Total oil and natural gas revenues $ 44,053 $ 22,040 $ 116,440 $ 54,601
------------- ------------ ------------ -----------
Operating costs $ 9,737 $ 6,742 $ 27,873 $ 17,655
Production taxes 2,059 1,139 5,370 2,568
------------- ------------ ------------ -----------
Total production expenses $ 11,796 $ 7,881 $ 33,243 $ 20,223
------------- ------------ ------------ -----------
UNIT PRICES-INCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 24.57 $ 13.63 $ 22.83 $ 11.73
Gas price per Mcf 3.25 2.54 2.92 2.33
UNIT PRICES-EXCLUDING IMPACT OF HEDGES
Oil price per Bbl $ 27.20 $ 16.64 $ 25.17 $ 13.01
Gas price per Mcf 4.59 2.79 3.62 2.34
OPERATING REVENUES AND EXPENSES PER BOE(1)
Oil and natural gas revenues $ 23.30 $ 14.06 $ 21.51 $ 12.38
------------- ------------ ------------ -----------
Operating costs $ 5.15 $ 4.30 $ 5.15 $ 4.00
Production taxes 1.09 0.73 0.99 0.58
------------- ------------ ------------ -----------
Total production expenses $ 6.24 $ 5.03 $ 6.14 $ 4.58
------------------------------------------------- ------------- ------------ ------------ -----------
<FN>
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
</FN>
</TABLE>
12
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
PRODUCTION: In the third quarter of 2000, production increased for the
sixth consecutive quarter, with average daily production of 20,553 BOE/d, a
3,519 BOE/d (21%) increase from the third quarter of 1999 and a 973 BOE/d (5%)
increase from the second quarter of 2000. Production for the nine months ended
September 30, 2000 averaged 19,754 BOE/d, a 22% increase over the first nine
months of 1999. The production increase over the third quarter of 1999 is due
primarily to production increases at Heidelberg Field (1,531 BOE/d), Little
Creek Field (1,282 BOE/d), Eucutta Field (417 BOE/d) and King Bee Field (216
BOE/d), offset in part by normal decreases in other minor fields. The production
increase over the first nine months of 1999 is due primarily to production
increases at Heidelberg Field (1,645 BOE/d), Little Creek Field (1,719 BOE/d)
and King Bee Field (422 BOE/d), offset in part by normal decreases in other
minor fields. The Company has also increased its presence in the offshore arena
in the Gulf of Mexico with an acquisition in May 2000, which added 255 BOE/d and
151 BOE/d to the third quarter and nine months ended September 30, 2000,
respectively.
The production increase for the Company's largest field, Heidelberg Field,
represents the eleventh consecutive quarterly increase for that field, with
average daily production of 7,670 BOE/d, a 25% increase from the third quarter
of 1999 and a 664 BOE/d (9%) increase from the prior quarter of 2000. These
production increases were the result of the Company's active drilling program
and further improvements in the performance of its waterfloods. A total of 14
wells were drilled at Heidelberg in the third quarter of 2000, comprised of four
oil, nine gas and one water injection well. Year-to-date the Company has drilled
34 wells at Heidelberg, comprised of 14 oil, 11 gas and 9 water injection wells.
The production increases in Little Creek Field and King Bee Field are
attributable to the fact that these properties were acquired in the second and
third quarters of 1999, respectively, plus increases in the overall production
levels at these fields since they were acquired as a result of the Company's
development and exploitation work.
OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues increased 100%
from the third quarter of 1999 to 2000 and 113% between the first nine months of
1999 and 2000. These increases were primarily a result of 55% to 93% increases
in oil and natural gas prices as outlined below and the 20-25% increases in
production levels as discussed above, offset in part by the Company's losses on
its hedging activities, also outlined below. The Company's net realized unhedged
oil price of $27.20 per Bbl for the third quarter of 2000 was a 63% increase
over the prior year third quarter unhedged average oil price of $16.64 per Bbl.
The net realized unhedged oil price for the first nine months of 2000 increased
93% over the prior year nine month period's price. The Company's net realized
unhedged natural gas price of $4.59 per Mcf for the third quarter of 2000 was a
65% increase over the prior year quarter unhedged natural gas price of $2.79 per
Mcf. The Company's net unhedged natural gas price increased 55% when comparing
the nine month periods ended September 30.
The Company's oil hedging contracts, which were put in place in early 1999,
negatively impacted the Company's oil revenues by $3.7 million, or $2.63 per
Bbl, for the third quarter of 2000, and by $9.5 million, or $2.34 per Bbl, for
the first nine months of 2000. In the third quarter and first nine months of
1999, the Company's oil hedging losses were $3.5 million and $4.0 million, which
reduced the Company's average oil price during those periods by $3.01 per Bbl
and $1.28 per Bbl, respectively.
The Company recorded a loss on its natural gas hedging contracts, which
were put in place in 1998, of $3.8 million, or $1.34 per Mcf, in the third
quarter of 2000 and $5.7 million, or $0.70 per Mcf, in the first nine months of
2000. In the third quarter of 1999 the Company lost $600,000 on its gas hedges
($0.25 per Mcf), and for the nine months ended September 30, 1999, the Company
recorded hedging losses of approximately $80,000 ($0.01 per Mcf). The Company's
hedging activities are discussed in more detail in "Market Risk Management"
herein.
PRODUCTION EXPENSES: Production expenses increased by $3.9 million, or 50%,
between the third quarters of 1999 and 2000 and increased by $13.0 million, or
64%, between the first nine months of 1999 and 2000. Approximately $1.7 million
of the third quarter of 2000 increase and $5.9 million of the first nine months
of 2000 increase were due to the addition of the King Bee Field and Little Creek
Field (a tertiary oil recovery operation which has higher operating expenses
than the Company's average), which were acquired in the second and third
quarters of 1999, respectively. An additional $750,000 increase in the third
quarter of 2000 and $2.3 million increase in the first nine months of 2000 were
13
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
due to increased production taxes resulting from the increase in oil and natural
gas prices and increased production. The remaining increases of approximately
$1.5 million in the third quarter of 2000 and $4.8 million for the first nine
months of 2000 were due primarily to increased operating costs, primarily at
Heidelberg Field, resulting from higher costs associated with the expansion of
the water floods in 1999 and 2000, increased workover expenses and additional
wells added as a result of increased drilling activity during the last year.
General and Administrative Expenses
General and administrative ("G&A") expenses increased slightly as set forth
below:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------- -------------------------- ---------------------------
2000 1999 2000 1999
----------------------------------------------- ------------ ----------- ----------- -----------
<S> <C> <C> <C> <C>
G&A EXPENSES (THOUSANDS)
Gross expenses $ 6,152 $ 5,232 $ 18,164 $ 14,654
State franchise taxes 100 124 389 428
Operator overhead charges (3,385) (2,680) (9,982) (7,195)
Capitalized exploration expenses (807) (779) (2,347) (2,126)
------------ ----------- ----------- -----------
Net expenses $ 2,060 $ 1,897 $ 6,224 $ 5,761
------------ ----------- ----------- -----------
Average G&A cost per BOE $ 1.09 $ 1.21 $ 1.15 $ 1.31
Employees as of September 30 240 218 240 218
----------------------------------------------- ------------ ----------- ----------- -----------
</TABLE>
Gross G&A expenses increased $920,000, or 18%, between the third quarters
of 1999 and 2000 and $3.5 million, or 24%, between the first nine months of 1999
and 2000. The largest components of these increases were salaries, bonus
accruals, and other related employee costs, which accounted for approximately
$866,000 of the increase between the respective quarters and $3.0 million of the
increase between the respective nine month periods. The increased employee cost
was due to salary increases that were given for the first time in two years
(effective January 1, 2000) at an overall average increase of 7%, personnel
additions resulting primarily from the King Bee and Little Creek acquisitions in
the second and third quarters of 1999, and increased bonus accruals.
The increase in gross G&A expenses is offset in part by an increase in
operator overhead recovery charges and capitalized exploration costs in 2000.
The Company's well operating agreements allow the Company, when it is the
operator, to charge a well with a specified overhead rate during the drilling
phase and also charge a monthly fixed overhead rate for each producing well. As
a result of the additional operated wells acquired in the King Bee and Little
Creek Field acquisitions and the new wells added as a result of increased
drilling activity since the second quarter of 1999, the amount recovered by the
Company as operator overhead charges increased by 26% between the third quarters
of 1999 and 2000 and by 39% between the first nine months of 1999 and 2000.
Capitalized exploration costs increased proportionally between the comparable
periods in 1999 and 2000 along with the increase in gross G&A expenses. The net
effect of the increase in gross G&A expenses, operator overhead charges and
capitalized exploration costs was a 9% increase in net G&A expense between the
third quarters of 1999 and 2000 and an 8% increase in net G&A expense between
the first nine months of 1999 and 2000. However, as a result of the increases in
production, the net G&A cost per BOE decreased 10% between the respective third
quarters of 1999 and 2000 and 12% between the two nine month periods ended
September 30, 1999 and 2000.
14
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
Interest and Financing Expenses
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------------------- ---------------------------- --------------------------
AMOUNTS IN THOUSANDS EXCEPT PER BOE DATA 2000 1999 2000 1999
---------------------------------------------------- ------------- ----------- ------------ -----------
<S> <C> <C> <C> <C>
Interest expense $ 3,545 $ 3,492 $ 10,763 $ 12,170
Non-cash interest expense (234) (205) (690) (612)
------------- ----------- ------------ -----------
Cash interest expense 3,311 3,287 10,073 11,558
Interest and other income (696) (338) (1,626) (1,069)
------------- ----------- ------------ -----------
Net cash interest expense $ 2,615 $ 2,949 $ 8,447 $ 10,489
------------- ----------- ------------ -----------
Average net cash interest expense per BOE $ 1.38 $ 1.88 $ 1.56 $ 2.38
Average debt outstanding $ 148,418 $ 147,363 $ 151,115 $ 178,585
---------------------------------------------------- ------------- ----------- ------------ -----------
</TABLE>
Interest expense for the quarter ended September 30, 2000 increased
slightly (2%) compared to the prior year quarter and decreased 12% for the nine
months ended September 30, 2000 versus the comparable prior year nine month
period. These fluctuations are due primarily to the change in the average debt
outstanding during each of the periods and to a slight increase in interest
rates on the Company's floating rate bank debt during 2000.
In 1999 the Company began the year with $100.0 million of total bank debt
and increased that amount to $109.6 million by the end of the first quarter.
This debt was reduced in April 1999 by $100.0 million with the proceeds from the
sale of stock to Texas Pacific Group, but subsequently increased by $7.9
million, to $17.5 million, during the second quarter of 1999 and to $27.5
million in the third quarter to fund the acquisition of Little Creek Field.
Since that time the Company's bank borrowings remained at $27.5 million until
late June 2000, when the Company paid down $4.0 million of its outstanding bank
debt and then paid down an additional $2.5 million in September 2000, leaving
$21 million outstanding as of September 30, 2000. The Company's $125 million of
9% Senior Subordinated Notes Due 2008 was outstanding during both 1999 and 2000.
On a BOE basis, net cash interest expense decreased 27% between the third
quarter of 1999 and 2000 and 34% between the first nine months of 1999 and 2000
as a result of the production increases each quarter since the first quarter of
1999.
Depletion, Depreciation and Site Restoration
As of June 30, 2000, the engineering firm of DeGolyer and MacNaughton
prepared a reserve report on the Company's four largest fields using the same
unescalated price scenario used in the Company's December 31, 1999 SEC report.
These four fields as of December 31, 1999 comprised 78% of the Company's total
value on both a BOE and PV10 (estimated future net revenues discounted at 10%)
basis. Based on the results of this report, the Company's estimated proved
reserves for its four largest fields increased approximately 19.8 MMBOE since
December 31, 1999 (including the 2.2 MMBOE produced during the first six months
of 2000 from these fields). The Company has used the results of this report in
estimating the DD&A rate for the third quarter and first nine months of 2000,
which resulted in a reduction in the DD&A rate from $4.50 per BOE in the first
quarter of 2000 to $4.35 per BOE for the current quarter and first nine months
of 2000. In addition to the increase in reserves, the Company also factored into
the DD&A rate calculation the effect of transferring approximately $32.7 million
from unevaluated properties into the full cost pool and the increase in site
reclamation expense attributable to the purchase of offshore properties in the
Gulf of Mexico, both in the second quarter of 2000. The $4.35 per BOE rate for
the first nine months of 2000 is an increase from the $4.00 rate during the
first nine months of 1999 or the fiscal year 1999 rate of $4.17 due to
development costs which exceeded the DD&A rate in effect after the large full
cost pool writedowns in 1998. The Company's provision for well abandonment and
site reclamation is made net of anticipated salvage value and is included in
DD&A expense.
15
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------------- ---------------------------- ---------------------------
AMOUNTS IN THOUSANDS EXCEPT PER BOE DATA 2000 1999 2000 1999
----------------------------------------------------- ----------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
Depletion and depreciation $ 7,786 $ 6,480 $ 22,322 $ 16,955
Site restoration provision 160 37 417 181
Depreciation of other fixed assets 282 187 819 513
----------- ------------ ------------ ------------
Total DD&A $ 8,228 $ 6,704 $ 23,558 $ 17,649
----------- ------------ ------------ ------------
Average DD&A cost per BOE $ 4.35 $ 4.28 $ 4.35 $ 4.00
----------------------------------------------------- ----------- ------------ ------------ ------------
</TABLE>
Income Taxes
Based on the Company's pre-tax income of $19.1 million for the third
quarter and $44.3 million for the nine months ended September 30, 2000, an
income tax provision for these periods using an effective tax rate of 37% would
have resulted in a $7.1 million and a $16.4 million income tax provision for the
three and nine month periods ended September 30, 2000, respectively. As of
December 31, 1999, the Company had a fully reserved deferred tax asset of $95.1
million which is available to offset pre-tax income. As the deferred tax asset
is utilized, the Company makes a corresponding adjustment to its valuation
allowance, resulting in no net deferred tax income or expense. The Company
believes that the remaining deferred tax asset should continue to be fully
impaired at this time, based on projected future taxable income at oil and gas
pricing consistent with the Company's long range planning and anticipated levels
of capital spending, a portion of which are intangible drilling costs which may
be deducted for tax purposes in the year incurred. The Company's $81,000 current
provision for income taxes in the third quarter and $121,000 for the first nine
months of 2000 is for alternative minimum tax, based on projected taxable income
that may not be completely offset by net operating losses.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------- -------------------------- -------------------------
2000 1999 2000 1999
-------------------------------------------------------- ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C>
Income tax provision $ 81 $ - $ 121 $ -
Average income tax expense per BOE $ 0.04 - $ 0.02 -
Effective tax rate 0.4% - 0.3% -
-------------------------------------------------------- ------------ ------------ ----------- -----------
</TABLE>
Summary Operating and BOE Data
Primarily as a result of the increased production and product prices in the
third quarter and first nine months of 2000, net income and cash flow from
operations increased on both a gross and per share basis over the comparable
periods.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------- -------------------------- --------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS 2000 1999 2000 1999
-------------------------------------------------------- ------------ ------------ ----------- ------------
<S> <C> <C> <C> <C>
Net income (loss) $ 19,039 $ 2,404 $ 44,157 $ (133)
Net income (loss) per common share:
Basic $ 0.42 $ 0.05 $ 0.96 $ -
Diluted 0.41 0.05 0.96 -
Cash flow from operations (1) $ 27,502 $ 9,547 $ 68,404 $ 18,642
-------------------------------------------------------- ------------ ------------ ----------- ------------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
16
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
The following table summarizes the cash flow, DD&A and results of
operations on a BOE basis for the comparative periods. Each of the individual
components are discussed above.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- -----------------------
Per BOE Data 2000 1999 2000 1999
-------------------------------------------------------- ------------ ----------- --------- -----------
<S> <C> <C> <C> <C>
Oil and natural gas revenue $ 23.30 $ 14.06 $ 21.51 $ 12.38
Operating costs (5.15) (4.30) (5.15) (4.00)
Production taxes (1.09) (0.73) (0.99) (0.58)
-------------------------------------------------------- ------------ ----------- --------- -----------
Production netback 17.06 9.03 15.37 7.80
General and administrative (1.09) (1.21) (1.15) (1.31)
Net interest expense (1.38) (1.88) (1.56) (2.38)
Other (0.04) 0.15 (0.02) 0.12
-------------------------------------------------------- ------------ ----------- --------- -----------
Cash flow from operations(1) 14.55 6.09 12.64 4.23
DD&A (4.35) (4.28) (4.35) (4.00)
Other non-cash items (0.13) (0.28) (0.13) (0.26)
-------------------------------------------------------- ------------ ----------- --------- -----------
Net income (loss) $ 10.07 $ 1.53 $ 8.16 $ (0.03)
-------------------------------------------------------- ------------ ----------- --------- -----------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
Market Risk Management
The Company uses fixed and variable rate debt to partially finance budgeted
expenditures. These agreements expose the Company to market risk related to
changes in interest rates. The Company does not hold or issue derivative
financial instruments for trading purposes. The carrying and fair value of these
debt instruments have not changed materially since year-end.
The Company also enters into various financial contracts to hedge its
exposure to commodity price risk associated with anticipated future oil and
natural gas production. The Company has a contract on its oil production that
hedges 3,000 Bbls/d with a price floor of $14.00 per Bbl and a price ceiling of
$18.05 per Bbl. This contract has been in effect since April 1999, expires as of
December 31, 2000, and hedges approximately 19% of the Company's oil production
based on the Company's third quarter of 2000 average oil production. The Company
also has a contract that hedges 24 million cubic feet of natural gas per day
with a price floor of $1.90 per MMBtu and a price ceiling of $2.58 per MMBtu.
This contract has been in effect since 1998, expires as of December 31, 2000,
and hedges approximately 78% of the Company's natural gas production based on
the Company's third quarter of 2000 average natural gas production. During the
third quarter of 2000 the Company paid approximately $3.7 million on the oil
hedge contract, which reduced the net average realized price by $2.63 per Bbl,
and paid approximately $3.8 million on the natural gas hedge contract, which
reduced the net realized price by $1.34 per Mcf. Through the first nine months
of 2000 the Company paid approximately $9.5 million on the oil hedge contract
and $5.7 million on the natural gas hedge contract, which reduced the Company's
net average realized price for oil and natural gas by $2.34 per Bbl and $0.70
per Mcf. During the three and nine month periods ended September 30, 1999, the
Company paid $3.5 million and $4.0 million on its oil hedge contract, which
reduced the Company's average oil price by $3.01 and $1.28 respectively. During
the three and nine month periods ended September 30, 1999, the Company paid
$619,000 and $80,000 on its gas hedge contracts, which reduced the Company's
average gas price by $0.25 and $0.01, respectively.
Gain or loss on these derivative commodity contracts would be offset by a
corresponding gain or loss on the hedged commodity positions. Based on futures
market prices at September 30, 2000, the Company would expect to pay
approximately $3.5 million on the oil hedge contract and $5.9 million on the
natural gas hedge contract through their expiration at the end of 2000. If the
futures market prices were to increase 10% from those in effect at September 30,
17
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (cont.)
2000, the Company would be required to make additional cash payments under the
oil contract of approximately $846,000 and additional payments under the natural
gas contract of $1.2 million. If the futures market prices were to decline 10%
from those in effect as September 30, 2000, the Company would reduce cash
payments under the oil contract by approximately $846,000 and reduce the
payments due under the natural gas contract by $1.2 million.
For the years 2001 and 2002 the Company has acquired puts or floors to
hedge a portion of its anticipated oil and natural gas production. For 2001, the
Company acquired a $22.00 floor on 12,800 Bbls/d and a $2.80 floor on 37.5
MMBtu/d for an aggregate cost of $2.6 million, which together cover
approximately 75% of its anticipated production, before the addition of the
Recent Acquisitions. At the time of signing the purchase and sale agreements on
the Recent Acquisitions, the Company purchased puts or floors on the anticipated
proven natural gas production from these properties during 2001 and 2002. The
floors relating to the Recent Acquisitions cost a total of approximately $2.5
million and have varying volume and price floors each quarter for 2001 and 2002.
The price floor ranges from $2.94 to $4.25 for 2001 and from $2.93 to $3.65 for
2002, with a weighted average price of $3.51 for 2001 and $3.23 for 2002. The
volumes on the floors also vary by quarter and range from 18.3 MMBtu/d to 26.6
MMBtu/d for 2001 and from 4.6 MMBtu/d and 12.0 MMBtu/d for 2002, with a weighted
average volume of 23.0 MMBtu/d for 2001 and 7.8 MMBtu/d for 2002.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement
establishes accounting and reporting standards for derivative instruments and
hedging activities. It requires the recognition of all derivatives as either
assets or liabilities in the statement of financial position and measurement of
these instruments at fair value. The Company is required to adopt this statement
in the first quarter of 2001.
The process relating to implementation of SFAS No. 133 is ongoing. To date,
all derivatives within the company have been identified. The Company is in the
process of designating, documenting and assessing hedging relationships. The
Company's derivatives are expected to result in cash flow hedges, which require
the Company to record the derivative assets or liabilities at fair value in the
statement of financial position with an offset in Other Comprehensive Income to
the extent the hedge is effective. Hedge ineffectiveness will be recorded in
earnings.
The Company continues to evaluate the impact of SFAS No. 133, as well as
the ongoing implementation issues currently being addressed by the Derivatives
Implementation Group. As a result, the direct financial impact of the
application of hedge accounting and the transition adjustment on the Company's
financial position and results of operations has yet to be determined.
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q ("Quarterly
Report") that are not historical facts, including, but not limited to,
statements found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, acquisition plans and proposals and dispositions, development
activities, cost savings, production efforts and volumes, hydrocarbon reserves,
hydrocarbon prices, liquidity, regulatory matters and competition. Such
forward-looking statements generally are accompanied by words such as "plan,"
"estimate," "budgeted," "expect," "predict," "anticipate," "projected,"
"should," "assume," "believe" or other words that convey the uncertainty of
future events or outcomes. Such forward-looking information is based upon
management's current plans, expectations, estimates and assumptions and is
subject to a number of risks
18
<PAGE>
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: volatility of
the prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital, general economic and market
conditions and the effect of such on operating expenses, competition and
government regulations, as well as the risks and uncertainties discussed in this
Quarterly Report, including, without limitation, the portions referenced above,
and the uncertainties set forth from time to time in the Company's other public
reports, filings and public statements.
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.
19
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K DURING THE THIRD QUARTER OF 2000
--------------------------------------------------------------------------
EXHIBITS:
---------
10* Second Amended and Restated Credit Agreement, dated October
13, 2000, between the Company and Bank of America, N.A., as
Administrative Agent, and the financial institutions listed
on Schedule 2.1 therein.
15* Letter from Independent Accountants as to unaudited interim
financial information.
27* Financial Data Schedule (EDGAR version only).
* Filed herewith.
REPORTS ON FORM 8-K:
--------------------
(i) On October 10, 2000, the Company filed a Current Report on
Form 8-K that reported under Item 5, "Other Events," that Ms.
Carrie Wheeler had been elected to the Company's Board of
Directors to fill the vacancy created by the resignation of
Mr. David Stanton.
(ii) On October 27, 2000, the Company filed a Current Report on
Form 8-K that reported under Item 2, "Acquisition or
Disposition of Assets," that the Company had purchased or had
signed purchase and sale agreements for the purchase of $66.5
million of oil and natural gas properties located in southwest
Louisiana.
20
<PAGE>
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
Chief Financial Officer
By: /s/ Mark C. Allen
-------------------------------------
Mark C. Allen
Chief Accounting Officer & Controller
Date: November 14, 2000
21
