UNITED STATES
SECURITIES AND EXCHA NGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
----------------------
(Mark One)
X Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 1999
Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 33-93722
---------------------------
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 75-2815171
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal (Zip code)
executive offices)
Registrant's telephone number, including area code:(972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No___
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at July 31, 1999
----- ----------------------------
Common Stock, $.001 par value 45,586,544
DENBURY RESOURCES INC.
INDEX
Part I. Financial Information
- ------------------------------
Page
----
Item 1. Financial Statements
Condensed Consolidated Balance Sheets at June 30, 1999
(Unaudited) and December 31, 1998 3
Condensed Consolidated Statements of Operations for the
Three and Six Months ended June 30, 1999
and 1998 (Unaudited) 4
Condensed Consolidated Statements of Cash Flows for the
Six Months ended June 30, 1999 and 1998 (Unaudited) 5
Notes to Condensed Consolidated Financial Statements 6-8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 9-20
Item 3. Quantitative and Qualitative Disclosures about Market 20sk
Part II. Other Information
- ---------------------------
Item 4. Submission of Matters to a Vote of Security Holders 21
Item 6. Exhibits and Reports on Form 8-K 21
Signatures 22
2
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of U.S. dollars except share amounts)
June 30, December 31,
1999 1998
--------- ---------
(Unaudited)
Assets
Current assets
Cash and cash equivalents $ 8,049 $ 2,049
Accrued production receivable 7,435 5,495
Trade and other receivables 10,576 16,390
--------- ----------
Total current assets 26,060 23,934
--------- ----------
Property and equipment (using full cost accounting)
Oil and gas properties 543,773 508,571
Unevaluated oil and gas properties 49,833 65,645
Less accumulated depreciation and depletion (404,027) (393,552)
--------- ----------
Net property and equipment 189,579 180,664
--------- ----------
Other assets 9,117 8,261
--------- ----------
Total assets $ 224,756 $ 212,859
========= ==========
Liabilities and Stockholders' Equity (Deficit)
Current liabilities
Accounts payable and accrued liabilities $ 9,584 $ 13,570
Oil and gas production payable 6,030 5,118
--------- ----------
Total current liabilities 15,614 18,688
--------- ----------
Long-term liabilities
Long-term debt 142,500 225,000
Provision for site reclamation costs 1,581 1,436
Other liabilities 280 -
--------- ----------
Total long-term liabilities 144,361 226,436
--------- ----------
Stockholders' equity (deficit)
Preferred stock, $.001 par value, 25,000,000
shares authorized; none issued and outstanding - -
Common stock, $.001 par value, 100,000,000
shares authorized; 45,586,544 and 26,801,680
shares issued and outstanding at June 30,
1999 and December 31, 1998, respectively 46 27
Paid-in capital in excess of par 327,333 227,769
Accumulated deficit (262,598) (260,061)
--------- ----------
Total stockholders' equity (deficit) 64,781 (32,265)
--------- ----------
Total liabilities and stockholders'
equity (deficit) $ 224,756 $ 212,859
========= ==========
(See accompanying notes to Condensed Consolidated Financial Statements)
3
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
(Unaudited - U.S. dollars)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1999 1998 1999 1998
--------- -------- -------- --------
Revenues
Oil, gas and related product
sales $ 17,858 $ 22,508 $ 32,561 $ 47,696
Interest and other income 370 375 731 742
--------- -------- -------- ---------
Total revenues 18,228 22,883 33,292 48,438
--------- -------- -------- ---------
Expenses
Production 6,487 8,109 12,342 15,963
General and administrative 1,669 1,677 3,560 3,453
Interest 3,820 3,978 8,678 8,369
Depletion and depreciation 5,610 16,071 10,945 28,458
Franchise taxes 150 232 304 432
Writedown of oil and gas
properties - 165,000 - 165,000
--------- -------- -------- ---------
Total expenses 17,736 195,067 35,829 221,675
--------- -------- -------- ---------
Income (loss) before income taxes 492 (172,184) (2,537) (173,237)
Income tax benefit - 50,245 - 50,618
--------- -------- -------- ---------
Net income (loss) $ 492 $(121,939) $ (2,537 $(122,619)
========= ========= ======== =========
Net income (loss) per common share
Basic $ 0.01 $ (4.57) $ (0.07) $ (4.89)
Diluted 0.01 (4.57) (0.07) (4.89)
Average number of common shares
outstanding
Basic 41,407 26,690 34,145 25,066
Diluted 41,475 26,690 34,145 25,066
(See accompanying notes to Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of U.S. dollars)
(Unaudited)
Six Months Ended
June 30,
-----------------------
1999 1998
--------- --------
Cash flow from operating activities:
Net loss $ (2,537) $(122,619)
Adjustments needed to reconcile to net cash flow
provided by operations:
Depreciation, depletion and amortization 10,945 28,458
Writedown of oil and natural gas properties - 165,000
Deferred income taxes - (50,618)
Other 687 286
--------- --------
9,095 20,507
Changes in working capital items relating
to operations:
Accrued production receivable (1,940) 283
Trade and other receivables 5,814 3,868
Other assets (342) -
Accounts payable and accrued liabilities (3,986) 5,567
Oil and gas production payable 912 605
--------- --------
Net cash flow provided by operations 9,553 30,830
--------- --------
Cash flow used for investing activities:
Oil and natural gas expenditures (12,797) (63,049)
Acquisition of oil and natural gas properties (6,593) (13,204)
Net purchases of other assets (759) (556)
--------- --------
Net cash used for investing activities (20,149) (76,809)
--------- --------
Cash flow from financing activities:
Bank repayments (100,000) (200,000)
Bank borrowings 17,500 30,000
Issuance of senior subordinated debt - 125,000
Issuance of common stock 99,583 94,157
Costs of debt financing - (3,402)
Other (487) (23)
--------- --------
Net cash provided by financing activities 16,596 45,732
--------- --------
Net increase (decrease) in cash and cash equivalents 6,000 (247)
Cash and cash equivalents at beginning of period 2,049 9,326
--------- --------
Cash and cash equivalents at end of period $ 8,049 $ 9,079
========= ========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 9,409 $ 4,178
--------- --------
(See accompanying notes to Condensed Consolidated Financial Statements)
5
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. 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, 1998. 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.
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 June 30, 1999 and the
consolidated results of its operations for the three and six months ended June
30, 1999 and 1998 and its cash flow for the six months ended June 30, 1999 and
1998.
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 six month periods ended
June 30, 1999 and 1998, 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 six
month periods ended June 30, 1999 and 1998 (in thousands).
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -----------------
1999 1998 1999 1998
-------- -------- ------- --------
Weighted average common
shares - basic 41,407 26,690 34,145 25,066
Potentially dilutive
securities:
Stock options 68 - - -
Stock warrants - - - -
-------- -------- ------- --------
Weighted average common
shares - diluted 41,475 26,690 34,145 25,066
======== ======== ======= ========
Due to the losses incurred by the Company for the six months ended June 30,
1999, and for the three and six months ended June 30, 1998, any dilutive effect
from stock options and stock warrants would be antidilutive to the calculation
of diluted net income (loss) per common share and therefore are not included for
those periods.
6
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
June 30, December 31,
1999 1998
--------- ---------
(Amounts in thousands)
(Unaudited)
9% Senior Subordinated Notes Due 2008 $ 125,000 $ 125,000
Senior bank loan 17,500 100,000
--------- ---------
Total long-term debt $ 142,500 $ 225,000
========= =========
4. CHANGE TO UNITED STATES GAAP; DIFFERENCES IN GAAP BETWEEN UNITED STATES AND
CANADA
In April 1999, the Company moved its corporate domicile from Canada to the
United States as a Delaware corporation (see Note 5). As a result of this move,
the consolidated financial statements for all periods have been prepared in
accordance with United States GAAP rather than Canadian GAAP. For the periods
presented herein, there are not any differences between United States and
Canadian GAAP. Historically, the Company has had differences between the two
accounting methods in the areas of diluted earnings per share, the handling of
losses on the early extinguishment of debt and the guidelines regarding full
cost ceiling tests.
5. 1999 SALE OF EQUITY AND MOVE OF DOMICILE
At a special meeting of the stockholders held on April 20, 1999, the
stockholders approved (i) a move of the Corporate's domicile from Canada to the
United States as a Delaware corporation, (ii) the sale of 18,552,876 common
shares to an affiliate of the Texas Pacific Group ("TPG") for $100 million or
$5.39 per share, and (iii) increases in the number of shares available for
issuance under the Company's stock purchase and stock option plans. The move of
domicile was completed on April 21, 1999, and along with the move, the Company's
wholly-owned subsidiary, Denbury Management Inc. ("DMI"), was merged into the
new Delaware parent company, Denbury Resources Inc. This move of domicile did
not have any effect on the operations and assets of the Company, and as part of
the move and merger, Denbury Resources Inc. expressly assumed any and all
liabilities of its subsidiary, DMI, including DMI's obligation for the 9% Senior
Subordinated Notes due 2008 and DMI's outstanding bank credit facility. The
December 31, 1998 year-end balance sheet included herein has been modified to
reflect the capital structure of the Company after the move of domiciles even
though this transaction occurred after the balance sheet date.
The sale of common stock to TPG was also completed on April 21, 1999. As a
result of this equity transaction, TPG's pro-rata ownership of the outstanding
common stock of the Company increased from 32% to 60%. The Company intends to
use the proceeds from the equity sale for acquisitions, although in the interim,
the funds were used to reduce its outstanding bank debt.
6. PRODUCT PRICE HEDGING CONTRACTS
During June and July 1998, the Company entered into two no-cost financial
contracts ("collars") to hedge a total of 40 million cubic feet of natural gas
per day ("MMcf/d"). The Company collected $539,000 on these financial contracts,
which have now expired, during the first quarter of 1999. During December 1998,
the Company extended these natural gas hedges through December 2000 by entering
into an additional no-cost collar with a floor price of $1.90 per MMBtu and a
ceiling price of $2.58 per MMBtu for the period of July 1999 through December
2000. This contract
7
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
hedges 25 MMcf/d for the months of July and August 1999 and 30 MMcf/d for each
month thereafter. This contract covers over 100% of the Company's current net
natural gas production. Based on the futures market prices at June 30, 1999, the
Company would expect to pay approximately $422,000 on these commodity contracts
during the remaining term because certain futures market prices at June 30, 1999
exceeded the ceiling on the contract collars.
During the fourth quarter of 1998, the Company also modified certain of its
oil sales contracts. The new contracts, which are generally for a period of
eighteen months, provide that approximately 45% of the Company's oil production
as of January 31, 1999, has a price floor of between $8.00 and $10.00 per Bbl.
This equates to a NYMEX oil price of between $15.00 and $16.00 per Bbl. As
compensation for the price floors, the contracts provide that the premiums
received on the posted prices decrease as oil prices rise.
During March and April 1999, the Company entered into two collars to hedge
a portion of its oil production. The first contract was a fixed price swap for
3,000 Bbls/d for the period of April through December, 1999 at a price of $14.24
per Bbl. The second contract was a collar to hedge 3,000 Bbls/d for the period
of May, 1999 through December, 2000 with a floor price of $14.00 per Bbl and a
ceiling price of $18.05 per Bbl. The Company paid approximately $540,000 on
these contracts during the second quarter, which lowered the effective net oil
price received by the Company during that quarter by $0.51 per barrel. When
combined with the amount received on the gas contracts, the Company paid a net
amount of $1,000 during the first six months of 1999 on its commodity hedges.
These two oil financial contracts hedge approximately 50% of the Company's
current oil production. Based on the futures market prices at June 30, 1999, the
Company would expect to pay approximately $3.5 million over the remaining terms
of the oil hedge contracts. For further discussion regarding the Company's
derivative financial instruments, see "Market Risk Management" in Management's
Discussion and Analysis of Financial Condition and Results of Operations.
8
DENBURY RESOURCES INC.
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,
1998, along with Management's Discussion and Analysis 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 an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. The Company's growth in proved reserves,
production and cash flow over the years has been achieved by concentrating on
the acquisition of properties which it believes have significant upside
potential and through the efficient development, enhancement and operation of
those properties.
RECENT 1999 EVENTS
1999 SALE OF EQUITY AND MOVE OF DOMICILE. At a special meeting of the
stockholders held on April 20, 1999, the stockholders approved (i) a move of the
Corporate's domicile from Canada to the United States as a Delaware corporation,
(ii) the sale of 18,552,876 common shares to an affiliate of the Texas Pacific
Group ("TPG") for $100 million or $5.39 per share, and (iii) increases in the
number of shares available for issuance under the Company's stock purchase and
stock option plans. The move of domicile was completed April 21, 1999, and along
with the move, the Company's wholly-owned subsidiary, Denbury Management Inc.
("DMI"), was merged into the new Delaware parent company, Denbury Resources Inc.
This move of domicile did not have any effect on the operations and assets of
the Company, and as part of the move and merger, Denbury Resources Inc.
expressly assumed any and all liabilities of its subsidiary, DMI, including
DMI's obligation for the 9% Senior Subordinated Notes due 2008 and DMI's
outstanding bank credit facility.
The sale of common stock to TPG was also completed on April 21, 1999. As a
result of this transaction, TPG's pro-rata ownership of the outstanding common
stock of the Company increased from 32% to 60%. The Company had approximately
45.6 million common shares outstanding as of June 30, 1999. The Company intends
to use the proceeds from the TPG equity sale for acquisitions, although in the
interim, the funds were used to reduce its outstanding bank debt.
FEBRUARY 1999 AMENDMENT TO BANK CREDIT FACILITY. On February 19, 1999, the
Company completed an amendment to its credit facility with Bank of America, as
agent for a group of eight other banks. This amendment set the borrowing base at
$110 million, of which $60 million was considered by the banks to be within
their normal credit guidelines. The credit facility continues with its other
restrictions, such as a prohibition on the payment of dividends and a
prohibition on most debt, liens and corporate guarantees. This amendment:
o provided certain relief on the minimum equity and interest coverage
tests;
o changed the facility to one secured by substantially all of the
Company's oil and natural gas properties;
o requires that as long as the borrowing base is larger than a borrowing
base that conforms to normal credit guidelines (currently $60 million),
that at least 75% of the funds borrowed subsequent to the closing of
the TPG purchase must be used for either qualifying acquisitions or
capital expenditures made to maintain, enhance or develop its proved
reserves; and
o increased the interest rate to a range from LIBOR plus 1.0% to LIBOR
plus 1.75% (depending on the amounts outstanding) and LIBOR plus 2.125%
if the outstanding debt exceeds the borrowing base under normal credit
guidelines, currently set at $60 million.
9
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
After the repayment of the credit facility in April, 1999, with the
proceeds from the sale of common stock to TPG, there was approximately $9.6
million outstanding on the facility ($17.5 million as of June 30, 1999), leaving
a total borrowing capacity at that time of approximately $100 million ($92.5
million as of June 30, 1999). The next scheduled re-determination of the
borrowing base will be as of October 1, 1999, based on June 30, 1999 assets and
proved reserves. 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 1999, the current level of debt and several other
factors, some of which are beyond the Company's control.
CAPITAL RESOURCES AND LIQUIDITY
As a result of depressed oil prices in 1998 which continued into the first
part of 1999, the Company's cash flow and results of operations were
significantly adversely effected during 1998 and the first quarter of 1999. This
reduction in cash flow also contributed to an increase in the Company's debt
levels, which as a multiple of cash flow, were at historic highs as of March 31,
1999. Because of the downturn in the oil and gas industry during 1998, resulting
from the decreases in oil and natural gas prices, the Company sought additional
capital in order to have funds to pursue acquisitions, and in December 1998
entered into an agreement to sell $100 million of common shares to TPG. This
sale of equity was approved by stockholders on April 20, 1999 and closed on
April 21, 1999 (see "1999 Sale of Equity and Move of Domicile" above).
As a result of the equity infusion, the Company's bank debt was reduced to
$17.5 million outstanding as of June 30, 1999 and the Company's stockholders'
deficit was eliminated. As of June 30, 1999, the Company had positive
stockholders equity of $64.8 million. In addition, oil prices have climbed from
a first quarter average NYMEX price of approximately $13.00 per Bbl to a second
quarter of 1999 average of approximately $17.65 per Bbl, and have further
increased to levels above $21.00 per Bbl in early August 1999. Both the improved
product prices and the reduction of debt had a positive impact on the Company's
earnings and cash flow for the second quarter of 1999 and will continue to
impact future periods. These prices will allow the Company to pursue oil
development opportunities that were uneconomical at the low oil prices which
prevailed in the second half of 1998 and first quarter of 1999. However, there
can be no assurance that the recent increase in oil prices will be sustained.
In addition, with the funds made available by the equity sale to TPG, the
Company intends to pursue oil and gas acquisitions which, if accomplished,
should also be accretive to the Company's operating results. However, there can
be no assurance that suitable acquisitions will be identified in the future or
that any such acquisitions will be successful in achieving desired profitability
objectives. Without suitable acquisitions or the capital to fund such
acquisitions, the Company's future growth could be limited or even eliminated.
The Company's current development budget for 1999 remains at $35 million,
although the Company is considering increasing the fourth quarter budget
slightly due to the improved product prices, if these price increases hold.
However, the general intent is to minimize the use of the bank credit facility
for anything other than acquisitions. 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 developmental work
and other factors, the Company does not expect its 1999 development spending to
cause debt to increase substantially. The Company also expects that this
spending level should be sufficient to cause a slight increase in production
levels throughout the year. Furthermore, if acquisitions are unavailable at
attractive rates, the Company does have an inventory of potential development
projects that it could commence, subject to the availability and allocation of
capital resources.
10
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
SOURCES AND USES OF FUNDS
During the first half of 1999, the Company spent approximately $12.6
million on exploration and development expenditures and approximately $6.8
million on acquisitions. The exploration and development expenditures included
approximately $5.6 million spent on drilling, $2.9 million on geological,
geophysical and acreage expenditures and $4.1 million on workover costs. These
expenditures were funded by bank debt and cash flow from operations.
In contrast, during the first half of 1998 the Company spent approximately
$63.1 million on oil and natural gas development expenditures and approximately
$13.2 million on acquisitions. The development expenditures included
approximately $38.0 million spent on drilling, $14.1 million on geological,
geophysical and acreage expenditures and $11.0 million spent on workover costs.
These expenditures were funded by cash flow from operations and bank debt.
RESULTS OF OPERATIONS
Operating Income
Production volumes were lower on a BOE basis during both the three and six
month periods ended June 30, 1999 when compared to the corresponding periods in
1998. These declines in production are generally the result of the curtailment
in spending during the last half of 1998 after the decline in oil prices.
Correspondingly, operating income was also less during the 1999 periods than the
corresponding 1998 periods. These statistics and other data are set forth in the
following chart.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------- -------------------- ------------------
1999 1998 1999 1998
- --------------------------------- -------- -------- -------- --------
OPERATING INCOME (THOUSANDS)
Oil sales $ 12,444 $ 14,655 $ 20,976 $ 30,828
Natural gas sales 5,414 7,853 11,585 16,868
Less production expenses (6,487) (8,109) (12,342) (15,963)
-------- -------- -------- --------
Operating income $ 11,371 $ 14,399 $ 20,219 $ 31,733
-------- -------- -------- --------
UNIT PRICES
Oil price per barrel ("Bbl") $ 11.85 $ 10.29 $ 10.62 $ 11.21
Gas price per thousand cubic
feet ("Mcf") 2.22 2.29 2.22 2.39
NETBACK PER BOE (1):
Sales price $ 12.26 $ 11.28 $ 11.44 $ 12.15
Production expenses (4.45) (4.06) (4.34) (4.07)
-------- -------- -------- --------
Production netback $ 7.81 $ 7.22 $ 7.10 $ 8.08
-------- -------- -------- --------
AVERAGE DAILY PRODUCTION VOLUME:
Bbls 11,541 15,649 10,914 15,191
Mcf 26,828 37,665 28,812 38,963
BOE 16,013 21,927 15,716 21,685
- --------------------------------- --------- -------- -------- --------
<FN>
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
</FN>
11
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Production for the second quarter of 1999 averaged 16,013 BOE/d, an
increase of 4% from the first quarter of 1999, but a decline from the Company's
peak production level during the second quarter of 1998 (21,927 BOE/d), after
which spending was curtailed due to the low oil prices. However, with the recent
response from the Company's East waterflood unit at Heidelberg, the production
in recent months has began to increase, even though development spending for the
first half of 1999 was limited to $12.6 million, the lowest level of development
spending in the last few years. Activity on the East waterflood unit commenced
in early 1998 and production has increased from approximately 250 Bbls/d in the
summer of 1998 to approximately 1,675 Bbls/d for the month of June, 1999. The
majority of the Company's planned 1999 development activities relate to
facilities and workovers with a substantial portion of these funds to be spent
on the waterflood units at Heidelberg Field, including the planned initiation of
two more waterfloods late in 1999. Drilling activities make up approximately 20%
of the current 1999 budget. Production for the second quarter of 1999 was also
impacted by the $4.9 million acquisition of the King Bee Field in Mississippi in
late April, which added approximately 650 BOE/d of average daily production for
the months of May and June, 1999.
Production during the second quarter of 1999 from the Company's two key
prior acquisitions, the properties acquired from Amerada Hess in 1996 and from
Chevron in 1997, averaged 4,081and 5,626 BOE/d respectively. This compares to
9,730 and 3,575 BOE/d for the second quarter of 1998 on these properties and
4,544 and 4,541 BOE/d for the first quarter of 1999. The production from the
Chevron properties (Heidelberg Field) represents the sixth consecutive quarterly
increase since its purchase in late 1997. However, the Amerada Hess properties
peaked in the second quarter of 1998 at 9,730 BOE/d and have declined since that
time due to production declines on horizontal oil wells drilled at Eucutta Field
in late 1997 and early 1998 and the lack of subsequent development work to
replace this production.
Oil and gas revenue for the three and six month periods ended June 30, 1999
decreased primarily as a result of the decrease in production. Oil prices were
also 5% lower in 1999 when comparing the six month periods, but showed a 15%
improvement in 1999 when comparing the second quarter periods. In general, oil
prices gradually declined throughout the first half of 1998 and did not begin to
recover until late in the first quarter of 1999. In contrast, prices generally
improved throughout the second quarter of 1999 and have reached levels in early
August of over $21.00 per Bbl. Although the comparison between the first and
second quarters of 1998 and 1999 do not show significant changes, the trend in
oil prices during the first half of each year is remarkably different. Included
in the net oil price for the second quarter of 1999 is a $540,000 loss on oil
hedges during the period, which lowered the net realized price by $0.51 per Bbl.
The net average realized gas price was relatively consistent between the
comparable periods in 1998 and 1999, ranging from a low of $2.22 per Mcf to a
high of $2.39 as outlined in the above table. Included in the gas revenue for
the first quarter of 1999 was $523,000 related to a settlement of a gas
imbalance and $539,000 relating to a gain on the Company's natural gas hedge
contracts. These two items caused the average natural gas price per Mcf to
increase by $.20 per Mcf for the first six months of 1999.
Production and operating expenses decreased 20% between the second quarter
of 1998 and 1999 and 23% between the comparable six month periods as a result of
cost savings measures and an overall decline in production. On a BOE basis,
operating expenses increased due to the declines in production. For the
properties acquired from Amerada Hess, the operating expenses declined from the
1996 level of $5.35 per BOE to $3.39 per BOE for 1998, but increased to $4.27
for the first six months of 1999 as a result of the production declines.
Operating expense per BOE on the properties acquired from Chevron continued to
decrease from their initial level of $6.38 per BOE when acquired in late 1997 to
an average of $5.04 per BOE during 1998 and to an average of $4.86 per BOE for
the first six months of 1999.
12
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
These reductions result from general cost saving measures and increased
productivity per well through overall production increases at Heidelberg.
General and Administrative Expenses
General and administrative ("G&A") expenses decreased slightly as set forth
below:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------- ------------------ -------------------
1999 1998 1999 1998
- -------------------------------- -------- -------- -------- --------
NET G&A EXPENSES (THOUSANDS)
Gross expenses $ 4,633 $ 4,848 $ 9,422 $ 9,750
State franchise taxes 150 232 304 432
Operator overhead charges (2,348) (2,444) (4,515) (4,919)
Capitalized exploration
expenses (616) (727) (1,347) (1,378)
-------- -------- -------- --------
Net expenses $ 1,819 $ 1,909 $ 3,864 $ 3,885
-------- -------- -------- --------
Average G&A cost per BOE $ 1.25 $ 0.96 $ 1.36 $ 0.99
Employees as of June 30 201 202 201 202
- -------------------------------- -------- -------- -------- --------
Gross G&A expenses decreased 4% between the second quarter of 1998 and 1999
and 3% between the first six months of 1998 and 1999. The largest component of
this decrease was the elimination of a bonus accrual in 1999 which was
approximately $375,000 per quarter during the first half of 1998 (no bonus
accrual was made during the last half of 1998), partially offset by
approximately $200,000 of additional non-recurring expenses incurred during the
first six months of 1999 as part of the cost of the move of domicile from Canada
to the United States (see "1999 Sale of Equity and Move of Domicile") and
$142,000 of increased rent expense as a result of increased space and the
expiration of an old lease which had below market rates.
The net G&A is also affected by the amount of overhead charged during the
period. The respective 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 to also charge a monthly fixed overhead rate for each
producing well. As a result of the decreased drilling activity in the first and
second quarters of 1999 as compared to the same periods in 1998, gross G&A
recovered through these types of charges (listed in the above table as "Operator
overhead charges") was lower in the two 1999 periods than in 1998. During the
second quarter of 1998, approximately $2.4 million of gross G&A was recovered by
operator overhead charges, while during the second quarter of 1999 this recovery
was reduced slightly to $2.3 million. Correspondingly, during the first six
months of 1998, approximately $4.9 million of gross G&A was recovered by
operator overhead charges, while during the first six months of 1999 this
recovery was reduced to $4.5 million. Consequently, net G&A expense decreased
slightly during the applicable periods of 1999 as compared to 1998. On a BOE
basis, G&A costs increased 30% from the second quarter of 1998 to the comparable
quarter in 1999 and increased 37% from the first half of 1998 to the first half
of 1999, primarily because of decreased production on both an absolute and per
well basis.
13
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Interest and Financing Expenses
Three Months Ended Six Months Ended
June 30, June 30,
- ------------------------------------ ------------------- ------------------
AMOUNTS IN THOUSANDS EXCEPT PER BOE 1999 1998 1999 1998
- ------------------------------------ -------- -------- --------- --------
Interest expense $ 3,820 $ 3,978 $ 8,678 $ 8,369
Non-cash interest expense (216) (164) (407) (285)
--------- --------- --------- --------
Cash interest expense 3,604 3,814 8,271 8,084
Interest and other income (370) (375) (731) (742)
--------- --------- --------- --------
Net interest expense $ 3,234 $ 3,439 $ 7,540 $ 7,342
--------- --------- --------- --------
Average net interest expense per BOE $ 2.22 $ 1.72 $ 2.65 $ 1.87
Average debt outstanding $ 159,976 $ 179,844 $ 194,761 $195,673
- ------------------------------------ --------- --------- --------- ---------
In December 1997, the Company borrowed $202 million to fund the Chevron
Acquisition, resulting in $240 million of outstanding bank debt during January
and most of February 1998. On February 26, 1998 this debt was refinanced with
proceeds from the issuance of equity and subordinated notes, leaving a bank
balance of $40 million for the rest of the first quarter of 1998, plus $125
million of debt from the issuance of the subordinated notes. Borrowing increased
by $30 million during the second quarter of 1998 to fund $49.8 million of
capital expenditures.
In 1999, the Company began the year with $225 million of total debt and
further increased this to $234.6 million by the end of the first quarter.
Furthermore, the bank amendment in February 1999 (see "February 1999 Amendment
to Bank Credit Facility") resulted in higher bank interest rates, as the margins
over LIBOR rates were increased at that time. This debt was reduced in April
1999 by $100 million with the proceeds from the TPG equity infusion (see "1999
Sale of Equity and Move of Domicile" above), although an additional $7.9 million
was borrowed during the remainder of the second quarter, primarily to fund
acquisitions. The net result was a lower average level of debt in the second
quarter of 1999 as compared to the second quarter of 1998, but an almost
identical level of average overall debt when comparing the two six months
periods. The net effect on interest expense was a decrease of 4% when comparing
the second quarters of 1999 and 1998, but an increase of 4% when comparing the
two six month periods, although interest on a BOE basis increased for both 1999
periods as a result of the overall decline in production.
Depletion, Depreciation and Site Restoration
The Company's depletion, depreciation and amortization ("DD&A") rate
dropped from $8.05 per BOE for the second quarter of 1998 and $7.25 for the
first six months of 1998 to an average rate of $3.85 per BOE for the two
comparable periods in 1999. This resulted from an increase in the proved reserve
quantities since December 31, 1998 related to improved oil prices during 1999
and the reduced oil and gas property basis after the second quarter and year-end
1998 full cost pool writedowns.
Under full cost accounting rules, each quarter the Company is required to
perform a ceiling test calculation. In determining the limitation on property
carrying values, U.S. accounting rules require the discounting of estimated
future net revenues from its proved reserves at 10% using constant current
prices following the guidelines of the Securities and Exchange Commission
("SEC"). Due to the higher product prices in 1999, the Company did not have any
ceiling
14
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
test limitations at either March 31, 1999 or June 30, 1999. However, at the end
of the second quarter of 1998, the Company incurred a $165 million writedown of
oil and natural gas properties, primarily due to the decline in oil prices
during the first half of 1998.
The Company also provides for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision is included in DD&A expense.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------- -------------------- -----------------
AMOUNTS IN THOUSANDS EXCEPT PER
BOE 1999 1998 1999 1998
- --------------------------------- ------- -------- ------- --------
Depletion and depreciation $ 5,542 $ 15,972 $ 10,800 $ 28,270
Site restoration provision 68 99 145 188
------- -------- -------- --------
Total amortization $ 5,610 $ 16,071 $ 10,945 $ 28,458
------- -------- -------- --------
Average DD&A cost per BOE $ 3.85 $ 8.05 $ 3.85 $ 7.25
- --------------------------------- ------- -------- -------- --------
Income Taxes
Due to a net operating loss of the Company for tax purposes, the Company
does not have any current tax provision. In addition, as a result of the net
pre-tax loss of $2.5 million for the six months ended June 30, 1999, an income
tax provision for that period using the effective tax rate of 37% would have
resulted in a $939,000 income tax benefit and an increase to the deferred tax
asset. Since the Company currently has a large tax net operating loss and it is
uncertain whether this total tax asset will ultimately be realized, the Company
has provided a valuation allowance for the tax benefit generated in the first
six months of 1999, resulting in no effective income tax provision.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------- -------------------- -----------------
1999 1998 1999 1998
- --------------------------------- --------- -------- ------- --------
Deferred income tax benefit
(thousands) $ - $(50,245) $ - $(50,618)
Average income tax costs
(benefit) per BOE - $ (25.18) - $ (12.90)
Effective tax rate - 29% - 29%
- --------------------------------- --------- -------- ------- --------
15
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Summary Operating and BOE Data
As a result of the $165 million writedown of oil and natural gas properties
as of June 30, 1998, net income increased during 1999 for both the second
quarter and the first six months, when compared to 1998. However, there are
several other factors also discussed above which had an impact on the results of
operations.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------- ------------------ -----------------
AMOUNTS IN THOUSAND EXCEPT PER SHARE
AMOUNTS 1999 1998 1999 1998
- --------------------------------------- ------- --------- -------- ---------
Net income (loss) $ 492 $(121,939) $ (2,537)$(122,619)
Net income (loss) per common share:
Basic $ 0.01 $ (4.57) $ (0.07)$ (4.89)
Diluted 0.01 (4.57) (0.07) (4.89)
Cash flow from operations (1) $ 6,598 $ 9,052 $ 9,095 $ 20,507
- --------------------------------------- -------- --------- -------- ---------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
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.
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------- ------------------- ----------------
Per BOE Data 1999 1998 1999 1998
- --------------------------------------- -------- -------- ------ -------
Oil and natural gas revenue $ 12.26 $ 11.28 $ 11.44 $ 12.15
Production expenses (4.45) (4.06) (4.34) (4.07)
- --------------------------------------- -------- -------- ------- -------
Production netback 7.81 7.22 7.10 8.08
General and administrative (1.25) (0.96) (1.36) (0.99)
Interest and other income (expense) (2.22) (1.72) (2.65) (1.87)
- --------------------------------------- -------- -------- ------- -------
Cash flow from operations(1) 4.34 4.54 3.09 5.22
DD&A (3.85) (8.05) (3.85) (7.25)
Deferred income taxes - 25.18 - 12.90
Writedown of oil and natural gas
properties - (82.69) - (42.04)
Other non-cash items (0.15) (0.09) (0.13) (0.07)
- --------------------------------------- -------- -------- ------- -------
Net income (loss) $ 0.34 $ (61.11) $ (0.89) $(31.24)
- --------------------------------------- -------- -------- ------- -------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
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 significantly since year-end. The Company also
enters into various financial contracts to hedge its exposure to
16
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
commodity price risk associated with anticipated future oil and natural gas
production. These contracts consist of price ceilings and floors, no-cost
collars and fixed price swaps.
During June and July 1998, the Company entered into two no-cost financial
contracts ("collars") to hedge a total of 40 million cubic feet of natural gas
per day ("Mmcf/d"). The Company collected $539,000 on these financial contracts,
which have now expired, during the first half of 1999. During December 1998, the
Company extended these natural gas hedges through December 2000 by entering into
an additional no-cost collar with a floor price of $1.90 per MMBtu and a ceiling
price of $2.58 per MMBtu for the period of July 1999 through December 2000. This
contract hedges 25 MMcf/d for the months of July and August 1999 and 30 MMcf/d
for each month thereafter. This contract covers over 100% of the Company's
current net natural gas production. Based on the futures market prices at June
30, 1999, the Company would expect to pay approximately $422,000 on these
commodity contracts during the remaining term because a portion of the futures
market prices at June 30, 1999 exceeded the ceiling on the contract collars.
During the fourth quarter of 1998, the Company also modified certain of its
oil sales contracts. The new contracts, which are generally for a period of
eighteen months, provide that approximately 45% of the Company's oil production
as of January 31, 1999, has a price floor of between $8.00 and $10.00 per Bbl.
This equates to a NYMEX oil price of between $15.00 and $16.00 per Bbl. As
compensation for the price floors, the contracts provide that the premiums
received on the posted prices decrease as oil prices rise.
During March and April 1999, the Company entered into two no-cost financial
contracts to hedge a portion of its oil production. The first contract was a
fixed price swap for 3,000 Bbls/d for the period of April through December, 1999
at a price of $14.24 per Bbl. The second contract was a collar to hedge 3,000
Bbls/d for the period of May, 1999 through December, 2000 with a floor price of
$14.00 per Bbl and a ceiling price of $18.05 per Bbl. The Company paid
approximately $540,000 on the first contract during the second quarter of 1999
which lowered the effective net oil price received during that quarter by $0.51
per barrel. When combined with the amount received on the gas contracts, the
Company paid a net amount of $1,000 during the first six months of 1999 on its
commodity hedges. These two oil financial contracts hedge approximately 50% of
the Company's current oil production.
These contracts in effect at June 30, 1999 expire at various dates, with
the latest being December 2000. Gain or loss on these derivative commodity
contracts would be offset by a corresponding gain or loss on the hedged
commodity positions. Based on the futures market prices at June 30, 1999, the
Company would expect to pay approximately $3.5 million on the oil hedge
contracts and pay approximately $422,000 on the natural gas hedge contracts. If
the futures market prices were to increase 10% from those in effect at June 30,
1999, the Company would be required to make additional cash payments under the
commodity contracts of approximately $5.7 million. If the futures market prices
were to decline 10% from those in effect as June 30, 1999, the Company would
neither pay or receive anything under the natural gas commodity contracts and
reduce the payments due under the oil contracts by $1.8 million.
17
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Year 2000 Update
Year 2000 issues relate to the ability of computer programs or equipment to
accurately calculate, store or use dates after December 31, 1999. These dates
can be handled or interpreted in a number of different ways, but the most common
error is for the system to contain a two digit year which may cause the system
to interpret the year 2000 as 1900. Errors of this type can result in system
failures, miscalculations and the disruption of operations, including, among
other things, a temporary inability to process transactions, send invoices or
engage in similar normal business. In response to the Year 2000 issues, the
Company has developed a strategic plan divided into the following phases:
inventory, product compliance based on vendor representations and in-house
testing, third party integration and development of a contingency plan.
All of the Company's processing needs are handled by third party systems,
none of which have been substantially modified and all of which have been
purchased within the last few years. Therefore, the Company's initial review of
its in-house systems with regard to Year 2000 issues required an inventory of
its systems and a review of the vendor representations. The Company has
completed this initial review of its information systems. The licensor of the
Company's core financial software system has certified that such software is
Year 2000 compliant. Additionally, most other less critical software systems,
various types of equipment and non-information technology have been reviewed,
and based on vendor representations, are either compliant, will be compliant
with the next forthcoming software release or are systems that are not date
specific.
The Company's non-information technology consists primarily of various oil
and gas exploration and production equipment. The initial review has established
that the primary non-information technology systems functions are either not
date sensitive or are Year 2000 compliant based on vendor representations, and
are therefore predicted to operate in customary manners when faced with Year
2000 issues. However, the Company has determined that in the event such systems
are unable to address the Year 2000, employees can manually perform most, if not
all, functions.
In anticipation of Year 2000 issues, the Company is also evaluating the
Year 2000 readiness status of its third party service suppliers. In addition to
reviewing Year 2000 readiness statements issued by the third parties handling
the Company's processing needs, to date the Company has received, and is relying
upon, Year 2000 readiness reports periodically issued by its financial services
and electrical service providers, vendors and purchasers of the Company's oil
and natural gas products. The Company is continuing to review Year 2000
readiness of third party service suppliers and, based on their representations,
does not currently foresee material disruptions in the Company's business as a
result of Year 2000 issues. Unanticipated prolonged losses of certain services,
such as electrical power, could cause material disruptions for which no
economically feasible contingency plan has been developed.
The Company is continuing to conduct in-house testing of the core systems
and non-information technology, and to date either all systems tested have
adequately addressed possible Year 2000 scenarios or the Company has a plan in
place to remedy the deficiency. The Company expects testing to be completed
during the third quarter of 1999. After the completion of its Year 2000 review
and testing, the Company will further develop a contingency plan as required,
including replacing or upgrading by December 31, 1999 any system incapable of
addressing the Year 2000. This final step is also expected to be completed
during the third quarter of 1999.
Although the effects of Year 2000 issues cannot be predicted with
certainty, the Company believes that the potential impact, if any, of such
events will, at most, require employees to manually complete otherwise automated
tasks or
18
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
calculations, other than those which might occur in a "worst case" scenario as
described below, which the Company does not anticipate will occur.
After considering Year 2000 effects on in-house operations, the Company
does not expect that any additional training would be required to perform these
tasks on a manual basis due to the level of experience of its personnel and the
routine nature of the tasks being performed. If, based on the results of its
in-house testing, the Company should determine that certain systems are not Year
2000 compliant and it appears as though the system is not likely to be compliant
within a reasonable time period, the Company will either elect to perform the
task manually or will attempt to purchase a different system for that particular
task and convert before December 31, 1999. The Company does not believe that
either option would impact the Company's ability to continue exploration,
drilling, production or sales activities, although the tasks may require
additional time and personnel to complete the same function or may require
incremental time and personnel during 1999 for a conversion to a new system.
The Company's core business consists primarily of oil and gas acquisition,
development and exploration activities. The equipment which is deemed "mission
critical" to the Company's activities requires external power sources such as
electricity supplied by third parties. Although the Company maintains limited
on-site secondary power sources such as generators, it is not economically
feasible to maintain secondary power supplies for any major component of its
"mission critical" equipment. Therefore, the most reasonably likely worst case
Year 2000 scenario for the Company would involve a disruption of third party
supplied electrical power, which would result in a substantial decrease in the
Company's oil production. Such event could result in a business interruption
that could materially affect the Company's operations, liquidity or capital
resources.
The Company has initiated the third party integration phase and will
continue to have formal communications with its significant suppliers, business
partners and key customers to determine the extent to which the Company is
vulnerable to either the third parties' or its own failure to correct their Year
2000 issues. The Company has been communicating with such third parties to keep
them informed of the Company's internal assessment of its Year 2000 review and
plans. This portion of the review and discussions with third parties is expected
to be completed during the third quarter of 1999. To date, more than one-half of
these third parties have provided certain favorable representations as to their
Year 2000 readiness and received similar representations from the Company. There
can be no guarantee that the systems of other companies on which the Company
relies will be timely converted or that the conversion will be compatible with
the Company's systems. However, after reviewing and estimating the effects of
such events, the Company's contingency plan involves identifying and arranging
for other vendors, purchasers and third party contractors to provide such
services, if necessary, in order to maintain its normal operations.
The Company has, and will continue to, utilize both internal and external
resources to complete tasks and perform testing necessary to address the Year
2000 issue. The Company has not incurred, and does not anticipate that it will
incur, any significant costs relating to the assessment and remediation of Year
2000 issues.
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
19
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
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 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, the uncertainty of drilling results and reserve estimates,
operating hazards, acquisition risks, requirements for capital, general economic
conditions, competition and government regulations, as well as the risks and
uncertainties discussed in this Quarterly Report, including, without limitation,
the portions referenced above, and the uncertainties set forth from time to time
in the Company's other public reports, filings and public statements.
In assessing Year 2000 issues, the Company has relied on certain
representations of third parties and has attempted to predict and address all
possible scenarios which could arise. However, uncertainties exist which could
cause Year 2000 effects to be more significant than the Company anticipates.
Such uncertainties include the success of the Company in identifying systems and
programs that are not Year 2000 compliant, the nature and amount of programming
required to up-grade or replace each of the affected programs, the availability,
rate and magnitude of related labor and consulting costs and the success of the
Company's vendors in addressing the Year 2000 issue.
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.
20
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders
Denbury's annual meeting of shareholders was held on May 19, 1999 for the
purpose of considering the following proposals: 1) the election of seven
nominees to serve as Directors of Denbury for one-year terms to expire at
the 2000 annual meeting of stockholders and 2) the appointment of Deloitte
and Touche LLP as auditors for the ensuing year and the authorization of
the directors to fix their remuneration as such. At the record date,
26,801,680 shares of common stock were outstanding and entitled to one vote
per share upon all matters submitted at the meeting.
With respect to proposal 1 above, the votes were cast as follows:
NOMINEES FOR DIRECTORS FOR AGAINST ABSTENTIONS
----------------------- ------------ ----------- -------------
Ronald G. Greene 22,897,443 - 12,445
David Bonderman 22,897,443 - 12,445
Wilmot L. Matthews 22,897,443 - 12,445
William S. Price, III 22,897,443 - 12,445
Gareth Roberts 22,897,443 - 12,445
David M. Stanton 22,897,443 - 12,445
Wieland F. Wettstein 22,897,443 - 12,445
With respect to proposal 2 above, the votes were cast as follows:
FOR AGAINST ABSTENTIONS
------------ ----------- ------------
22,898,488 - 11,400
Item 6. Exhibits and Reports on Form 8-K during the Second Quarter of 1999
Exhibits:
---------
10 Form of indemnification agreement between Denbury Resources
Inc. and its officers and directors.
27 Financial Data Schedule (EDGAR version only).
Reports on Form 8-K:
--------------------
None
21
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:
-------------------------------
Phil Rykhoek
Chief Financial Officer
By:
-------------------------------
Mark C. Allen
Chief Accounting Officer & Controller
Date: August 11, 1999
22