<PAGE> 1
==============================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------------------------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
Commission file number 1-12534
---------------------------------------------
NEWFIELD EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 72-1133047
(State or other jurisdiction (I.R.S. employer
of incorporation or organization) identification number)
363 N. Sam Houston Parkway E.
Suite 2020
Houston, Texas 77060
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (281) 847-6000
---------------------------------------------
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 [ ]
As of October 26, 2000, there were 42,529,097 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
==============================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
PART I
<S> <C> <C>
Item 1. Financial Statements:
Consolidated Balance Sheet as of September 30,
2000 and December 31, 1999 . . . . . . . . . . . . . 1
Consolidated Statement of Income for the three months
ended September 30, 2000 and 1999 and for the nine
months ended September 30, 2000 and 1999 . . . . . . 2
Consolidated Statement of Cash Flows for the
nine months ended September 30, 2000 and 1999. . . . 3
Consolidated Statement of Stockholders' Equity
for the nine months ended September 30, 2000 . . . . 4
Notes to Consolidated Financial Statements . . . . . . 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 11
PART II
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . 21
</TABLE>
-ii-
<PAGE> 3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------ ------------
ASSETS
<S> <C> <C>
Current assets:
Cash and cash equivalents . . . . . . . . . $ 43,953 $ 41,841
Accounts receivable-oil and gas . . . . . . 94,952 67,744
Inventories . . . . . . . . . . . . . . . . 17,433 9,962
Other . . . . . . . . . . . . . . . . . . . 5,222 6,382
------------ ------------
Total current assets. . . . . . . . . . . 161,560 125,929
------------ ------------
Oil and gas properties (full cost method, of
which $100,046 at September 30, 2000 and
$77,732 at December 31, 1999 were excluded
from amortization). . . . . . . . . . . . . 1,499,995 1,210,895
Less-accumulated depreciation, depletion and
amortization. . . . . . . . . . . . . . . . (704,446) (566,053)
------------ ------------
795,549 644,842
------------ ------------
Furniture, fixtures and equipment, net. . . . 3,683 3,369
Other assets. . . . . . . . . . . . . . . . . 6,944 7,421
------------ ------------
Total assets. . . . . . . . . . . . . . . $ 967,736 $ 781,561
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities. . $ 119,669 $ 88,670
Advances from joint owners. . . . . . . . . 7,902 2,057
------------ ------------
Total current liabilities . . . . . . . . 127,571 90,727
------------ ------------
Other liabilities . . . . . . . . . . . . . . 6,835 10,586
Long-term debt. . . . . . . . . . . . . . . . 162,703 124,679
Deferred taxes. . . . . . . . . . . . . . . . 50,804 36,801
------------ ------------
Total long-term liabilities . . . . . . . 220,342 172,066
------------ ------------
Company-obligated, mandatorily redeemable,
convertible preferred securities of Newfield
Financial Trust I. . . . . . . . . . . . . . 143,750 143,750
------------ ------------
Commitments and contingencies . . . . . . . . --- ---
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000
shares authorized, no shares issued). . . --- ---
Common stock ($0.01 par value, 100,000,000
shares authorized; 42,526,897 and
41,734,884 shares issued and outstanding
at September 30, 2000 and
December 31, 1999, respectively) . . . . 425 417
Additional paid-in capital. . . . . . . . . . 285,348 267,352
Unearned compensation . . . . . . . . . . . . (6,985) (3,685)
Accumulated other comprehensive - loss -
foreign currency translation adjustment. . . (4,850) (179)
Retained earnings . . . . . . . . . . . . . . 202,135 111,113
------------ ------------
Total stockholders' equity. . . . . . . . 476,073 375,018
------------ ------------
Total liabilities and stockholders' equity $ 967,736 $ 781,561
============ ============
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of this statement.
-1-
<PAGE> 4
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In thousands, except per share data)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- ---------------------
2000 1999 2000 1999
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oil and gas revenues. . . . . . . $151,263 $ 78,648 $365,180 $191,725
--------- --------- --------- ---------
Operating expenses:
Lease operating . . . . . . . . 18,067 12,016 49,092 30,783
Production and other taxes. . . 2,530 963 4,015 1,054
Depreciation, depletion and
amortization . . . . . . . . 51,183 38,382 139,140 112,232
Ceiling test writedown. . . . . 503 --- 503 ---
General and administrative
(exclusive of stock
compensation). . . . . . . . 8,036 4,094 20,639 10,350
Stock compensation. . . . . . . 767 494 2,262 1,485
--------- --------- --------- ---------
Total operating expenses. . . 81,086 55,949 215,651 155,904
--------- --------- --------- ---------
Income from operations. . . . . . 70,177 22,699 149,529 35,821
Other income (expenses):
Interest income . . . . . . . . 580 427 1,502 715
Interest expense, net . . . . . (2,441) (2,675) (7,614) (9,324)
Dividends on convertible
preferred securities of
Newfield Financial Trust I . (2,336) (1,168) (7,008) (1,168)
--------- --------- --------- ---------
(4,197) (3,416) (13,120) (9,777)
--------- --------- --------- ---------
Income before income taxes. . . . 65,980 19,283 136,409 26,044
Income tax provision:
Current . . . . . . . . . . . . 8,447 --- 22,894 ---
Deferred. . . . . . . . . . . . 13,195 6,878 22,493 9,434
--------- --------- --------- ---------
21,642 6,878 45,387 9,434
--------- --------- --------- ---------
Net income. . . . . . . . . . . . $ 44,338 $ 12,405 $ 91,022 $ 16,610
========= ========= ========= =========
Basic earnings per common share . $ 1.04 $ 0.30 $ 2.15 $ 0.40
========= ========= ========== =========
Diluted earnings per common share $ 0.97 $ 0.29 $ 2.03 $ 0.39
========= ========= ========== =========
Weighted average number of shares
outstanding for basic earnings
per share. . . . . . . . . . . 42,493 41,517 42,260 41,039
========= ========= ========= =========
Weighted average number of shares
outstanding for diluted
earnings per share . . . . . . 47,366 42,590 47,158 42,192
========= ========= ========= =========
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of this financial statement.
-2-
<PAGE> 5
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
---------------------------
2000 1999
----------- ------------
<S> <C> <C>
Cash flows from operating activities:
Net income. . . . . . . . . . . . . . . . $ 91,022 $ 16,610
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion
and amortization. . . . . . . . . . . 139,140 112,232
Deferred taxes. . . . . . . . . . . . . 22,493 9,434
Stock compensation. . . . . . . . . . . 2,262 1,485
Ceiling test writedown. . . . . . . . . 503 ---
----------- ------------
255,420 139,761
Changes in assets and liabilities:
(Increase) decrease in accounts
receivable, oil and gas . . . . . . . (28,341) 1,585
(Increase) decrease in inventory. . . . (10,100) 1,503
Increase in other current assets. . . . (810) (3,012)
Increase (decrease) in other assets . . 477 (4,177)
Increase (decrease) in accounts payable
and accrued liabilities . . . . . . . 28,592 (204)
Increase (decrease) in advances from
joint owners. . . . . . . . . . . . . 5,845 (1,566)
Decrease in other liabilities . . . . . (3,536) (559)
----------- ------------
Net cash provided by
operating activities. . . . . . . . 247,547 133,331
----------- ------------
Cash flows from investing activities:
Acquisition of Gulf Australia,
net of cash acquired. . . . . . . . . --- (10,681)
Additions to oil and gas properties . . (287,781) (157,764)
Additions to furniture, fixtures and
equipment . . . . . . . . . . . . . . (1,097) (922)
----------- ------------
Net cash used in
investing activities. . . . . . . . (288,878) (169,367)
----------- ------------
Cash flows from financing activities:
Proceeds from borrowings. . . . . . . . 158,000 443,000
Repayments of borrowings. . . . . . . . (120,000) (527,000)
Proceeds from issuances of convertible
preferred securities. . . . . . . . . --- 143,750
Proceeds from issuances of common
stock, net. . . . . . . . . . . . . . 5,875 6,707
----------- ------------
Net cash provided by
financing activities . . . . . . . 43,875 66,457
----------- ------------
Effect of exchange rate changes on cash and
cash equivalents . . . . . . . . . . . (432) (88)
----------- ------------
Increase in cash and cash equivalents . . . . 2,112 30,333
Cash and cash equivalents,
beginning of period . . . . . . . . . . 41,841 92
----------- ------------
Cash and cash equivalents, end of period. . . $ 43,953 $ 30,425
=========== ============
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of this financial statement.
-3-
<PAGE> 6
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In thousands, except share data)
(Unaudited)
<TABLE>
<CAPTION>
Accumulated
Common Stock Additional Other Total
------------------- Paid-in Unearned Retained Compreshensive Stockholders'
Shares Amount Capital Compensation Earnings Loss Equity
---------- ------ -------- ------------ -------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31,
1999.................. 41,734,884 $ 417 $267,352 $ (3,685) $111,113 $ (179) $375,018
Issuance of common
stock............... 695,757 7 5,868 5,875
Issuance of
restricted stock,
less amortization
of $476............. 96,256 1 5,561 (5,086) 476
Amortization of stock
compensation........ 1,786 1,786
Tax benefit from
exercise of
stock options....... 6,567 6,567
Comprehensive Income:
Net income............ 91,022 91,022
Foreign currency
translation
adjustment net
of tax.............. (4,671) (4,671)
---------
Total
Comprehensive
Income........ 86,351
---------- ------ -------- ------------ -------- ------------ ---------
Balance, September 30,
2000................... 42,526,897 $ 425 $285,348 $ (6,985) $202,135 $ (4,850) $476,073
========== ====== ======== ============ ======== ============ =========
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of this statement.
-4-
<PAGE> 7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Accounting Policies
Basis of Presentation
Unless the context otherwise requires, references to the "Company"
include Newfield Exploration Company and its subsidiaries. All significant
intercompany balances and transactions have been eliminated. The unaudited
consolidated financial statements of the Company reflect, in the opinion of
management, all adjustments, consisting only of normal and recurring
adjustments, necessary to present fairly the Company's consolidated financial
position at September 30, 2000 and the Company's consolidated results of
operations for the three and nine month periods ended September 30, 2000 and
1999 and consolidated cash flows for the nine-month periods ended September 30,
2000 and 1999. The consolidated financial statements have been prepared in
accordance with the instructions to Form 10-Q and therefore do not include all
disclosures required for financial statements prepared in conformity with
generally accepted accounting principles. Interim period results are not
necessarily indicative of results of operations or cash flows for a full year.
These consolidated 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, including the financial statements and notes thereto.
Earnings per Share
Basic earnings per common share ("EPS") is computed by dividing
net income by the weighted average number of common shares outstanding
for the period. Diluted EPS reflects the potential dilution that could occur
if securities were exercised for or converted into common stock.
The following is a calculation of basic and diluted weighted average
shares outstanding for the three months and nine months ended September 30,
2000 and 1999, respectively (in thousands, except per share data):
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Income:
Income - basic. . . . . . . . . $ 44,338 $ 12,405 $ 91,022 $ 16,610
Preferred dividends on
convertible securities, net
of tax. . . . . . . . . . . . 1,518 --- 4,555 ---
--------- --------- --------- ---------
Income - diluted. . . . . . . . $ 45,856 $ 12,405 $ 95,577 $ 16,610
========= ========= ========= =========
Shares:
Shares outstanding - basic. . . 42,493 41,517 42,260 41,039
Stock options . . . . . . . . . 950 1,073 975 1,153
Convertible preferred securities
of Newfield Financial Trust I. 3,923 --- 3,923 ---
--------- --------- --------- ---------
Shares oustanding - diluted . . 47,366 42,590 47,158 42,192
========= ========= ========= =========
Earnings per Share:
Basic. . . . . . . . . . . . . $ 1.04 $ 0.30 $ 2.15 $ 0.40
Diluted. . . . . . . . . . . . $ 0.97 $ 0.29 $ 2.03 $ 0.39
</TABLE>
-5-
<PAGE> 8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
The calculation of shares outstanding for diluted EPS for the three months
ended September 30, 2000 and 1999 does not include the effect of outstanding
stock options to purchase 66,500 and 42,000 shares, respectively, because to do
so would have been antidilutive. The calculation of shares outstanding for
diluted EPS for nine months ended September 30, 2000 and 1999 does not include
the effect of outstanding stock options to purchase 86,500 and 263,500 shares,
respectively, because to do so would have been antidilutive.
Hedging
The Company enters into various commodity price hedging contracts with
respect to its oil and gas production. While the use of these hedging
arrangements limits the downside risk of adverse price movements, they may
also limit future revenues from favorable price movements. The use of
hedging arrangements also involves the risk that the counterparties will be
unable to meet the financial terms of such transactions. Hedging contracts are
accounted for as hedges in accordance with Statement of Financial Accounting
Standards No. 80. Gains and losses on these contracts are recognized in revenue
in the period in which the underlying production is delivered. These contracts
are measured for correlation at both the inception of the contract and on an
ongoing basis. If these instruments cease to meet the criteria for deferral
accounting, any subsequent gains or losses are recognized in income. If these
instruments are terminated prior to maturity, resulting gains and losses
continue to be deferred until the hedged item is recognized in revenue.
(2) Property Acquisition
In February 2000, the Company acquired interests in three producing gas
fields in South Texas for approximately $137 million. The acquisition has been
accounted for as a purchase and, accordingly, income and expenses from the
properties have been included in the Company's statement of income from the
date of purchase.
The unaudited pro forma results of operations assuming that such
acquisition occurred on January 1 of the respective periods are as follow (in
thousands, except per share amounts):
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- --------------------
2000 1999 2000 1999
-------- -------- -------- --------
(Unaudited)
<S> <C> <C> <C> <C>
Proforma:
Revenue . . . . . . . . . . . . . . . . . . $151,263 $86,359 $370,680 $209,638
Income from operations. . . . . . . . . . . 70,177 25,541 152,071 40,913
Net income. . . . . . . . . . . . . . . . . 44,338 13,272 92,052 16,919
Basic earnings per common share . . . . . . $1.04 $0.32 $2.18 $0.41
Diluted earnings per common share . . . . . $0.97 $0.31 $2.05 $0.40
</TABLE>
The proforma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisition taken
place at the beginning of the periods presented or future results of
operations.
-6-
<PAGE> 9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(3) Contingencies
The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot
be predicted with certainty, management does not expect these matters to have
a material adverse effect on the financial position, cash flows or results of
operations of the Company.
Management believes that the Company is in substantial compliance with
current applicable U.S. federal, state and local environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse effect on the Company's financial position, cash flows
or results of operations. The Company's foreign operations are potentially
subject to similar governmental controls and restrictions relating to the
environment. Management believes that the Company is in substantial compliance
with any such foreign requirements pertaining to the environment. There can be
no assurance, however, that current regulatory requirements will not change,
currently unforeseen environmental incidents will not occur or past
non-compliance with environmental laws or regulations will not be discovered.
-7-
<PAGE> 10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(4) Geographic Information
<TABLE>
<CAPTION>
Other
United States Australia International Total
------------- --------- ------------- ---------
(In thousands)
<S> <C> <C> <C> <C>
Three months ended September 30, 2000
------------------------------------
Oil and gas revenues................ $ 137,067 $ 14,196 $ --- $ 151,263
Operating expenses:
Lease operating................... 14,919 3,148 --- 18,067
Production and other taxes........ 1,263 1,267 --- 2,530
Depreciation, depletion and
amortization.................... 49,378 1,805 --- 51,183
Ceiling test writedown............ --- --- 503 503
Allocated income taxes............ 25,028 2,712 ---
--------- --------- ---------
Net income from oil and
gas operations............... $ 46,479 $ 5,264 $ 503
========= ========= =========
General and administrative
(exclusive of stock
compensation)................. 8,036
Stock compensation................ 767
---------
Total operating expenses.. 81,086
---------
Income from operations.............. 70,177
Interest expense, net............. (4,197)
---------
Income before income taxes.......... $ 65,980
=========
Total Long-Lived Assets............. $772,116 $ 10,082 $ 13,351 $ 795,549
========= ========= ========= =========
Additions to Long-Lived Assets...... $ 54,715 $ 2,464 $ 1,910 $ 54,161
========= ========= ========= =========
Three months ended September 30, 1999
------------------------------------
Oil and gas revenues................ $ 67,614 $ 11,034 $ --- $ 78,648
Operating expenses:
Lease operating................... 8,347 3,669 --- 12,016
Production and other taxes........ 226 737 --- 963
Depreciation, depletion and
amortization................... 36,957 1,425 --- 38,382
Allocated income taxes............ 7,730 1,873 ---
--------- --------- ---------
Net income from oil and
gas operations............... $ 14,354 $ 3,330 $ ---
========= ========= =========
General and administrative
(exclusive of stock
compensation) ................ 4,094
Stock compensation................ 494
---------
Total operating expenses.. 55,949
---------
Income from operations.............. 22,699
Interest expense, net............. (3,416)
---------
Loss before income taxes............ $ 19,283
=========
Total Long-Lived Assets............. $ 612,839 $ 171 $ 10,300 $ 623,310
========= ========= ========= =========
Additions to Long-Lived Asset....... $ 107,106 $ 1,596 $ (193) $ 108,509
========= ========= ========= =========
</TABLE>
-8-
<PAGE> 11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
<TABLE>
<CAPTION>
Other
United States Australia International Total
------------- ---------- ------------- ---------
(In thousands)
<S> <C> <C> <C> <C>
Nine months ended September 30, 2000
-------------------------------------
Oil and gas revenues................ $ 326,917 $ 38,263 $ --- $ 365,180
Operating expenses:
Lease operating................... 38,445 10,647 --- 49,092
Production and other taxes........ 3,252 763 --- 4,015
Depreciation, depletion and
amortization.................... 133,695 5,445 --- 139,140
Ceiling test writedown............ --- --- 503 503
Allocated income taxes............ 53,034 7,279 ---
--------- --------- ---------
Net income from oil and
gas operations............... $ 98,491 $ 14,129 $ 503
========= ========= =========
General and administrative
(exclusive of stock
compensation).................. 20,639
Stock compensation................ 2,262
---------
Total operating expenses.. 215,651
---------
Income from operations.............. 149,529
Interest expense, net............. (13,120)
---------
Income before income taxes.......... $ 136,409
=========
Total Long-Lived Assets............. $ 772,116 $ 10,082 $ 13,351 $ 795,549
========= ========= ========= =========
Additions to Long-Lived Assets...... $ 274,850 $ 11,395 $ 3,424 $ 289,669
========= ========= ========= =========
Nine months ended September 30, 1999
-------------------------------------
Oil and gas revenues................ $ 180,691 $ 11,034 $ --- $ 191,725
Operating expenses:
Lease operating................... 27,114 3,669 --- 30,783
Production and other taxes........ 317 737 --- 1,054
Depreciation, depletion and
amortization................... 110,807 1,425 --- 112,232
Allocated income taxes............ 14,859 1,873 ---
--------- --------- ---------
Net income from oil and
gas operations............... $ 27,594 $ 3,330 $ ---
========= ========= =========
General and administrative
(exclusive of stock
compensation)................. 10,350
Stock compensation................ 1,485
---------
Total operating expenses.. 155,904
---------
Income from operations.............. 35,821
Interest expense, net............. (9,777)
---------
Loss before income taxes............ $ 26,044
=========
Total Long-Lived Assets............. $ 612,839 $ 171 $ 10,300 $ 623,310
========= ========= ========= =========
Additions to Long-Lived Asset....... $ 153,863 $ 1,596 $ 1,136 $ 156,595
========= ========= ========= =========
</TABLE>
-9-
<PAGE> 12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(5) Hedging Transactions
As of October 26, 2000, the Company had entered into commodity price
hedging contracts with respect to its 2000 through 2002 natural gas and oil
production, some of which were entered into subsequent to September 30, 2000,
as follows:
<TABLE>
<CAPTION>
NATURAL GAS Swaps Collars Floor Contracts
-------------------- --------------------------------- ----------------------------
Weighted NYMEX
Average Contract
NYMEX Price
Contract per MMBtu NYMEX
Volume in Price Volume in ------------------------ Volume in Contract Price
PERIOD MMMBtus per MMBtu MMMBtus Floors Ceilings MMMbtus per MMBtu
--------------------------- ------- --------- --------- ----------- ----------- --------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 2000-December 2000. 11,260 $3.00 1,110 $2.60-$2.75 $3.21-$3.28 3,000 $5.35-$5.44
January 2001-March 2001.... 10,050 $3.05 5,130 $2.75-$4.50 $3.21-$6.25 --- ---
April 2001-June 2001....... 5,640 $2.80 7,480 $2.75-$4.00 $3.21-$5.75 --- ---
July 2001-September 2001... --- --- 7,000 $3.25-$4.00 $3.85-$5.75 --- ---
October 2001............... --- --- 500 $4.00 $5.75 --- ---
</TABLE>
<TABLE>
<CAPTION>
OIL Swaps Collars Floor Contracts
-------------------- ---------------------------------------- -------------------------
Weighted
Average NYMEX
NYMEX Contract Price NYMEX
Contract per Bbl Contract
Volume in Price Volume in ---------------------------- Volume in Price
PERIOD Bbls per Bbl Bbls Floors Ceilings Bbls per Bbl
------------------------------ --------- --------- --------- ------------- ------------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 2000-December 2000.... 736,000 $22.09 184,000 $25.00 $30.05 --- ---
January 2001-March 2001....... 540,000 $21.99 270,000 $25.00 $30.05-$30.75 112,500 $22.17-$26.00
April 2001-June 2001.......... 364,000 $21.70 364,000 $25.00-$27.25 $30.05-$30.75 113,750 $24.17-$26.00
July 2001-September 2001...... 276,000 $22.57 414,000 $24.00-$26.25 $27.30-$32.45 115,000 $24.17-$26.00
October 2001-December 2001.... 276,000 $22.17 345,000 $24.00-$25.25 $27.30-$30.75 115,000 $24.17-$26.00
January 2002-March 2002....... --- --- 517,500 $22.00-$25.00 $25.75-$30.75 --- ---
April 2002-June 2002.......... --- --- 455,000 $22.00-$25.00 $25.75-$30.75 --- ---
July 2002-September 2002...... --- --- 345,000 $23.00-$25.00 $26.75-$30.75 --- ---
October 2002-December 2002.... --- --- 184,000 $25.00 $28.00-$30.75 --- ---
</TABLE>
-10-
<PAGE> 13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
As an independent oil and gas producer, our revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas, oil and condensate, which are dependent upon numerous factors
beyond our control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have historically
been very volatile, and there can be no assurance that oil and gas prices will
not be subject to wide fluctuations in the future. A substantial or extended
decline in oil and gas prices could have a material adverse effect on our
financial position, results of operations, cash flows, quantities of oil and
gas reserves that may be economically produced and access to capital.
Our results of operations and cash flows may vary significantly from
quarter to quarter as a result of development operations, commodity prices,
the curtailment of production in association with workover and recompletion
activities and the incurrence of expenses related thereto, the timing and
amount of reimbursement for customary overhead costs we receive and other
factors, and, the results of operations and cash flows for any one quarter may
not be indicative of results for the full fiscal year.
We use the full cost method of accounting. Under this method, all costs
incurred in the acquisition, exploration and development of oil and gas
properties are capitalized into cost centers that are established on a
country-by-country basis. For each cost center, at the end of each quarter,
the net capitalized costs of oil and gas properties are limited to the lower of
unamortized cost or the cost center ceiling, defined as the sum of the present
value (10% discount rate) of estimated future net revenues from proved
reserves, based on period-end oil and gas prices; plus the cost of properties
not being amortized, if any; plus the lower of cost or estimated fair value of
unproved properties included in the costs being amortized, if any; less related
income tax effects. If net capitalized costs of oil and gas properties exceed
the ceiling limit, we are subject to a ceiling test writedown to the extent of
such excess. A ceiling test writedown is a non-cash charge to earnings. If
required, it would reduce earnings and impact stockholders' equity in the
period of occurrence.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards 133, "Accounting for Derivative
Instruments and Hedging Activities" (FAS 133). In June 1999, the FASB issued
FAS 137 "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement 133," which deferred FAS
133's effective date to fiscal years beginning after June 15, 2000. In June
2000, the FASB issued FAS 138, "Accounting for Certain Derivative Instruments
and Certain Hedging Activities," which amended FAS 133. FAS 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) to be
recorded in the balance sheet as either an asset or liability at its fair
value. The accounting for changes in the fair value of a derivative depends on
the intended use of the derivative and the resulting designation.
We will adopt FAS 133 effective January 1, 2001. We expect our natural
gas and oil forward sales contracts to qualify for special hedge accounting
treatment under FAS 133, whereby changes in fair value will be recognized in
other comprehensive income (a component of stockholder's equity) until settled,
when the resulting gains and losses will be recorded in earnings. Any hedge
ineffectiveness will be charged currently to earnings; however, we believe that
any ineffectiveness will be immaterial. The affect on our earnings and other
comprehensive income as the result of the adoption of FAS 133 will vary from
period to period and will be dependent upon prevailing oil and gas prices, the
volatility of forward prices for such commodities, the volumes of production
we hedge and the time periods covered by such hedges. We do not expect
FAS 133 to have a material impact on our financial statements as a result of
other contractual arrangements that we are subject to.
Explanation of some commonly used oil and gas terms can be found under the
caption "Commonly Used Oil and Gas Terms" at the end of Management's Discussion
and Analysis.
-11-
<PAGE> 14
RESULTS OF OPERATIONS
The following table presents information about our oil and gas operations.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2000 1999 2000 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
PRODUCTION:
UNITED STATES
Natural gas (Bcf)........................ 27.9 21.7 77.5 65.0
Oil and condensate (MBbls)............... 1,190 883 3,065 2,593
Total (Bcfe)............................. 35.1 27.0 95.9 80.5
AUSTRALIA*
Oil and condensate (MBbls)............... 431 419 1,222 419
Total (Bcfe)............................. 2.6 2.5 7.3 2.5
TOTAL
Natural gas (Bcf)........................ 27.9 21.7 77.5 65.0
Oil and condensate (MBbls)............... 1,621 1,302 4,287 3,012
Total (Bcfe)............................. 37.7 29.5 103.2 83.0
AVERAGE REALIZED PRICES:
UNITED STATES
Natural gas (per Mcf).................... $ 3.86 $ 2.42 $ 3.29 $ 2.20
Oil and condensate (per Bbl)............. 24.66 17.12 23.57 14.43
AUSTRALIA
Oil and condensate (per Bbl)............. $32.93 26.33 $31.30 26.33
TOTAL
Natural gas (per Mcf).................... $ 3.86 $ 2.42 $ 3.29 $ 2.20
Oil and condensate (per Bbl)............. 26.86 20.09 25.77 16.08
</TABLE>
----------------
* In July 1999, we acquired oil producing assets offshore Australia.
PRODUCTION
NATURAL GAS. Natural gas production for the third quarter of 2000
increased 29% over the third quarter of 1999. Increases in gas production
were primarily related to the success of our drilling program at West Cameron
522 and 617, Eugene Island 198/199/202, Main Pass 264, onshore at our
Broussard, Provident City and Wright prospects, the acquisition of South Pass
41, Vermilion 215 and Ship Shoal 28 during the third quarter of 1999 and the
acquisition of three producing gas fields in South Texas in February 2000.
Gains in production were partially offset by natural declines from
other producing properties.
Natural gas volumes production for the first nine months of 2000 increased
19% over the first nine months of 1999. The increase was primarily related to
the success of our drilling program at West Cameron 522, 533 and 617, Eugene
Island 198/199/202, Main Pass 264, Ship Shoal 69, West Delta 18 and onshore at
Broussard and Provident City, the acquisition of South Pass 41, Vermilion 215
and Ship Shoal 28 during the third quarter of 1999 and the acquisition of three
producing gas fields in South Texas in February 2000. Gains in production were
partially offset by natural declines from other producing properties.
CRUDE OIL AND CONDENSATE. Our oil production increased 25% in the first
quarter of 2000 over the comparable quarter of 1999. Increases in oil and
condensate production were mainly due to the acquisition of Main Pass 138,
Vermilion 215, South Marsh 146, Ship Shoal 28 and West Delta 79 in the Gulf of
Mexico during the third quarter of 1999 and condensate production from the
acquisition of three producing gas fields in South Texas in February 2000 and
production from drilling success at Eugene Island 198/199/202, Main Pass 264,
Vermilion 398, South Marsh 160 and onshore at our Wright prospect. These
increases were offset by natural production declines from other producing
properties.
-12-
<PAGE> 15
Our oil production increased 42% in the first nine months of 2000 over the
comparable period of 1999. The primary reason for the increase was the
acquisition of interests in two oil fields in the Timor Sea, offshore
Australia, during the third quarter of 1999. Increases in domestic oil
production were mainly due to the acquisition of Main Pass 138, West Delta 79,
Vermilion 215 and condensate production from the acquisition of three producing
gas fields in South Texas in February 2000 and production from drilling success
at Eugene Island 198/199/202, Ship Shoal 69, Main Pass 264 and South Marsh
Island 160. These increases were offset by natural production declines from
other producing properties.
REALIZED PRICES
NATURAL GAS. Our average realized gas price in the third quarter of 2000
was $3.86 per Mcf, an increase of 60% over an average realized price of $2.42
per Mcf in the third quarter of 1999. Hedging activities in the third
quarter of 2000 resulted in a price that was 86% of what otherwise would have
been received. Hedging activities in the third quarter of 1999 resulted in a
price that was 93% of what otherwise would have been received.
Our average realized gas price in the first nine months of 2000 was $3.29
per Mcf, an increase of 50% over an average realized price of $2.20 per Mcf in
the first nine months of 1999. Hedging activities in the first nine months of
2000 resulted in a price that was 92% of what otherwise would have been
received. Hedging activities in the first nine months of 1999 resulted in a
price that was 102% of what otherwise would have been received.
CRUDE OIL AND CONDENSATE. Crude oil and condensate prices in the third
quarter of 2000 averaged $26.86, an increase of 34% over the average price of
$20.09 per barrel in the third quarter of 1999. Our average crude oil price
in the third quarter of 2000 was 85% of what would have been received without
hedging activities. Our average crude oil price in the third quarter of 1999
was 93% of what would have been received without hedging activities.
Crude oil and condensate prices in the first nine months of 2000 averaged
$25.77 per barrel, an increase of 60% over the average price of $16.08 per
barrel in the comparable period of 1999. Our average crude oil price in the
first nine months of 2000 was 86% of what would have been received without
hedging activities. Our average crude oil price in the first nine months of
1999 was 96% of what would have been received without hedging activities.
NET INCOME AND REVENUES
For the third quarter of 2000, we reported net income of $44.3 million,
or $0.97 cents per diluted share. This compares to net income of $12.4
million, or $0.29 per diluted share, in the third quarter of 1999. Revenues
for the third quarter of 2000 increased 92% to $151.3 million compared to
revenues of $78.6 million in the third quarter of 1999.
For the first nine months of 2000, we reported net income of $91.0 million,
or $2.03 cents per diluted share. This compares to net income of $16.6 million,
or $0.39 per diluted share, in the comparable period of 1999. Revenues for the
first nine months of 2000 increased 90% to $365.2 million compared to revenues
of $191.7 million in the comparable period of 1999.
The increases in net income and revenues in the three and nine month
periods ended September 30, 2000 were primarily due to sharp increases in
commodity prices coupled with higher production volumes partially offset by
higher costs.
-13-
<PAGE> 16
OPERATING EXPENSES
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ----------------
2000 1999 2000 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
AVERAGE COSTS (PER MCFE):
UNITED STATES
Lease operating........................... $0.43 $0.31 $0.40 $0.34
Production and other taxes................ 0.04 0.01 0.03 ---
Depreciation, depletion and amortization.. 1.41 1.37 1.39 1.38
General and administrative (exclusive of
stock compensation). ................... 0.22 0.14 0.21 0.12
AUSTRALIA*
Lease operating........................... $1.22 1.46 $1.45 1.46
Production and other taxes................ 0.49 0.29 0.10 0.29
Depreciation, depletion and amortization.. 0.70 0.57 0.74 0.57
General and administrative (exclusive of
stock compensation)..................... 0.14 0.17 0.06 0.17
TOTAL
Lease operating........................... $0.48 $0.41 $0.48 $0.37
Production and other taxes................ 0.07 0.03 0.04 0.01
Depreciation, depletion and amortization.. 1.36 1.30 1.35 1.35
General and administrative (exclusive of
stock compensation)..................... $0.21 $0.14 $0.20 $0.12
</TABLE>
----------------
* In July 1999, we acquired oil producing assets offshore Australia.
Operating expenses during the three and nine month periods ended September
30, 2000 were impacted by the following:
- Lease operating expense, stated on a unit of production basis, increased
17% to $0.48 per Mcfe in the third quarter of 2000 compared to $0.41
per Mcfe in the third quarter of 1999. Domestic lease operating
expense increased 39% on a unit of production basis to $0.43 per Mcfe in
the third quarter of 2000 compared to $0.31 per Mcfe in the third
quarter of 1999. Lease operating expense stated on a unit of production
basis, for the first nine months of 2000 increased 30% to $0.48 per Mcfe
compared to $0.37 per Mcfe for the first nine months of 1999. This
increase reflects higher oilfield service and related costs in the Gulf
of Mexico and the relatively higher Australian lease operating expenses
associated with the operations and maintenance of the two floating
production, storage and off-loading vessels.
- Production and other taxes in the third quarter of 2000 were $2.5
million, a 263% increase over the comparable period in 1999 of $1.0
million. This increase is primarily due to our acquisition of three
producing gas fields in South Texas in February 2000 and the acquisition
of interests in two oil fields in the Timor Sea, offshore Australia,
during the third quarter of 1999 and a higher commodity price environment
during the first nine months of 2000. For the first nine months of 2000,
production and other taxes were $4.0 million, an increase of 381% over
the first nine months of 1999 of $1.0 million. The increase is primarily
due to the acquisition of three producing gas fields in South Texas in
February 2000, and a higher commodity price environment partially offset
by a $1.5 million resource rent tax credit related to our Australian oil
production for the period from July 1999 to June 2000.
-14-
<PAGE> 17
- Depreciation, depletion and amortization expense for the third quarter
of 2000 increased 5% on a unit of production basis to $1.36 per Mcfe.
Our domestic DD&A rate increased 3% to $1.41 per Mcfe as compared to the
third quarter of 1999. Depreciation, depletion and amortization
expense for the nine months of 2000 remained flat on a unit of
production basis at $1.35 per Mcfe. Our domestic depreciation,
depletion and amortization expense increased 1% on a unit of production
basis to $1.39. The increases in the domestic DD&A rate are due to
several factors which include the increases in the cost of drilling
goods and services, platforms and facilities construction, industry
transportation cost and the completion of several higher cost wells.
The Australian DD&A rate was $0.70 per Mcfe for the third quarter and
$0.74 for the first nine months of 2000. The increases in the
Australian DD&A rate are a result of our unsuccessful drilling
activities in 2000 in Australia.
- General and administrative expense for the third quarter of 2000
increased $3.9 million compared to the third quarter of 1999, or 96%,
due primarily to an increase in performance based pay and our growing
workforce. Performance based compensation excluding stock compensation
expense, as a component of general and administrative expense, increased
from $1.2 million, or $0.04 per Mcfe, for the three months ended
September 30, 1999, to $4.0 million or $0.11 per Mcfe, for the three
months ended September 30, 2000. During the first nine months of 2000,
general and administrative expenses increased 99% to $20.6 million from
$10.4 million over the comparable period in 1999. This increase is
primarily due to an increase in performance based pay, some
non-recurring expenses associated with a transition to more
sophisticated business systems and our growing workforce. Performance
based compensation excluding stock compensation expense, as a component
of general and administrative expense, increased from $2.2 million, or
$0.03 per Mcfe, for the first nine months of 1999, to $8.5 million, or
$0.08 per Mcfe, for the first nine months of 2000. The increases in
performance based compensation are related to increases in earning which
are primarily a result of the sharp increases in commodity prices and
higher production volumes in the three and nine month periods ended
September 30, 2000 as compared to the comparable periods in 1999.
Performanced based pay is limited by profitability. Please see the
Company's Annual Report on Form 10-K for the year ended December 31,
1999.
-15-
<PAGE> 18
INTEREST EXPENSE AND DIVIDENDS
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ----------------
2000 1999 2000 1999
----- ----- ----- ------
(In millions)
<S> <C> <C> <C> <C>
Gross interest expense................................ $ 3.8 $ 3.3 $11.5 $10.9
Capitalized interest.................................. (1.4) (0.6) (3.9) (1.6)
----- ----- ----- -----
Net interest expense.................................. 2.4 2.7 7.6 9.3
Dividends on preferred securities..................... 2.3 1.2 7.0 1.2
----- ----- ----- -----
Total interest expense and dividends.................. $ 4.7 $ 3.9 $14.6 $10.5
===== ===== ===== =====
</TABLE>
Our net interest expense decreased as a result of the issuance of $143.8
million of 6.5% convertible preferred securities by Newfield Financial Trust
I in August 1999 (a portion of the proceeds of which were used to repay
borrowings) and a higher percentage of total interest costs being capitalized
during the third quarter and first nine months of 2000, partially offset by
higher average debt levels during the third quarter and first nine months of
2000. In total, interest expense and dividends increased in the third quarter
and first nine months of 2000 over the comparable periods of 1999 because of
the higher average levels of financing that were subject to interest or
dividends during the third quarter and first nine months of 2000, partially
offset by a higher percentage of total interest costs being capitalized during
the third quarter and first nine months of 2000. The borrowings that resulted
in higher average levels of financing and the remaining proceeds of the 6.5%
convertible preferred securities were used primarily to fund several
acquisitions in the second half of 1999 and our February 2000 South Texas
acquisition.
The effective tax rate for the three and nine month periods ended
September 30, 2000 was 33%. The effective tax rate was less
than the statutory tax rate because the valuation allowance on the Australian
net operating loss carryforwards was reduced by approximately $1.3 million and
$2.3 million for the three and nine month periods ended September 30, 2000,
respectively. Based on estimates of future taxable income, we believe it is
more likely than not that the Australian net operating loss will be fully
utilized. Estimates of future taxable income can be significantly affected by
changes in oil and natural gas prices, estimates of the timing and amounts of
future production, and estimates of future operating and capital costs. The
valuation allowance could be increased in the near term if our estimates of
future taxable income are significantly reduced. If sufficient taxable income
is not generated in the future through operating results, a valuation allowance
adjustment would be recorded as a charge to income.
LIQUIDITY AND CAPITAL RESOURCES
We had working capital of $33.9 million at September 30, 2000. This
compares to working capital of $35.2 million at December 31, 1999. Long-
term debt increased to $162.7 million at September 30, 2000 from $124.7
million at December 31, 1999. The $1.3 million decrease in working capital
and the increase in long-term debt is primarily due to the acquisition of
producing properties in South Texas in February 2000 for $137 million.
Working capital balances may fluctuate from quarter to quarter to the extent
we increase or decrease borrowings under our revolving credit facility.
Historically, we have funded our oil and gas activities through cash flow from
operations, equity capital from public sources, public debt and bank
borrowings.
-16-
<PAGE> 19
We maintain our reserve-based revolving credit facility with Chase Bank
of Texas, National Association, as agent. As of September 30, 2000, there was
$38.0 million outstanding under the credit facility. The credit facility
provides a $225 million revolving credit maturing on October 31, 2002. The
amount available under the credit facility is subject to a calculated borrowing
base determined by a majority of the banks participating in the credit
facility, which is reduced by the aggregate principal outstanding on our senior
unsecured notes (currently $125 million). The borrowing base is redetermined
at least semi-annually and, after reduction for the senior unsecured notes, is
currently $255 million. No assurances can be given that a majority of the
banks will not elect to redetermine the borrowing base in the future. We have
an option, subject to the borrowing base, to increase the facility to $250
million.
We have also established money market lines of credit with various banks,
the aggregate borrowings under which are limited by the credit facility to $25
million. As of September 30, 2000, there were no borrowings outstanding under
these lines of credit. At October 26, 2000, without so increasing the
facility, we have approximately $228 million of available capacity under the
credit facility and money market lines.
CASH FLOW FROM OPERATIONS. Our net cash flow from operations for the nine
months ended September 30, 2000 increased 86% over the comparable period of
1999 to $247.5 million. This increase in cash flow is primarily due to sharply
higher commodity prices for oil and gas and higher production volumes. Net
cash flow from operations before changes in working capial for the nine months
ended September 30, 2000 was $255.4 million compared to $139.8 million in the
comparable period of 1999. The increase in net cash flow from operations
before changes in working capital is primarily attributable to sharply higher
commodity prices and production volumes offset slightly by increased operating
expenses.
CAPITAL EXPENDITURES. We made capital expenditures of $289.7 million in
the first nine months of 2000. This includes $68.3 million for exploration,
$79.7 million for exploitation and development projects and $141.7 million for
property acquisitions. We have budgeted $70 million for capital spending for
the remainder of 2000. Approximately $20 million has been budgeted for
domestic exploration projects and $43 million for domestic exploitation and
development drilling and the construction of platforms, facilities and
pipelines. International spending is estimated at $7 million for the
remainder of 2000. Acquisitions are opportunistic and are generally not
budgeted under our capital program. We continue to pursue attractive
acquisition opportunities, however, the timing, size and purchase price of
acquisitions are unpredictable. Actual levels of capital expenditures may vary
significantly due to many factors, including drilling results, oil and gas
prices, industry conditions, the prices and availability of goods and services
and the extent to which proved properties are acquired.
Our February 2000 South Texas acquisition was funded with working capital
and borrowings under our credit facility. We anticipate that our remaining
capital expenditure budget for 2000 will be funded principally from cash flow
from operations and working capital. We do not anticipate additional
borrowings under our credit facility and money market lines of credit during
2000 unless we make another significant acquisition.
-17-
<PAGE> 20
HEDGING
We utilize and expect to continue to utilize hedging transactions with
respect to a portion of our oil and gas production. These derivative financial
instruments are used to hedge our exposure to changes in the market price of
natural gas and crude oil and to achieve more predictable cash flow. While the
use of these hedging arrangements limits the downside risk of adverse price
movements, they may also limit future revenues from favorable price movements.
The use of hedging transactions also involves the risk that the counterparties
will be unable to meet the financial terms of such transactions. All of our
hedging transactions to date were carried out in the over-the-counter market.
We account for these transactions as hedging activities and, accordingly, gains
or losses are included in oil and gas revenues when the hedged production is
delivered.
As of October 26, 2000, we had entered into commodity price hedging
contracts with respect to our 2000 and 2001 natural gas production as set forth
below. Some of these contracts were entered into subsequent to
September 30, 2000.
<TABLE>
<CAPTION>
Swaps Collars Floor Contracts
-------------------- --------------------------------- ----------------------------
Weighted NYMEX
Average Contract
NYMEX Price
Contract per MMBtu NYMEX
Volume in Price Volume in ------------------------ Volume in Contract Price
PERIOD MMMBtus per MMBtu MMMBtus Floors Ceilings MMMbtus per MMBtu
--------------------------- ------- --------- --------- ----------- ----------- --------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 2000-December 2000. 11,260 $3.00 1,110 $2.60-$2.75 $3.21-$3.28 3,000 $5.35-$5.44
January 2001-March 2001.... 10,050 $3.05 5,130 $2.75-$4.50 $3.21-$6.25 --- ---
April 2001-June 2001....... 5,640 $2.80 7,480 $2.75-$4.00 $3.21-$5.75 --- ---
July 2001-September 2001... --- --- 7,000 $3.25-$4.00 $3.85-$5.75 --- ---
October 2001............... --- --- 500 $4.00 $5.75 --- ---
</TABLE>
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or,
occasionally, the penultimate trading day of a particular contract month (the
"settlement price"). With respect to any particular swap transaction, the
counterparty is required to make a payment to us in the event that the
settlement price for any settlement period is less than the swap price for
such transaction, and we are required to make payment to the counterparty in
the event that the settlement price for any settlement period is greater than
the swap price for such transaction. For any particular collar transaction,
the counterparty is required to make a payment to us if the settlement price
for any settlement period is below the floor price for such transaction, and
we are required to make payment to the counterparty if the settlement price
for any settlement period is above the ceiling price for such transaction.
For any particular floor transaction, the counterparty is required to make a
payment to us if the settlement price for any settlement period is below the
floor price for such transaction. We are not required to make any payment in
connection with the settlement of a floor transaction.
We believe that we have no material basis risk with respect to gas swaps
because substantially all of our natural gas production is sold under spot
contracts that have historically correlated with the swap price.
-18-
<PAGE> 21
As of October 26, 2000, we had entered into commodity price hedging
contracts with respect to our 2000 through 2002 domestic oil production as set
forth below. Some of these contracts were entered into subsequent to
September 30, 2000.
<TABLE>
<CAPTION>
Swaps Collars Floor Contracts
-------------------- ---------------------------------------- -------------------------
Weighted
Average NYMEX
NYMEX Contract Price NYMEX
Contract per Bbl Contract
Volume in Price Volume in ---------------------------- Volume in Price
PERIOD Bbls per Bbl Bbls Floors Ceilings Bbls per Bbl
------------------------------ --------- --------- --------- ------------- ------------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 2000-December 2000.... 736,000 $22.09 184,000 $25.00 $30.05 --- ---
January 2001-March 2001....... 540,000 $21.99 270,000 $25.00 $30.05-$30.75 112,500 $22.17-$26.00
April 2001-June 2001.......... 364,000 $21.70 364,000 $25.00-$27.25 $30.05-$30.75 113,750 $24.17-$26.00
July 2001-September 2001...... 276,000 $22.57 414,000 $24.00-$26.25 $27.30-$32.45 115,000 $24.17-$26.00
October 2001-December 2001.... 276,000 $22.17 345,000 $24.00-$25.25 $27.30-$30.75 115,000 $24.17-$26.00
January 2002-March 2002....... --- --- 517,500 $22.00-$25.00 $25.75-$30.75 --- ---
April 2002-June 2002.......... --- --- 455,000 $22.00-$25.00 $25.75-$30.75 --- ---
July 2002-September 2002...... --- --- 345,000 $23.00-$25.00 $26.75-$30.75 --- ---
October 2002-December 2002.... --- --- 184,000 $25.00 $28.00-$30.75 --- ---
</TABLE>
Because substantially all of our domestic oil production is sold under
spot contracts that have historically correlated to the NYMEX West Texas
Intermediate price, we believe that we have no material basis risk with respect
to these transactions. The actual cash price we receive in the U.S., however,
generally is about $2.00 per barrel less than the NYMEX West Texas Intermediate
price when adjusted for location and quality differences.
Estimated Operating and Financial Data; Operating Activities
We recently introduced a revised home page located at www.newfld.com. In
conjunction with the introduction of our new web page, we also introduced an
electronic publication entitled @NFX. @NFX will be periodically published to
provide updates on our current operating activities. @NFX also includes our
latest publicly announced estimates of expected production volumes, costs and
expenses for the then current quarter. All recent additions of @NFX are
available on our web page. To receive @NFX directly by e-mail, please forward
your e-mail address to [email protected] or visit our web page and sign up.
Forward Looking Information
Certain of the statements set forth in this document regarding planned
capital expenditures, drilling plans, other capital activities and the
financing of capital expenditures are forward looking and are based upon
assumptions and anticipated results that are subject to numerous uncertainties.
Actual results may vary significantly from those anticipated due to many
factors, including drilling results, oil and gas prices, industry conditions,
the prices of goods and services, the availability of drilling rigs and other
support services and the availability of capital resources. In addition, the
drilling of oil and gas wells and the production of hydrocarbons are subject
to governmental regulations and operating risks.
-19-
<PAGE> 22
Commonly Used Oil and Gas Terms
Below are explanations of some commonly used terms in the oil and gas
business.
Basis risk. The risk associated with the sales point price for oil or gas
production varying from the reference (or settlement) price
for a particular hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of
crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined by using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees to
59.5 degrees Fahrenheit.
MBbls. One thousand barrels of crude oil or other liquid
hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
MMBbls. One million barrels of crude oil or other liquid
hydrocarbons.
MMbtu. One million Btus.
MMMbtu. One billion Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
NYMEX. The New York Mercantile Exchange
-20-
<PAGE> 23
Part II
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
27 Financial Data Schedule (included only in the electronic
filing of this document)
(b) Reports on Form 8-K:
None.
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<PAGE> 24
SIGNATURE
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.
NEWFIELD EXPLORATION COMPANY
Date: October 26, 2000 By: /s/ TERRY W. RATHERT
--------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)
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<PAGE> 25
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description of Exhibits
--------- -----------------------
<S> <C>
27 Financial Data Schedule (included
only in the electronic filing of
this document)
</TABLE>
