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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q/A
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
Commission file number 1-12534
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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 and Zip Code of principal executive offices)
Registrant's telephone number, including area code: (281) 847-6000
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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 November 1, 2001, there were 43,990,178 shares of the Registrant's Common
Stock, par value $0.01 per share, outstanding.
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EXPLANATORY NOTE
The Company is re-filing its third quarter 2001 10-Q to add the
following sentence to Note 2, "Oil and Gas Properties" and under "General" in
Management's Discussion and Analysis; "No consideration of the value of
production associated with proved oil and gas properties which has been hedged
against fluctuations in oil and gas prices in financial markets can be
attributed to the value of such properties in determining the limitation on net
capitalized costs."
No other changes have been made to the Company's consolidated financial
statements.
TABLE OF CONTENTS
PART I
Page
----
Item 1. Financial Statements:
Consolidated Balance Sheet as of September 30, 2001
and December 31, 2000 ..................................... 1
Consolidated Statement of Income for the three and nine months
ended September 30, 2001 and 2000 ......................... 2
Consolidated Statement of Cash Flows for the
nine months ended September 30, 2001 and 2000 ............. 3
Consolidated Statement of Stockholders' Equity
for the nine months ended September 30, 2001 .............. 4
Notes to Consolidated Financial Statements ................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations .......................... 15
PART II
Item 6. Exhibits and Reports on Form 8-K ............................... 24
-ii-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
September 30, December 31,
2001 2000
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents ...................... $ 33,195 $ 18,451
Accounts receivable-oil and gas ................ 103,641 147,643
Inventories .................................... 10,796 7,572
Commodity derivatives .......................... 75,001 --
Other current assets ........................... 13,347 5,891
------------- ------------
Total current assets ......................... 235,980 179,557
------------- ------------
Oil and gas properties (full cost method, of which
$161,656 at September 30, 2001 and $106,783 at
December 31, 2000 were excluded from
amortization) .................................. 2,434,784 1,589,150
Less-accumulated depreciation, depletion and
amortization ................................... (961,427) (756,243)
------------- ------------
1,473,357 832,907
------------- ------------
Furniture, fixtures and equipment, net ........... 7,049 4,028
Commodity derivatives ............................ 16,254 --
Other assets ..................................... 10,260 6,758
------------- ------------
Total assets ................................. $ 1,742,900 $ 1,023,250
============= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ............................... $ 7,101 $ 10,209
Other accrued liabilities ...................... 162,817 128,190
Advances from joint owners ..................... 2,085 2,661
Commodity derivatives .......................... 4,719 --
------------- ------------
Total current liabilities .................... 176,722 141,060
------------- ------------
Other liabilities ................................ 7,926 6,030
Commodity derivatives ............................ 3,117 --
Long-term debt ................................... 393,620 133,711
Deferred taxes ................................... 258,603 79,244
------------- ------------
Total long-term liabilities .................. 663,266 218,985
------------- ------------
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; 44,792,809 and
42,625,764 shares issued at September 30, 2001
and December 31, 2000, respectively) ......... 448 426
Additional paid-in capital ....................... 361,663 286,811
Treasury stock (at cost, 859,431 and 18,463
shares at September 30, 2001 and December 31,
2000, respectively) ............................ (25,751) (399)
Unearned compensation ............................ (8,535) (6,201)
Accumulated other comprehensive income (loss) -
Foreign currency translation adjustment ........ (8,106) (4,644)
Commodity derivatives .......................... 37,917 --
Retained earnings ................................ 401,526 243,462
------------- ------------
Total stockholders' equity ................... 759,162 519,455
------------- ------------
Total liabilities and stockholders' equity ... $ 1,742,900 $ 1,023,250
============= ============
The accompanying notes to consolidated financial statements
are an integral part of this financial statement.
-1-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In thousands, except per share data)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Oil and gas revenues .................................. $ 183,259 $ 150,431 $ 593,332 $ 362,957
---------- ---------- ---------- ----------
Operating expenses:
Lease operating ..................................... 30,245 17,780 73,819 47,520
Production and other taxes .......................... 3,311 1,802 15,892 3,801
Transportation ...................................... 1,325 1,568 4,150 4,671
Depreciation, depletion and amortization ............ 74,259 50,989 206,982 138,382
Ceiling test write-down ............................. -- 503 -- 503
General and administrative (includes non-cash
stock compensation of $729 and $767 for the
three months ended September 30, 2001 and 2000,
respectively, and $2,027 and $2,262 for the
nine months ended September 30, 2001 and 2000,
respectively) ..................................... 12,135 8,803 35,359 22,901
---------- ---------- ---------- ----------
Total operating expenses .......................... 121,275 81,445 336,202 217,778
---------- ---------- ---------- ----------
Income from operations ................................ 61,984 68,986 257,130 145,179
Other income (expenses):
Interest income ..................................... 316 580 1,458 1,502
Interest expense .................................... (6,897) (3,815) (20,520) (11,552)
Capitalized interest ................................ 2,354 1,374 6,508 3,938
Dividends on convertible preferred
securities of Newfield Financial Trust I .......... (2,336) (2,336) (7,008) (7,008)
Unrealized commodity derivative income .............. 11,101 -- 15,262 --
---------- ---------- ---------- ----------
4,538 (4,197) (4,300) (13,120)
---------- ---------- ---------- ----------
Income before income taxes ............................ 66,522 64,789 252,830 132,059
Income tax provision:
Current ............................................. 473 8,447 30,961 22,894
Deferred ............................................ 23,073 12,790 59,011 21,014
---------- ---------- ---------- ----------
23,546 21,237 89,972 43,908
---------- ---------- ---------- ----------
Income before cumulative effect of change in
accounting principles ............................... 42,976 43,552 162,858 88,151
Cumulative effect of change in accounting
principles, net of tax
Adoption of SAB 101 ............................... -- -- -- (2,360)
Adoption of SFAS 133 .............................. -- -- (4,794) --
---------- ---------- ---------- ----------
Net income ............................................ $ 42,976 $ 43,552 $ 158,064 $ 85,791
========== ========== ========== ==========
Earnings per share
Basic -
Income before cumulative effect of
change in accounting principles ................. $ 0.97 $ 1.02 $ 3.67 $ 2.09
Cumulative effect of change in
accounting principles ........................... -- -- (0.11) (0.06)
---------- ---------- ---------- ----------
Net income ........................................ $ 0.97 $ 1.02 $ 3.56 $ 2.03
========== ========== ========== ==========
Diluted -
Income before cumulative effect of
change in accounting principles ................. $ 0.91 $ 0.95 $ 3.42 $ 1.97
Cumulative effect of change in
accounting principles ........................... -- -- (0.10) (0.05)
---------- ---------- ---------- ----------
Net income ........................................ $ 0.91 $ 0.95 $ 3.32 $ 1.92
========== ========== ========== ==========
Weighted average number of shares outstanding
for basic earnings per share ....................... 44,219 42,493 44,344 42,260
========== ========== ========== ==========
Weighted average number of shares outstanding
for diluted earnings per share ..................... 48,798 47,366 49,014 47,158
========== ========== ========== ==========
The accompanying notes to consolidated financial statements
are an integral part of this financial statement.
-2-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended
September 30,
----------------------------
2001 2000
------------ ------------
Cash flows from operating activities:
Net income .................................. $ 158,064 $ 85,791
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion
and amortization ........................ 206,982 138,382
Deferred taxes ............................ 59,011 21,014
Stock compensation ........................ 2,027 2,262
Unrealized commodity derivative income .... (15,262) --
Cumulative effect of change in
accounting principles ................... 4,794 2,360
Ceiling test write-down ................... -- 503
------------ ------------
415,616 250,312
Changes in assets and liabilities, net of
business acquired:
(Increase) decrease in accounts receivable-
oil and gas ............................. 72,640 (28,341)
Increase in inventories ................... (4,142) (4,992)
Increase in other current assets .......... (8,421) (810)
(Increase) decrease in other assets ....... (8,212) 477
Increase (decrease) in accounts payable
and accrued liabilities ................. (5,797) 28,592
Increase (decrease) in advances from
joint owners ............................ (576) 5,845
Increase (decrease) in other liabilities .. 1,983 (3,536)
------------ ------------
Net cash provided by
operating activities .................. 463,091 247,547
------------ ------------
Cash flows from investing activities:
Acquisition of Lariat Petroleum,
net of cash acquired .................... (264,089) --
Additions to oil and gas properties ....... (417,806) (287,781)
Additions to furniture, fixtures and
equipment ............................... (3,468) (1,097)
------------ ------------
Net cash used in investing activities ... (685,363) (288,878)
------------ ------------
Cash flows from financing activities:
Proceeds from borrowings .................. 1,110,000 158,000
Repayments of borrowings .................. (1,025,000) (120,000)
Proceeds from issuance of senior notes .... 174,879 --
Proceeds from issuance of common
stock, net ............................... 1,795 5,875
Purchases of treasury stock ............... (25,352) --
------------ ------------
Net cash provided by financing
activities ............................ 236,322 43,875
------------ ------------
Effect of exchange rate changes on cash and
cash equivalents .......................... 694 (432)
------------ ------------
Increase in cash and cash equivalents ........... 14,744 2,112
Cash and cash equivalents, beginning of period .. 18,451 41,841
------------ ------------
Cash and cash equivalents, end of period ........ $ 33,195 $ 43,953
============ ============
The accompanying notes to consolidated financial statements
are an integral part of this financial statement.
-3-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In thousands, except share data)
(Unaudited)
Accumulated
Common Stock Additional Treasury Stock Other
------------------ Paid-in ----------------- Unearned Retained Comprehensive
Shares Amount Capital Shares Amount Compensation Earnings Income (Loss)
---------- ------ ---------- ------- ------- ------------ -------- -------------
Balance, December 31,
2000 ..................... 42,625,764 $ 426 $ 286,811 (18,463) $ (399) $ (6,201) $243,462 $ (4,644)
Issuance of common
stock .................. 2,047,077 21 69,628
Purchase of treasury
stock ..................
Issuance of
restricted stock,
less amortization
of $589 ................ 119,968 1 4,359 (3,771)
Treasury Stock ............. (840,968) (25,352)
Cancellation of
restricted stock ......
Amortization of stock
compensation ........... 1,437
Tax benefit from
exercise of
stock options .......... 865
Comprehensive Income:
Net income ............... 158,064
Foreign currency
translation
adjustment ............. (3,462)
Cumulative effect of
accounting change,
net of tax of $39,964 .. (74,218)
Reclassification
adjustments for
settled contracts,
net of tax of
$24,242 ................ 45,021
Changes in fair value
of outstanding
hedging positions,
net of tax of
$36,138 ................ 67,114
Total
Comprehensive
Income ...........
---------- ------ ---------- -------- -------- ------------ -------- -------------
Balance, September 30,
2001 ...................... 44,792,809 $ 448 $ 361,663 (859,431) $(25,751) $ (8,535) $401,526 $ 29,811
========== ====== ========== ======== ======== ============ ======== =============
Total
Stockholders'
Equity
-------------
Balance, December 31,
2000 ..................... $ 519,455
Issuance of common
stock .................. 69,649
Purchase of treasury
stock ..................
Issuance of
restricted stock,
less amortization
of $589 ................ 589
Treasury Stock ............. (25,352)
Cancellation of
restricted stock ......
Amortization of stock
compensation ........... 1,437
Tax benefit from
exercise of
stock options .......... 865
Comprehensive Income:
Net income ............... 158,064
Foreign currency
translation
adjustment ............. (3,462)
Cumulative effect of
accounting change,
net of tax of $39,964 .. (74,218)
Reclassification
adjustments for
settled contracts,
net of tax of
$24,242 ................ 45,021
Changes in fair value
of outstanding
hedging positions,
net of tax of
$36,138 ................ 67,114
-------------
Total
Comprehensive
Income ........... 192,519
-------------
Balance, September 30,
2001 ...................... $ 759,162
=============
The accompanying notes to consolidated financial statements
are an integral part of this financial statement.
-4-
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
statements for the periods presented. 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. Certain reclassifications have been made to prior year's reported amounts
in order to conform to the current year presentation.
In the fourth quarter of 2000 we adopted SEC Staff Accounting Bulletin
(SAB) No. 101, "Revenue Recognition in Financial Statements." SAB No. 101
requires us to report crude oil inventory associated with our Australian
offshore operations at lower of cost or market, which is a change from our
historical policy of recording such inventory at market value on the balance
sheet date, net of estimated costs to sell. The cumulative effect of the change
from the acquisition date of our Australian operations in July 1999 through
December 31, 1999 is a reduction in net income of $2.36 million,or $0.05 per
diluted share, and is shown as the cumulative effect of change in accounting
principle on our consolidated statement of income for the nine month period
ended September 30, 2000. The adoption of SAB No. 101 does not affect any
period prior to our acquisition in Australia.
As a result of the adoption of Emerging Issues Task Force (EITF) No.
00-10, "Accounting for Shipping and Handling Fees and Costs," we have
reclassified to operating expenses, for all periods presented, third party
costs incurred to transport production to our sales point. Such costs
previously were recorded as a reduction of the related revenues. This
reclassification had no effect on previously reported net income. Approximately
$1.6 million and $4.7 million were reclassified pursuant to EITF No. 00-10 for
the three and nine month periods ended September 30, 2000, respectively.
These consolidated financial statements and the notes thereto should be
read in conjunction with the Company's consolidated financial statements and the
notes thereto for the year ended December 31, 2000 included in the Company's
Current Report on Form 8-K dated October 4, 2001.
Accounting Changes
On January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS Nos. 137 and 138. See Note 6, "Commodity
Derivative Instruments and Hedging Activities."
On June 29, 2001, the Financial Accounting Standards Board ("FASB")
approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets."
Under SFAS 141, all business combinations should be accounted for using
the purchase method of accounting; use of the pooling-of-interests method is
prohibited. The provisions of the statement will apply to all business
combinations initiated after June 30, 2001.
SFAS No. 142 will apply to all acquired intangible assets whether
acquired singly, as part of a group, or in a business combination. The statement
will supersede Accounting Principles Board (APB) Opinion No. 17, "Intangible
Assets," but continue provisions in APB Opinion No. 17 related to internally
developed intangible assets. Adoption of SFAS 142 will result in ceasing
amortization of goodwill. All of the provisions of the statement should be
applied in fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial
position at that date, regardless of when those assets were initially
recognized. The Company does not expect the adoption of these standards to have
a material effect on its consolidated financial statements.
The FASB recently issued SFAS 143, "Accounting for Asset Retirement
Obligations." This statement changes the method of accruing for costs associated
with the retirement of fixed assets (e.g. oil & gas production facilities, etc.)
that an entity is legally obligated to incur. Implementation of this standard is
required no later than January 1, 2003, with earlier application encouraged.
The Company is currently assessing the impact of this standard.
In October 2001, the FASB approved SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", which clarified certain
implementation issues arising from SFAS No. 121, "Accounting for Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of." This standard is
effective for the Company on January 1, 2002. The Company is currently assessing
the impact of this standard.
-5-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Unaudited)
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 each of the three and nine month periods ended September
30, 2001 and 2000.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2001 2000 2001 2000
-------- -------- -------- --------
(In thousands, except per share data):
Income (numerator):
Income - basic .......................... $ 42,976 $ 43,552 $158,064 $ 85,791
After tax dividends on convertible
trust preferred securities ........... 1,518 1,518 4,555 4,555
-------- -------- -------- --------
Income - diluted ........................ $ 44,494 $ 45,070 $162,619 $ 90,346
======== ======== ======== ========
Shares (denominator):
Shares - basic .......................... 44,219 42,493 44,344 42,260
Dilution effect of stock options
outstanding at end of period .......... 656 950 747 975
Dilution effect of convertible
trust preferred securities ............ 3,923 3,923 3,923 3,923
-------- -------- -------- --------
Shared - diluted ........................ 48,798 47,366 49,014 47,158
======== ======== ======== ========
Earnings per share:
Basic .................................. $ 0.97 $ 1.02 $ 3.56 $ 2.03
Diluted ................................ $ 0.91 $ 0.95 $ 3.32 $ 1.92
The calculation of shares outstanding for diluted EPS above does not include the
effect of outstanding stock options to purchase 1,026,000 and 66,500 shares for
the three months ended September 30, 2001 and 2000, respectively, and 850,000
and 86,500 for the nine months ended September 30, 2001 and 2000, respectively,
because to do so would have been antidilutive.
-6-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
Hedging
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires
enterprises to recognize all derivatives as either assets or liabilities on
their balance sheet and measure those instruments at fair value. See Note 6 -
"Commodity Derivative Instruments and Hedging Activities."
For all periods prior to January 1, 2001, the Company accounted for
commodity price hedging contracts in accordance with SFAS No. 80. Pursuant to
SFAS No. 80, gains and losses on these contracts were recognized in revenue in
the period in which the underlying production was delivered. Hedging contracts
were measured for correlation at both the inception of the contract and on an
ongoing basis. If a contract ceased to meet the criteria for deferral
accounting, any subsequent gains or losses were recognized in revenue. If a
hedging contract was terminated prior to maturity, resulting gains and losses
were deferred until the hedged item was recognized in revenue. Neither the
hedging contracts nor the unrealized gains or losses on these contracts were
recognized in the financial statements.
(2) Oil and Gas Properties
The Company uses 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, the net capitalized costs are
amortized on a unit-of-production method based on proved reserves. For each cost
center, 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% per annum discount rate) of estimated future net revenues
from proved reserves, based on the oil and gas prices in effect on the balance
sheet date; 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. No consideration
of the value of production associated with proved oil and gas properties which
has been hedged against fluctuations in oil and gas prices in financial markets
can be attributed to the value of such properties in determining the limitation
on net capitalized costs. If net capitalized costs of oil and gas properties
exceed the cost center ceiling, the Company is 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
stockholder's equity in the period of occurrence and result in lower
depreciation, depletion and amortization expense in future periods.
The risk that the Company will be required to writedown the carrying
value of its oil and gas properties increases when oil and gas prices are
depressed or if the Company has substantial downward revisions in its estimated
proved reserves. Application of these rules during periods of relatively low oil
or gas prices, even if temporary, increases the probability of a ceiling test
writedown. Based on oil and gas prices in effect on September 30, 2001 ($1.90
per MMBtu for gas and $23.37 per barrel for oil), the unamortized cost of the
Company's domestic oil and gas properties exceeded the cost center ceiling from
its proved oil and gas reserves. However, the Company was not required to adjust
its net capitalized costs downward because oil and gas prices increased
sufficiently after September 30, 2001 so that its unamortized costs did not
exceed the cost center ceiling.
(3) Acquisitions
On January 23, 2001, the Company acquired all of the outstanding
capital stock of Lariat Petroleum, Inc. ("Lariat") by merging Lariat with and
into Newfield Exploration Mid-Continent Inc., a wholly owned subsidiary of the
Company. The total consideration for the acquisition was approximately $333
million, consisting of $68 million in Newfield stock and $265 million in cash
funded through the Company's credit facility. The Company also assumed debt and
certain other obligations of Lariat.
-7-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
In February 2000, the Company acquired interests in three producing gas
fields in South Texas for approximately $137 million in cash.
The acquisitions have been accounted for as purchases and, accordingly,
income and expenses for Lariat and from the South Texas 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
acquisitions occurred on January 1 of the respective periods are as follow (in
thousands, except per share amounts):
Nine Months Ended
September 30,
------------------------
2001 2000
---------- ----------
Pro forma Pro forma
(Unaudited)
Revenue .......................................... $ 598,974 $ 414,867
Income from operations ........................... 258,271 158,064
Income before cumulative effect of change
in accounting principles ....................... 162,640 87,989
Cumulative effect of change in accounting
principles ..................................... (4,794) (2,360)
Net income ....................................... 157,846 85,629
Basic earnings per common share before
cumulative effect of change in accounting
principle ...................................... $ 3.67 $ 1.99
Basic earnings per common share .................. $ 3.56 $ 1.94
Diluted earnings per common share before
cumulative effect of change in accounting
principle ...................................... $ 3.41 $ 1.87
Diluted earnings per common share ................ $ 3.31 $ 1.84
The pro forma financial information does not purport to be indicative
of the results of operations that would have occurred had the acquisitions taken
place at the beginning of the periods presented or future results of operations.
(4) 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.
-8-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(5) Geographic Information
Other
United States Australia International Total
------------- ------------ ------------- ------------
(In thousands)
Three months ended September 30, 2001
Oil and gas revenues ........................ $ 174,126 $ 9,133 $ -- $ 183,259
Operating expenses:
Lease operating ........................... 26,097 4,148 -- 30,245
Production and other taxes ................ 3,357 (46) -- 3,311
Transportation ............................ 1,325 -- -- 1,325
Depreciation, depletion and
amortization ............................ 72,075 2,184 -- 74,259
Allocated income taxes .................... 24,945 854 --
------------ ------------ ------------
Net income from oil and
gas operations ....................... $ 46,327 $ 1,993 $ --
============ ============ ============
General and administrative
(inclusive of stock
compensation) ......................... 12,135
------------
Total operating expenses .......... 121,275
------------
Income from operations ...................... 61,984
Interest expense and
dividends, net ......................... (6,563)
Unrealized commodity derivative
income ................................. 11,101
------------
Income before income taxes .................. $ 66,522
============
Total long-lived assets ..................... $ 1,437,434 $ 11,425 $ 24,498 $ 1,473,357
============ ============ ============ ============
Additions to long-lived assets .............. $ 157,563 $ 4,391 $ 3,146 $ 165,100
============ ============ ============ ============
Three months ended September 30, 2000
Oil and gas revenues ........................ $ 138,635 $ 11,796 $ -- $ 150,431
Operating expenses:
Lease operating ........................... 14,919 2,861 -- 17,780
Production and other taxes ................ 1,263 539 -- 1,802
Transportation ............................ 1,568 -- -- 1,568
Depreciation, depletion and
amortization ........................... 49,378 1,611 -- 50,989
Ceiling test write-down ................... -- -- 503 503
Allocated income taxes .................... 25,027 2,036 -- --
------------ ------------ ------------
Net income from oil and
gas operations ....................... $ 46,480 $ 4,749 $ (503)
============ ============ ============
General and administrative
(inclusive of stock
compensation) ......................... 8,803
------------
Total operating expenses .......... 81,445
------------
Income from operations ...................... 68,986
Interest expense and
dividends, net ......................... (4,197)
------------
Income before income taxes .................. $ 64,789
============
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
============ ============ ============ ============
-9-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
Other
United States Australia International Total
------------- ------------ ------------- ------------
(In thousands)
Nine months ended September 30, 2001
Oil and gas revenues ................... $ 568,324 $ 25,008 $ -- $ 593,332
Operating expenses:
Lease operating ...................... 62,890 10,929 -- 73,819
Production and other taxes ........... 12,217 3,675 -- 15,892
Transportation ....................... 4,150 -- -- 4,150
Depreciation, depletion and
amortization ....................... 201,850 5,132 -- 206,982
Allocated income taxes ............... 100,526 1,582 --
------------- ------------ -------------
Net income from oil and
gas operations .................. $ 186,691 $ 3,690 $ --
============= ============ ============
General and administrative
(inclusive of stock
compensation) .................... 35,359
------------
Total operating expenses ..... 336,202
------------
Income from operations ................. 257,130
Interest expense and
dividends, net .................... (19,562)
Unrealized commodity derivative
income ............................ 15,262
------------
Income before income taxes ............. $ 252,830
============
Total long-lived assets ................ $ 1,437,434 $ 11,425 $ 24,498 $ 1,473,357
============= ============ ============= ============
Additions to long-lived assets ......... $ 831,641 $ 5,739 $ 8,254 $ 845,634
============= ============ ============= ============
Nine months ended September 30, 2000
Oil and gas revenues ................... $ 331,588 $ 31,369 $ -- $ 362,957
Operating expenses:
Lease operating ...................... 38,445 9,075 -- 47,520
Production and other taxes ........... 3,252 549 -- 3,801
Transportation ....................... 4,671 -- -- 4,671
Depreciation, depletion and
amortization ...................... 133,695 4,687 -- 138,382
Ceiling test write-down .............. -- -- 503 503
Allocated income taxes ............... 53,034 5,117 --
------------- ------------ -------------
Net income from oil and
gas operations .................. $ 98,491 $ 11,941 $ (503)
============= ============ =============
General and administrative
(inclusive of stock
compensation) .................... 22,901
------------
Total operating expenses ..... 217,778
------------
Income from operations ................. 145,179
Interest expense and
dividends, net .................... (13,120)
------------
Income before income taxes ............. $ 132,059
============
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
============= ============ ============= ============
-10-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(6) Commodity Derivative Instruments and Hedging Activities
The Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended by SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133, an amendment of FASB Statement No. 133," and SFAS No.
138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of FASB Statement No. 133," on January 1, 2001. In
accordance with the transition provisions of SFAS No. 133, on January 1, 2001,
the Company recorded as cumulative effect adjustments a loss of $74.2 million
(net of tax of $40.0 million) in accumulated other comprehensive loss and a loss
of $4.8 million (net of tax of $2.6 million) in 2001 earnings. In addition, the
adoption resulted in the recognition of $17.7 million of derivative assets and
$139.3 million of derivative liabilities on the balance sheet on January 1,
2001.
The Company maintains a commodity-price risk management strategy that
utilizes derivative instruments in order to hedge against the variability in
cash flows associated with the forecasted sale of its oil and gas production.
While the use of these derivative instruments limits the downside risk of
adverse price movements, they may also limit future revenues from favorable
price movements. The use of derivatives also involves the risk that the counter
parties to such instruments will be unable to meet the financial terms of such
contracts.
All derivatives are recognized on the balance sheet at their fair
value. On the date that the Company enters into a derivative contract, it
designates the derivative as a hedge of the variability in cash flows associated
with the forecasted sale of its oil and gas production. Changes in the fair
value of a derivative that is highly effective as and that is designated and
qualifies as a cash flow hedge, to the extent that the hedge is effective, are
recorded in other comprehensive income (loss), until earnings are affected by
the variability of cash flows of the hedged transaction (e.g., until the sale of
the Company's oil and gas production is recorded in earnings). Such gains or
losses are reported in oil and gas revenues on the consolidated statement of
income. For the nine months ended September 30, 2001, the Company had the
following activity in the "Commodity derivatives" component of accumulated other
comprehensive income (loss) (in thousands):
Cumulative effect of accounting change, net of tax ......... $(74,218)
Reclassification adjustments for settled contracts,
net of tax ............................................... 45,021
Change in fair value of outstanding hedging positions,
net of tax ............................................... 67,114
--------
$ 37,917
========
The Company expects that within the next twelve months it will
reclassify to earnings $50.4 million in after tax gains out of the net $37.9
million in after tax gains recorded in accumulated other comprehensive income at
September 30, 2001.
-11-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
Any hedge ineffectiveness (which represents the amount by which the
changes in the fair value of the derivative exceed the variability in the cash
flows of the forecasted transaction) is recorded in current-period earnings. For
the three and nine month periods ended September 30, 2001, the Company recorded
an unrealized gain of $11.1 million and $15.3 million, respectively, under the
income statement caption "Unrealized commodity derivative income" representing
the net of the ineffective portion of the Company's commodity derivative
positions during the three and nine month periods ended September 30, 2001 as
well as the change in the time value component of the option contracts used in
the Company's hedging strategy.
The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk-management objective and
strategy for undertaking various hedge transactions. This process includes
linking all derivatives that are designated as cash flow hedges to the specific
forecasted sale of oil or gas at its physical location. The Company also
formally assesses (both at the hedge's inception and on an ongoing basis)
whether the derivatives that are used in hedging transactions have been highly
effective in offsetting changes in the cash flows of hedged items and whether
those derivatives may be expected to remain highly effective in future periods.
If it is determined that a derivative is not (or has ceased to be) highly
effective as a hedge, the Company will discontinue hedge accounting
prospectively. The gain or loss on the derivative will remain in accumulated
other comprehensive income or loss and will be reclassified into earnings when
the forecasted transaction affects earnings. If hedge accounting is discontinued
and the derivative remains outstanding, the Company will carry the derivative at
its fair value on the balance sheet, recognizing all subsequent changes in the
fair value in current-period earnings. Hedge accounting was not discontinued
during the period for any hedging instruments.
SFAS 133 is complex and subject to a potentially wide range of
interpretation in its application. There are currently several issues before the
FASB and the potential exists for additional issues to be brought under its
review. If subsequent FASB interpretations of SFAS 133 are different than the
Company's current interpretation, it is possible that the application of SFAS
133 on the Company's financial statements will be modified.
NATURAL GAS. As of September 30, 2001, the Company had entered into the
commodity derivative instruments set forth in the table below as a cash flow
hedge of the forecasted sale of its U.S. Gulf Coast natural gas production for
2001 through 2003.
NYMEX CONTRACT PRICE PER MMBTU
----------------------------------------------------------------------------
COLLARS
-------------------------------------------
FLOORS CEILINGS FLOOR CONTRACTS
SWAPS --------------------- --------------------- ----------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED FAIR MARKET
PERIOD MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE VALUE(1)
----------------------------- --------- --------- ----------- --------- ---------- --------- ----------- --------- --------------
October 2001 -- December 2001
Price Swap Contracts....... 15,170 $3.86 -- -- -- -- -- -- $23.9 million
Collar Contracts........... 5,140 -- $3.50-$4.75 $3.92 $4.50-$6.00 $5.16 -- -- $ 9.1 million
Floor Contracts ........... 800 -- -- -- -- -- $3.37-$3.66 $3.51 $(0.9 million)
January 2002 -- March 2002
Price Swap Contracts....... 9,050 $3.85 -- -- -- -- -- -- $ 9.2 million
Collar Contracts........... 8,790 -- $3.50-$4.25 $3.79 $4.90-$9.95 $5.81 -- -- $ 9.4 million
April 2002 -- June 2002
Price Swap Contracts ...... 8,600 $3.52 -- -- -- -- -- -- $ 6.3 million
Collar Contracts........... 4,200 -- $3.75-$4.00 $3.98 $4.80-$6.00 $5.33 -- -- $ 5.3 million
July 2002 -- September 2002
Price Swap Contracts ...... 1,200 $3.68 -- -- -- -- -- -- $ 0.9 million
Collar Contracts........... 4,200 -- $3.75-$4.00 $3.98 $4.80-$6.00 $5.32 -- -- $ 5.0 million
October 2002 -- December 2002
Price Swap Contracts....... 1,200 $3.86 -- -- -- -- -- -- $ 0.9 million
Collar Contracts........... 3,300 -- $4.00 $4.00 $4.80-$6.10 $5.27 -- -- $ 3.7 million
January 2003 -- December 2003
Price Swap Contracts....... 1,825 $3.32 -- -- -- -- -- -- $ 0.2 million
----------
(1) Except for October 2001 hedging contracts, fair market value is
calculated using prices derived from NYMEX futures contract prices
existing at September 30, 2001. Because October 2001 NYMEX futures
contracts expired on September 26, 2001, the fair market value of
October 2001 hedging contracts represents the actual settlement value
of such contracts.
-12-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
In connection with the acquisition of Lariat in January 2001, the
Company assumed certain commodity derivative instruments and designated them as
cash flow hedges of the forecasted natural gas sales of the Company's production
in Oklahoma. The table below presents the outstanding derivative instruments as
of September 30, 2001.
CONTRACT PRICE PER MMBTU
------------------------------------
SWAPS COLLARS
VOLUME IN (WEIGHTED ------------------------ FAIR MARKET
PERIOD MMMBTUS AVERAGE) FLOORS CEILINGS VALUE(1)
-------------------------------------------- --------- --------- ----------- ---------- --------------
October 2001 -- December 2001
Price Swap Contracts...................... 2,420 $4.11 -- -- $ 4.5 million
January 2002 -- December 2002
Price Swap Contracts...................... 3,650 $2.62 -- -- $(0.5 million)
January 2003 -- March 2003
Price Swap Contracts...................... 900 $2.61 -- -- $(0.5 million)
----------
(1) Except for October 2001 hedging contracts, fair market value is
calculated using prices derived from NYMEX futures contract prices
existing at September 30, 2001. Because October 2001 NYMEX futures
contracts expired on September 26, 2001, the fair market value of
October 2001 hedging contracts represents the actual settlement value
of such contracts.
OIL AND CONDENSATE. As of September 30, 2001, the Company had entered
into commodity derivative instruments set forth in the table below as a cash
flow hedge of the forecasted sale of its U.S. Gulf Coast oil production for 2001
through 2003.
NYMEX CONTRACT PRICE PER BBL
------------------------------------------------------------------------------
COLLARS
---------------------------------------------
FLOORS CEILINGS FLOOR CONTRACTS
SWAPS ---------------------- ---------------------- ----------------------
(WEIGHTED WEIGHTED WEIGHTED WEIGHTED FAIR MARKET
PERIOD BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE VALUE(1)
----------------------------- ------- --------- ------------- -------- ------------- -------- ------------- -------- --------------
October 2001 -- December 2001
Price Swap Contracts....... 570,400 $23.78 -- -- -- -- -- -- $ -- million
Collar Contracts........... 345,000 -- $24.00-$25.25 $24.77 $27.30-$30.75 $29.26 -- -- $ 0.6 million
Floor Contracts............ 400,200 -- -- -- -- -- $21.15-$26.00 $23.85 $ 0.7 million
January 2002 -- March 2002
Price Swap Contracts....... 180,000 $24.92 -- -- -- -- -- -- $ 0.2 million
Collar Contracts........... 818,500 -- $21.00-$25.00 $23.64 $25.75-$30.75 $28.21 -- -- $ 0.9 million
Floor Contracts............ 135,000 -- -- -- -- -- $21.15 $21.15 $ 0.1 million
April 2002 -- June 2002
Price Swap Contracts....... 182,000 $24.92 -- -- -- -- -- -- $ 0.2 million
Collar Contracts........... 728,000 -- $21.00-$25.00 $23.45 $25.75-$30.75 $27.95 -- -- $ 0.9 million
Floor Contracts............ 136,500 -- -- -- -- -- $21.15 $21.15 $ 0.1 million
July 2002 -- September 2002
Price Swap Contracts....... 184,000 $24.92 -- -- -- -- -- -- $ 0.3 million
Collar Contracts........... 713,000 -- $21.00-$25.00 $23.50 $26.75-$30.75 $28.60 -- -- $ 0.9 million
Floor Contracts............ 138,000 -- -- -- -- -- $21.15 $21.15 $ 0.2 million
October 2002 -- December 2002
Price Swap Contracts....... 184,000 $24.92 -- -- -- -- -- -- $ 0.4 million
Collar Contracts........... 583,000 -- $21.00-$25.00 $23.50 $26.75-$30.75 $28.86 -- -- $ 0.8 million
Floor Contracts............ 138,000 -- -- -- -- -- $21.15 $21.15 $ 0.2 million
January 2003 -- March 2003
Price Swap Contracts....... 180,000 $24.92 -- -- -- -- -- -- $ 0.4 million
Collar Contracts........... 90,000 -- $21.00 $21.00 $27.50 $27.50 -- -- $(0.1 million)
Floor Contracts............ 135,000 -- -- -- -- -- $21.15 $21.15 $ 0.3 million
April 2003 -- June 2003
Collar Contracts........... 91,000 -- $21.00 $21.00 $27.50 $27.50 -- -- $(0.1 million)
----------
(1) Except for October 2001 hedging contracts, fair market value is
calculated using prices derived from NYMEX futures contract prices
existing at September 30, 2001. Because October 2001 NYMEX futures
contracts expired on September 20, 2001, the fair market value of
October 2001 hedging contracts represents the actual settlement value
of such contracts.
-13-
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
With respect to any particular swap transaction, the counter party is
required to make a payment to the Company if the settlement price for any
settlement period is less than the swap price for such transaction, and the
Company is required to make payment to the counter party if the settlement price
for any settlement period is greater than the swap price for such transaction.
For any particular collar transaction, the counter party is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction, and the Company is required to make
payment to the counter party if the settlement price for any settlement period
is above the ceiling price of such transaction. For any particular floor
transaction, the counter party is required to make a payment to the Company if
the settlement price for any settlement period is below the floor price for such
transaction. The Company is not required to make any payment in connection with
the settlement of a floor transaction.
(7) Treasury Stock
On May 4, 2001, the Company announced that its Board of Directors
authorized the expenditure of up to $50 million to repurchase shares of the
Company's common stock. As of September 30, 2001, the Company had repurchased
823,000 shares of its common stock under this program for total consideration of
$24.7 million, an average of $29.97 per share. Additional repurchases may be
effected from time to time in accordance with applicable securities laws,
through solicited or unsolicited transactions in the market or in privately
negotiated transactions. No limit was placed on the duration of the repurchase
program. Subject to applicable securities laws, such purchases will be at times
and in amounts as the Company deems appropriate. As of November 1, 2001, no
shares had been purchased during the fourth quarter of 2001.
-14-
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 and access to capital and
on the quantities of oil and gas reserves that may be economically produced.
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 work over and recompletion
activities and the incurrence of expenses related thereto and the timing of
crude oil offloadings from inventory in Australia. Consequently, quarterly
results of operations and cash flows may not be indicative of results for the
full 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. No consideration of the value of production associated with proved
oil and gas properties which has been hedged against fluctuations in oil and gas
prices in financial markets can be attributed to the value of such properties in
determining the limitation on net capitalized costs. If net capitalized costs of
oil and gas properties exceed the cost center ceiling, 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 and result in lower
depreciation, depletion and amortization expense in future periods.
The risk that we will be required to writedown the carrying value of
our oil and gas properties increases when oil and gas prices are depressed or if
we have substantial downward revisions in our estimated proved reserves.
Application of these rules during periods of relatively low oil or gas prices,
even if temporary, increases the probability of a ceiling test writedown. Based
on oil and gas prices in effect on September 30, 2001 ($1.90 per MMBtu for gas
and $23.37 per barrel for oil), the unamortized cost of our domestic oil and gas
properties exceeded the cost center ceiling from our proved oil and gas
reserves. However, we were not required to adjust our net capitalized costs
downward because oil and gas prices increased sufficiently after September 30,
2001 so that our unamortized costs did not exceed the cost center ceiling.
Because of the volatility of oil and gas prices and, in particular, the
relatively low recent prices for oil and gas, no assurance can be given that we
will not experience a ceiling test writedown in future quarterly periods. If,
for purposes of determining the net present of our domestic proved reserves at
September 30, 2001, we had used prices of $2.25 per MMBtu for gas and $21.00 per
barrel for oil, we would have recorded a domestic ceiling test writedown of as
much as $200 million in the third quarter. As recently as October 25, 2001,
relevant benchmark prices were $2.68 per MMBtu for gas (Gas Daily-Henry Hub) and
$21.61 per barrel for oil (Platt's - WTI at Cushing).
We adopted Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities" on January 1,
2001. Please see the discussion in Note 6, "Commodity Derivative Instruments and
Hedging Activities," to our consolidated financial statements appearing earlier
in this report.
In the fourth quarter of 2000 we adopted SEC Staff Accounting Bulletin
(SAB) No. 101, "Revenue Recognition in Financial Statements." SAB No. 101
requires us to report crude oil inventory associated with our Australian
offshore operations at lower of cost or market, which is a change from our
historical policy of recording such inventory at market value on the balance
sheet date, net of estimated costs to sell. The cumulative effect of the change
from the acquisition date of our Australian operations in July 1999 through
December 31, 1999 is a reduction in net income of $2.36 million, or $0.05 per
diluted share, and is shown as the cumulative effect of change in accounting
principle on our consolidated statement of income for the nine month period
ended September 30, 2000. The adoption of SAB No. 101 does not affect any period
prior to our acquisition in Australia.
-15-
As a result of the adoption of Emerging Issues Task Force (EITF) No.
00-10, "Accounting for Shipping and Handling Fees and Costs," we have
reclassified to operating expenses, for all periods presented, third party costs
incurred to transport production to our sales point. Such costs previously were
recorded as a reduction of the related revenues. This reclassification had no
effect on previously reported net income. Approximately $1.6 million and $4.7
million were reclassified pursuant to EITF No. 00-10 for the three and nine
month periods ended September 30, 2000, respectively.
On June 29, 2001, the Financial Accounting Standards Board (FASB)
approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets."
Under SFAS No. 141, all business combinations should be accounted for
using the purchase method of accounting; use of the pooling-of-interests method
is prohibited. The provisions of the statement will apply to all business
combinations initiated after June 30, 2001.
SFAS No. 142 will apply to all acquired intangible assets whether
acquired singly, as part of a group or in a business combination. The statement
will supersede Accounting Principles Board (APB) Opinion No. 17, "Intangible
Assets," but continues in APB Opinion No. 17 related to internally developed
intangible assets. Adoption of SFAS No. 142 will result in ceasing amortization
of goodwill. All of the provisions of the statement should be applied in fiscal
years beginning after December 15, 2001 to all goodwill and other intangible
assets recognized in an entity's statement of financial position at that date,
regardless of when those assets were initially recognized.
We do not expect the adoption of these standards to have a material
effect on our consolidated financial statements.
The FASB recently issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement changes the method of accruing for costs associated
with the retirement of fixed assets (e.g. oil & gas production facilities, etc.)
that an entity is legally obligated to incur. Implementation of this standard is
required no later than January 1, 2003, with earlier application encouraged. The
Company is currently assessing the impact of this standard.
In October 2001, the FASB approved SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", which clarified certain
implementation issues arising from SFAS No. 121, "Accounting for Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of." This standard is
effective for the Company on January 1, 2002. The Company is currently assessing
the impact of this standard.
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.
-16-
RESULTS OF OPERATIONS
The following table presents information about our oil and gas production and
realized prices.
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
PRODUCTION:
UNITED STATES
Natural gas (Bcf) ................. 35.0 27.9 101.2 77.5
Oil and condensate (MBbls) ........ 1,418 1,190 4,034 3,064
Total (Bcfe) ...................... 43.5 35.1 125.4 95.9
AUSTRALIA(1)
Oil and condensate (MBbls) ........ 360 372 941 1,084
Total (Bcfe) ...................... 2.2 2.2 5.7 6.5
TOTAL
Natural gas (Bcf) ................. 35.0 27.9 101.2 77.5
Oil and condensate (MBbls) ........ 1,778 1,562 4,975 4,148
Total (Bcfe) ...................... 45.7 37.3 131.1 102.4
AVERAGE REALIZED PRICES:(2)
UNITED STATES
Natural gas (per Mcf) ............. $ 3.94 $ 3.86 $ 4.59 $ 3.29
Oil and condensate (per Bbl) ...... 24.52 24.66 24.55 23.57
AUSTRALIA(2)
Oil and condensate (per Bbl) ...... $ 25.40 $ 31.68 $ 26.58 $ 28.95
TOTAL
Natural gas (per Mcf) ............. $ 3.94 $ 3.86 $ 4.59 $ 3.29
Oil and condensate (per Bbl) ...... 24.70 26.33 24.93 24.97
----------
(1) Represents oil and condensate sold during the period rather
than production.
(2) As discussed above, as the result of the adoption of EITF No.
00-10, we have reclassified third party transportation costs
as operating expenses. Previously, such costs were recorded as
a reduction of the related revenue. However, for purposes of
this table, average realized prices for natural gas and oil
and condensate are presented net of all applicable
transportation expenses, which reduces the realized price of
natural gas by $0.02 and $0.04 for the three months ended
September 30, 2001 and 2000, respectively, and by $0.03 and
$0.05 for the nine months ended September 30, 2001 and 2000,
respectively. The realized price of oil and condensate is
reduced by $0.28 and $0.26 for the three months ended
September 30, 2001 and 2000, respectively, and by $0.27 and
$0.30 for the nine months ended September 30, 2001 and 2000,
respectively. Average realized prices include the effect of
hedges.
PRODUCTION
NATURAL GAS. The increase in gas production was primarily related to the
acquisition of producing properties in South Texas in February 2000, the
acquisition of Lariat Petroleum in January 2001, development projects in the
Gulf of Mexico and the success of our drilling program. Gains in production were
partially offset by natural declines from other producing properties.
CRUDE OIL AND CONDENSATE. The increase in oil and condensate production is
mainly due to the acquisition of Lariat Petroleum in January 2001 and
development projects at Vermilion 215 and Eugene Island 198/199/202. These
increases were offset during the nine month period ended September 30, 2001 by
the decrease in reported Australian crude oil production caused by the timing of
liftings of crude oil from our two FPSOs.
-17-
EFFECT OF HEDGING ON REALIZED PRICES
Average Realized Prices Ratio of
------------------------- Hedged to
With Without Non-Hedged
Hedge Hedge Price(1)
---------- ---------- ----------
Natural Gas
Three months ended September 30, 2000..... $ 3.86 $ 4.46 87%
Three months ended September 30, 2001..... $ 3.94 $ 2.83 139%
Nine months ended September 30, 2000...... $ 3.29 $ 3.58 92%
Nine months ended September 30, 2001...... $ 4.59 $ 4.72 97%
Crude Oil and Condensate
Three months ended September 30, 2000..... $26.33 $31.29 84%
Three months ended September 30, 2001..... $24.70 $25.30 98%
Nine months ended September 30, 2000...... $24.97 $29.28 85%
Nine months ended September 30, 2001...... $24.93 $26.15 95%
----------
(1) The ratio is determined by dividing the realized price (which includes the
effects of hedging) by the price that otherwise would have been realized without
hedging activities.
OPERATING EXPENSES
The following table presents information about our operating expenses for the
three months ended September 30, 2001 and 2000.
UNIT OF PRODUCTION (PER MCFE) AMOUNT (IN MILLIONS)
--------------------------------- ---------------------------------
Three Months Ended Three Months Ended
September 30, Percentage September 30, Percentage
-------------------- Increase -------------------- Increase
2001 2000 (Decrease) 2001 2000 (Decrease)
-------- -------- ---------- -------- -------- ----------
UNITED STATES
Lease operating ............................... $ 0.60 $ 0.42 43% $ 26,097 $ 14,904 75%
Production and other taxes .................... 0.08 0.04 100% 3,357 1,278 163%
Transportation ................................ 0.03 0.04 (25)% 1,325 1,568 (15)%
Depreciation, depletion and amortization ...... 1.66 1.41 18% 72,075 49,378 46%
General and administrative (exclusive of
stock compensation) ......................... 0.25 0.22 14% 10,971 7,670 43%
AUSTRALIA
Lease operating ............................... $ 1.92 $ 1.29 49% $ 4,148 $ 2,876 44%
Production and other taxes .................... (0.02) 0.23 (109)% (46) 524 (109)%
Transportation ................................ -- -- -- -- -- --
Depreciation, depletion and amortization ...... 1.01 0.72 40% 2,184 1,611 36%
General and administrative (exclusive of
stock compensation) ......................... 0.20 0.16 25% 435 366 19%
TOTAL
Lease operating ............................... $ 0.66 $ 0.48 38% $ 30,245 $ 17,780 70%
Production and other taxes .................... 0.07 0.05 40% 3,311 1,802 84%
Transportation ................................ 0.03 0.04 (25)% 1,325 1,568 (15)%
Depreciation, depletion and amortization ...... 1.63 1.37 19% 74,259 50,989 46%
General and administrative (exclusive of
stock compensation) ......................... 0.25 0.22 14% 11,406 8,036 42%
Operating expenses during the three month period ended September 30, 2001 were
impacted by the following:
- The per unit of production increase in domestic lease operating expense
reflects higher oilfield service and related costs in the Gulf of
Mexico and a non-recurring workover of a well at South Marsh Island 160
of $5.5 million. The 49% increase in our Australian lease operating
expense per Mcfe is due mainly to several non-routine maintenance
operations on our FPSOs during the third quarter of 2001.
- The significant increase in production and other taxes in the third
quarter of 2001 is primarily due to our expanding onshore Gulf Coast
operations and the acquisition of Lariat Petroleum in January 2001
offset by a lower natural gas price environment during the third
quarter of 2001. The decrease in production and other taxes in
Australia is due to revised estimates of such taxes during the third
quarter of 2001 as a result of changes in the timing and amount of
anticipated future capital expenditures in Australia.
- The increase in our domestic depreciation, depletion and amortization
rate is primarily the result of increases in the cost of drilling goods
and services, platform and facilities construction, industry
transportation costs, exploration drilling and the completion of
several higher cost wells.
- The increase in domestic general and administrative expense for the
third quarter of 2001 is due primarily to an increase in salaries for
our growing workforce.
-18-
The following table presents information about our operating expenses for the
nine months ended September 30, 2001 and 2000.
UNIT OF PRODUCTION (PER MCFE) AMOUNT (IN MILLIONS)
-------------------------------- --------------------------------
Nine Months Ended Nine Months Ended
September 30, Percentage September 30, Percentage
------------------- Increase ------------------- Increase
2001 2000 (Decrease) 2001 2000 (Decrease)
-------- -------- ---------- -------- -------- ----------
UNITED STATES
Lease operating ............................... $ 0.50 $ 0.40 25% $ 62,890 $ 38,430 64%
Production and other taxes .................... 0.10 0.03 233% 12,217 3,267 274%
Transportation ................................ 0.03 0.05 (40)% 4,150 4,671 (11)%
Depreciation, depletion and amortization ...... 1.61 1.39 16% 201,850 133,695 51%
General and administrative (exclusive of
stock compensation) ......................... 0.26 0.21 24% 32,463 20,207 61%
AUSTRALIA
Lease operating ............................... $ 1.94 $ 1.40 38% $ 10,929 $ 9,090 20%
Production and other taxes .................... 0.65 0.08 713% 3,675 534 588%
Transportation ................................ -- -- -- -- -- --
Depreciation, depletion and amortization ...... 0.91 0.72 26% 5,132 4,687 9%
General and administrative (exclusive of
stock compensation) ......................... 0.15 0.07 114% 869 432 101%
TOTAL
Lease operating ............................... $ 0.56 $ 0.46 22% $ 73,819 $ 47,520 55%
Production and other taxes .................... 0.12 0.04 200% 15,892 3,801 318%
Transportation ................................ 0.03 0.05 (40)% 4,150 4,671 (11)%
Depreciation, depletion and amortization ...... 1.58 1.35 17% 206,982 138,382 50%
General and administrative (exclusive of
stock compensation) ......................... 0.25 0.20 25% 33,332 20,639 62%
Operating expenses during the nine month period ended September 30, 2001 were
impacted by the following:
- The per unit of production increase in domestic lease operating expense
reflects higher oilfield service and related costs in the Gulf of
Mexico and a non-recurring workover of a well at South Marsh Island
160 of $5.5 million. The 38% increase in our Australian lease operating
expense per Mcfe is due mainly to several non-routine maintenance
operations on our FPSOs during the first nine months 2001 and a
decrease in the volume of liftings of crude oil from the FPSOs, which
resulted in increased expenses and lower production.
- The significant increase in production and other taxes in the nine
months ended September 30, 2001 is primarily due to our expanding
onshore Gulf Coast operations, the acquisition of Lariat Petroleum in
January 2001 and a higher natural gas price environment overall during
the first nine months of 2001. The increase in production and other
taxes in Australia is due to revised estimates of such taxes in 2000 as
a result of changes in the timing of anticipated future capital
expenditures in Australia.
- The increase in our domestic depreciation, depletion and amortization
rate is primarily the result of increases in the cost of drilling goods
and services, platforms and facilities construction, industry
transportation costs and the completion of several higher cost wells.
- The increase in domestic general and administrative expense for the
nine months ended September 30, 2001 is 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 $8.4 million, or
$0.08 per Mcfe, for the nine months ended September 30, 2000, to $12.3
million or $0.09 per Mcfe, for the nine months ended September 30,
2001. The increase in performance based compensation is a result of
higher earnings during the first nine months of 2001 as compared to the
same period of 2000. Performance based pay is limited by profitability.
The significant increase in general and administrative expense on a
unit of production basis in Australia is due to the timing of liftings
from the FPSOs during the first nine months of 2001 as compared to the
same period of 2000.
-19-
INTEREST EXPENSE AND DIVIDENDS
We incur interest expense on our $125 million principal amount 7.45%
Senior Notes due 2007, our $175 million principal amount 7 5/8% Senior Notes due
2011 and on borrowings under our reserve-based revolving credit facility and
money market credit lines. Outstanding borrowings under the credit facility and
money market lines of credit may vary significantly from period to period. We
pay dividends on the 6.5% convertible trust preferred securities we issued in
August 1999.
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
(In millions)
Gross interest expense ................. $ 6.9 $ 3.8 $ 20.5 $ 11.5
Capitalized interest ................... (2.3) (1.4) (6.5) (3.9)
-------- -------- -------- --------
Net interest expense ................... 4.6 2.4 14.0 7.6
Dividends on preferred securities ...... 2.3 2.3 7.0 7.0
-------- -------- -------- --------
Total interest expense and dividends ... $ 6.9 $ 4.7 $ 21.0 $ 14.6
======== ======== ======== ========
Our higher total interest expense for the three and nine month period
ended September 30, 2001 is the result of borrowings in January 2001 to
partially finance the acquisition of Lariat Petroleum. At September 30, 2001,
borrowings under our credit facility and money market lines of credit were $94
million.
UNREALIZED COMMODITY DERIVATIVE INCOME
As a result of our adoption of SFAS No. 133 effective January 1, 2001,
we are now required to record all derivative instruments on the balance sheet at
fair value. The $11.1 million and $15.3 million unrealized income for the three
and nine months ended September 30, 2001, respectively, represent the net of the
ineffective portion of our commodity derivative hedge positions and the change
in the time value component of the option contracts used in our hedging
strategy.
TAXES
The effective tax rate for the three and nine month periods ended
September 30, 2001 was 35% and 36%, respectively, as compared to 33% and 33% for
the comparable periods in 2000. The effective tax rates were slightly greater
than the statutory tax rate in 2001 as a result of state income taxes associated
with the acquisition of Lariat Petroleum.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. We had a working capital surplus of $59.3 million at
September 30, 2001. This compares to a working capital surplus of $38.1 million
at December 31, 2000. Working capital balances may fluctuate from quarter to
quarter to the extent we increase or decrease borrowings under our revolving
credit facility.
CAPITAL RESOURCES. Historically, we have funded our oil and gas
activities through cash flow from operations, equity capital, public debt and
bank borrowings.
DEBT. The banks participating in our facility have committed to lend
the Company up to $425 million. The amount available under the facility is
subject to a calculated borrowing base determined by banks holding 75% of the
aggregate commitments, which is reduced by the aggregate outstanding principal
amount of any senior notes issued by us (currently $300 million). The borrowing
base is currently $510 million and is redetermined at least semi-annually. No
assurances can be given that the banks will not elect to redetermine the
borrowing base in the future. The facility contains restrictions on the
payment of dividends and the incurrence of debt as well as other customary
covenants and restrictions. The facility matures in January 2004. We also have
money market lines of credit with various banks in an amount limited by the
credit facility to $40 million. At September 30, 2001, we had outstanding
borrowings under the credit facility of $70 million and $24 million of
outstanding borrowings under the money market lines of credit. Consequently, at
September 30, 2001, we had approximately $155 million of available capacity
under our credit arrangements.
-20-
CASH FLOW FROM OPERATIONS. Our net cash flow from operations for the
nine months ended September 30, 2001 increased 66% over the comparable period of
2000 to $415.6 million. This increase in cash flow is primarily due to higher
production volumes, significantly higher realized prices and changes in working
capital.
CAPITAL EXPENDITURES. We made capital expenditures of $740.5 million in
the first nine months of 2001. This includes $80.8 million for exploration,
$252.2 million for exploitation and development projects and $407.5 million for
property acquisitions, including the $333 million paid for Lariat Petroleum. We
have budgeted $108 million for capital spending for the remainder of 2001.
Approximately $33 million has been budgeted for domestic exploration projects
and $38 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 2001. 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.
HEDGING
We enter into various commodity price hedging contracts with respect to
a portion of our anticipated future natural gas and crude oil production. During
2000, approximately 45% of our equivalent production was subject to hedge
positions. As of November 1, 2001, approximately 66% of our anticipated
production for 2001 was or is subject to hedge positions. 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 counter parties will be
unable to meet the financial terms of such transactions. Such contracts are
accounted for as derivatives in accordance with SFAS No. 133. Please see the
discussion in Note 6, "Commodity Derivative Instruments and Hedging Activities,"
to our consolidated financial statements appearing earlier in this report.
Historically, we have entered into hedging arrangements with respect to
a portion of our anticipated future production offshore and onshore near the
Gulf Coast. In connection with our acquisition of Lariat Petroleum in January
2001, we assumed natural gas hedges entered into by Lariat with respect to a
portion Of its anticipated future production in Oklahoma.
Please see the tables in Note 6, "Commodity Derivative Instruments and
Hedging Activities," to our consolidated financial statements appearing earlier
in this report for a description of our hedging contracts as of September 30,
2001 and the fair value of those contracts as of that date.
In addition to the hedging contracts described in Note 6, we have
entered into several contracts after September 30, 2001 for both our natural gas
and crude and condensate production. We continue to evaluate additional hedging
transactions for the remainder of 2001 and future years.
NATURAL GAS. Subsequent to September 30, 2001, we have entered into the
commodity derivative instruments set forth in the table below as cash flow
hedges of the forecasted sale of our U.S. Gulf Coast natural gas production for
2001 through 2003.
NYMEX CONTRACT PRICE PER MMBTU
--------------------------------------------------------------------------------
COLLARS
---------------------------------------------
FLOORS CEILINGS FLOOR CONTRACTS
SWAPS --------------------- --------------------- ---------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED
PERIOD MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE
----------------------------- --------- --------- ----------- -------- ----------- -------- --------- --------
October 2001 -- December 2001
Price Swap Contracts....... 1,250 $2.75 -- -- -- -- -- --
Collar Contracts........... 1,000 -- $2.50 $2.50 $3.30 $3.30 -- --
Floor Contracts ........... 1,000 -- -- -- -- -- $2.85 $2.85
January 2002 -- March 2002
Collar Contracts........... 8,250 -- $2.50-$2.85 $2.72 $3.30-$3.56 $3.41 -- --
Floor Contracts ........... 3,000 -- -- -- -- -- $2.85 $2.85
April 2002 -- June 2002
Price Swap Contracts ...... 3,250 $2.76 -- -- -- -- -- --
Collar Contracts........... 4,000 -- $2.50-$3.00 $2.88 $3.30-$4.00 $3.71 -- --
Floor Contracts ........... 1,000 -- -- -- -- -- $2.85 $2.85
January 2003 -- December 2003
Price Swap Contracts....... 7,800 $3.55 -- -- -- -- -- --
Collar Contracts........... 2,400 -- $3.50 $3.50 $3.90 $3.90 -- --
-21-
OIL AND CONDENSATE. Subsequent to September 30, 2001, we have entered
into commodity derivative instruments set forth in the table below as cash flow
hedges of the forecasted sale of our U.S. Gulf Coast oil production for 2002.
NYMEX CONTRACT PRICE PER BBL
---------------------------------------------------------------------------------
COLLARS
------------------------------------------
FLOORS CEILINGS FLOOR CONTRACTS
SWAPS ------------------- ------------------- -------------------
(WEIGHTED WEIGHTED WEIGHTED WEIGHTED
PERIOD BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE
----------------------------- ------ --------- ----- -------- ----- -------- ----- --------
January 2002 -- March 2002
Price Swap Contracts....... 90,000 $22.20 -- -- -- -- -- --
April 2002 -- June 2002
Price Swap Contracts ...... 91,000 $22.20 -- -- -- -- -- --
July 2002 -- September 2002
Price Swap Contracts ...... 92,000 $22.20 -- -- -- -- -- --
October 2002 -- December 2002
Price Swap Contracts....... 61,000 $22.20 -- -- -- -- -- --
STOCK REPURCHASE PROGRAM
On May 4, 2001, we announced that our Board of Directors authorized the
expenditure of up to $50 million to repurchase shares of our common stock. We
purchased 311,000 shares in the third quarter of 2001 under this program for
total consideration of $8.3 million, an average of $26.69 per share. Through
September 30, 2001, we had purchased 823,000 shares for total consideration of
$24.7 million, an average of $29.97 per share. Additional repurchases may be
effected from time to time in accordance with applicable securities laws,
through solicited or unsolicited transactions in the market or in privately
negotiated transactions. No limit was placed on the duration of the repurchase
program. Subject to applicable securities laws, purchases will be at times and
in amounts as we deem appropriate. As of November 1, 2001, no shares had been
purchased during the fourth quarter of 2001.
ESTIMATED OPERATING AND FINANCIAL DATA; OPERATING ACTIVITIES
We continue to maintain our home page located at www.newfld.com. In
conjunction with our web page, we also maintain our 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
pmcknight@newfld.com or visit our web page and sign up.
FORWARD LOOKING INFORMATION.
Certain of the statements set forth in this report 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, the
availability of capital resources and other factors described in our annual
report on Form 10-K for the year ended December 31, 2000. In addition, the
drilling of oil and gas wells and the production of hydrocarbons are subject to
governmental regulations and operating risks.
-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
-23-
Part II
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
None
(b) Reports on Form 8-K:
On October 4, 2001, we filed a Current Report on Form 8-K to file the
financial statements of Lariat Petroleum for the year ended December
31, 2000 and the pro forma combined financial statements of Lariat
Petroleum and Newfield for the year ended December 31, 2000 and the six
months in the period ended June 30, 2001 and to re-file our audited
consolidated financial statements as of December 31, 2000 and 1999 and
for each of the three years in the period ended December 31, 2000 for
the sole purpose of adding a new Note 16.
On October 9, 2001, we filed a current report on Form 8-K announcing
the curtailment of a small portion of our fourth quarter 2001 natural
gas production and the deferral of some capital projects.
-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: November 2, 2001 By: /s/ TERRY W. RATHERT
-----------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)
-25-
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
None
-26-