- --------------------------------------------------------------------------------
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, 2002
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 AND ZIP CODE OF PRINCIPAL EXECUTIVE OFFICES)
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 NOVEMBER 8, 2002, THERE WERE 44,499,736 SHARES OF THE REGISTRANT'S
COMMON STOCK, PAR VALUE $0.01 PER SHARE, OUTSTANDING.
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TABLE OF CONTENTS
PART I
<Table>
<Caption>
Page
Item I. Unaudited Financial Statements:
Consolidated Balance Sheet as of September 30, 2002 and December 31, 2001..... 1
Consolidated Statement of Income for the three and nine months
ended September 30, 2002 and 2001............................................. 2
Consolidated Statement of Cash Flows for the nine months ended
September 30, 2002 and 2001................................................... 3
Consolidated Statement of Stockholders' Equity for the nine
months ended September 30, 2002............................................... 4
Notes to Consolidated Financial Statements.................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................................... 14
Item 4. Controls and Procedures............................................................. 22
PART II
Item 5. Other Information................................................................... 23
Item 6. Exhibits and Reports on Form 8-K.................................................... 23
</Table>
-ii-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
<Table>
<Caption>
September 30, December 31,
2002 2001
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents .............................................. $ 23,694 $ 26,610
Accounts receivable-oil and gas ........................................ 88,936 92,644
Inventories ............................................................ 7,776 7,332
Commodity derivatives .................................................. 6,712 79,012
Other current assets ................................................... 16,276 25,006
Deferred taxes ......................................................... 2,329 --
------------ ------------
Total current assets ............................................... 145,723 230,604
------------ ------------
Oil and gas properties (full cost method, of which $191,859 at
September 30, 2002 and $149,742 at December 31, 2001 were
excluded from amortization) ............................................ 2,688,078 2,443,615
Less-accumulated depreciation, depletion and amortization ................... (1,257,592) (1,035,036)
------------ ------------
1,430,486 1,408,579
------------ ------------
Furniture, fixtures and equipment, net ...................................... 6,748 6,807
Commodity derivatives ....................................................... 663 7,409
Other assets ................................................................ 9,156 9,972
------------ ------------
Total assets ....................................................... $ 1,592,776 $ 1,663,371
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ....................................................... $ 10,817 $ 9,172
Accrued liabilities .................................................... 117,256 122,214
Advances from joint owners ............................................. 173 10
Commodity derivatives .................................................. 19,768 4,217
Deferred taxes ......................................................... -- 29,418
------------ ------------
Total current liabilities .......................................... 148,014 165,031
------------ ------------
Other liabilities ........................................................... 8,493 6,288
Commodity derivatives ....................................................... 2,596 1,813
Long-term debt .............................................................. 360,665 428,631
Deferred taxes .............................................................. 203,578 207,880
------------ ------------
Total long-term liabilities ........................................ 575,332 644,612
------------ ------------
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;
45,323,992 and 44,962,277 shares issued at September 30, 2002
and December 31, 2001, respectively) ............................... 453 449
Additional paid-in capital .................................................. 373,429 364,734
Treasury stock (at cost, 871,480 and 860,755 shares at September 30, 2002
and December 31, 2001, respectively) ................................... (26,161) (25,794)
Unearned compensation ....................................................... (6,965) (7,845)
Accumulated other comprehensive income (loss)
Foreign currency translation adjustment ................................ (6,053) (8,918)
Commodity derivatives .................................................. (13,406) 24,936
Retained earnings ........................................................... 404,383 362,416
------------ ------------
Total stockholders' equity ......................................... 725,680 709,978
------------ ------------
Total liabilities and stockholders' equity ......................... $ 1,592,776 $ 1,663,371
============ ============
</Table>
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)
<Table>
<Caption>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Oil and gas revenues .......................................... $ 152,610 $ 183,259 $ 462,260 $ 593,332
------------ ------------ ------------ ------------
Operating expenses:
Lease operating .......................................... 25,065 30,245 73,824 73,819
Production and other taxes ............................... 5,635 3,311 12,906 15,892
Transportation ........................................... 1,730 1,325 4,377 4,150
Depreciation, depletion and amortization ................. 72,294 74,259 221,528 206,982
General and administrative (includes non-cash stock
compensation of $731 and $729 for the three months
ended September 30, 2002 and 2001, respectively, and
$2,066 and $2,027 for the nine months ended
September 30, 2002 and 2001, respectively) ............. 13,776 12,135 39,084 35,359
------------ ------------ ------------ ------------
Total operating expenses ............................... 118,500 121,275 351,719 336,202
------------ ------------ ------------ ------------
Income from operations ........................................ 34,110 61,984 110,541 257,130
Other income (expenses):
Interest expense ......................................... (7,049) (6,897) (21,397) (20,520)
Capitalized interest ..................................... 2,280 2,354 6,553 6,508
Dividends on convertible preferred securities of
Newfield Financial Trust I ............................. (2,336) (2,336) (7,008) (7,008)
Unrealized commodity derivative income (expense) ......... (13,952) 11,101 (25,477) 15,262
Other .................................................... 1,346 316 1,915 1,458
------------ ------------ ------------ ------------
(19,711) 4,538 (45,414) (4,300)
------------ ------------ ------------ ------------
Income before income taxes .................................... 14,399 66,522 65,127 252,830
Income tax provision (benefit):
Current .................................................. 15,150 473 31,572 30,961
Deferred ................................................. (10,122) 23,073 (8,412) 59,011
------------ ------------ ------------ ------------
5,028 23,546 23,160 89,972
------------ ------------ ------------ ------------
Income before cumulative effect of change in
accounting principle ..................................... 9,371 42,976 41,967 162,858
Cumulative effect of change in accounting principle,
net of tax Adoption of SFAS 133 .......................... -- -- -- (4,794)
------------ ------------ ------------ ------------
Net income .................................................... $ 9,371 $ 42,976 $ 41,967 $ 158,064
============ ============ ============ ============
Earnings per share
Basic-
Income before cumulative effect of change in
accounting principle ................................. $ 0.21 $ 0.97 $ 0.95 $ 3.67
Cumulative effect of change in accounting principle .... -- -- -- (0.11)
------------ ------------ ------------ ------------
Net income ............................................. $ 0.21 $ 0.97 $ 0.95 $ 3.56
============ ============ ============ ============
Diluted-
Income before cumulative effect of change in
accounting principle ................................. $ 0.21 $ 0.91 $ 0.93 $ 3.42
Cumulative effect of change in accounting principle .... -- -- -- (0.10)
------------ ------------ ------------ ------------
Net income ............................................. $ 0.21 $ 0.91 $ 0.93 $ 3.32
============ ============ ============ ============
Weighted average number of shares outstanding for basic
earnings per share ....................................... 44,420 44,219 44,337 44,344
============ ============ ============ ============
Weighted average number of shares outstanding for diluted
earnings per share ....................................... 44,905 48,798 44,910 49,014
============ ============ ============ ============
</Table>
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)
<Table>
<Caption>
Nine Months Ended
September 30,
----------------------------
2002 2001
------------ ------------
Cash flows from operating activities:
Net income .......................................................... $ 41,967 $ 158,064
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization ............................ 221,528 206,982
Deferred taxes ...................................................... (8,412) 59,011
Stock compensation .................................................. 2,066 2,027
Unrealized commodity derivatives .................................... 25,477 (15,262)
Cumulative effect of change in accounting principle ................. -- 4,794
------------ ------------
282,626 415,616
Changes in assets and liabilities:
Decrease (increase) in accounts receivable - oil and gas ............ 4,096 72,640
Decrease (increase) in inventories .................................. 1,254 (4,142)
Decrease (increase) in other current assets ......................... 6,883 (8,421)
Decrease (increase) in other assets ................................. 816 (8,212)
Increase (decrease) in accounts payable and accrued liabilities ..... (2,657) (5,797)
Increase (decrease) in advances from joint owners ................... 164 (576)
Increase (decrease) in other liabilities ............................ 2,183 1,983
------------ ------------
Net cash provided by operating activities ......................... 295,365 463,091
------------ ------------
Cash flows from investing activities:
Acquisition, net of cash acquired ................................... -- (264,089)
Additions to oil and gas properties ................................. (233,586) (417,806)
Additions to furniture, fixtures and equipment ...................... (2,249) (3,468)
------------ ------------
Net cash used in investing activities ............................. (235,835) (685,363)
------------ ------------
Cash flows from financing activities:
Proceeds from borrowings ............................................ 490,000 1,110,000
Repayments of borrowings ............................................ (558,000) (1,025,000)
Proceeds from issuance of senior notes .............................. -- 174,879
Proceeds from issuance of common stock .............................. 5,830 1,795
Purchases of treasury stock ......................................... (366) (25,352)
------------ ------------
Net cash provided by (used in) financing activities ............... (62,536) 236,322
------------ ------------
Effect of exchange rate changes on cash and cash equivalents ............. 90 694
------------ ------------
Increase (decrease) in cash and cash equivalents ......................... (2,916) 14,744
Cash and cash equivalents, beginning of period ........................... 26,610 18,451
------------ ------------
Cash and cash equivalents, end of period ................................. $ 23,694 $ 33,195
============ ============
</Table>
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)
<Table>
<Caption>
Common Stock Treasury Stock Additional
---------------------------- ---------------------------- Paid-in Unearned
Shares Amount Shares Amount Capital Compensation
------------ -------------- ------------ ------------ ------------ ------------
Balance, December 31, 2001 ....... 44,962,277 $ 449 (860,755) $ (25,794) $ 364,734 $ (7,845)
Issuance of common stock ......... 325,919 4 5,826
Issuance of restricted stock,
less amortization
of $342 ....................... 35,796 1,186 (844)
Treasury stock, at cost .......... (10,725) (367)
Amortization of stock
compensation .................. 1,724
Tax benefit from exercise of
stock options ................. 1,683
Comprehensive Income:
Net income .......................
Foreign currency translation
adjustment, net of tax
of $1,542 .....................
Reclassification adjustments
for settled contracts, net
of tax of $7,277 ..............
Changes in fair value of
outstanding hedging
positions, net of tax
of $13,368 ....................
Total comprehensive
income ........................
------------ ------------ ------------ ------------ ------------ ------------
Balance, September 30, 2002 ...... 45,323,992 $ 453 (871,480) $ (26,161) $ 373,429 $ (6,965)
============ ============ ============ ============ ============ ============
<Caption>
Accumulated
Other Total
Retained Comprehensive Stockholders'
Earnings Income (Loss) Equity
------------ ------------- ------------
Balance, December 31, 2001 ...... $ 362,416 $ 16,018 $ 709,978
Issuance of common stock ........ 5,830
Issuance of restricted stock,
less amortization
of $342 ...................... 342
Treasury stock, at cost ......... (367)
Amortization of stock
compensation ................. 1,724
Tax benefit from exercise of
stock options ................ 1,683
Comprehensive Income:
Net income ...................... 41,967 41,967
Foreign currency translation
adjustment, net of tax
of $1,542 .................... 2,864 2,864
Reclassification adjustments
for settled contracts, net
of tax of $7,277 ............. (13,514) (13,514)
Changes in fair value of
outstanding hedging
positions, net of tax
of $13,368 ................... (24,827) (24,827)
------------
Total comprehensive
income ....................... 6,490
------------ ------------ ------------
Balance, September 30, 2002 ..... $ 404,383 $ (19,459) $ 725,680
============ ============ ============
</Table>
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. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
ORGANIZATION AND PRINCIPLES OF CONSOLIDATION
These financial statements include the accounts of Newfield Exploration
Company, a Delaware corporation, and its subsidiaries (collectively, the
"Company"). 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 as of, and results of operations 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.
These consolidated financial statements and the notes hereto should be read
in conjunction with the Company's consolidated financial statements and the
notes thereto for the year ended December 31, 2001 included in the Company's
Annual Report on Form 10-K.
DEPENDENCE ON OIL AND GAS PRICES
As an independent oil and gas producer, the Company's 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 the Company's 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 the Company's 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.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates. The
Company's most significant financial estimates are based on remaining proved oil
and gas reserves.
5
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(Unaudited)
NEW ACCOUNTING STANDARDS
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. This statement will require
that the fair value of the obligation be recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made, and that the
associated asset retirement costs be capitalized as part of the carrying amount
of the asset. The Company plans to implement this standard on January 1, 2003.
The Company is currently assessing the impact of this standard.
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 outstanding stock
options and convertible securities were exercised for or converted into common
stock.
The following is a calculation of basic and diluted earnings per share for
the three and nine month periods ended September 30, 2002 and 2001.
<Table>
<Caption>
Three Month Nine Month
Period Ended Period Ended
September 30, September 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(in thousands, except per share amounts)
Income (numerator):
Income before cumulative effect change
in accounting principle .................... $ 9,371 $ 42,976 $ 41,967 $ 162,858
Cumulative effect change in accounting
principle, net of tax ..................... -- -- -- (4,794)
------------ ------------ ------------ ------------
Income - basic ................................. 9,371 42,976 41,967 158,064
After tax dividends on convertible trust
preferred securities ...................... -- 1,518 -- 4,555
------------ ------------ ------------ ------------
Income - diluted ............................... $ 9,371 $ 44,494 $ 41,967 $ 162,619
============ ============ ============ ============
Shares (denominator):
Shares - basic ................................. 44,420 44,219 44,337 44,344
Dilution effect of stock options outstanding
at end of period ........................... 485 656 573 747
Dilution effect of convertible trust
preferred securities ....................... -- 3,923 -- 3,923
------------ ------------ ------------ ------------
Shares - diluted ............................... 44,905 48,798 44,910 49,014
============ ============ ============ ============
Earnings per share:
Basic before change in accounting principle .... $ 0.21 $ 0.97 $ 0.95 $ 3.67
Basic .......................................... $ 0.21 $ 0.97 $ 0.95 $ 3.56
Diluted before change in accounting principle .. $ 0.21 $ 0.91 $ 0.93 $ 3.42
Diluted ........................................ $ 0.21 $ 0.91 $ 0.93 $ 3.32
</Table>
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 1,519,900 and
1,026,000 shares for the three months ended September 30, 2002 and 2001,
respectively, and 798,100 and 850,000 shares for the nine months ended September
30, 2002 and 2001, respectively, because to do so would have been antidilutive.
Additionally, the calculation of shares outstanding for diluted EPS does not
include the effect of the convertible trust preferred securities outstanding for
the three and nine months ended September 30, 2002, because to do so would have
been antidilutive.
6
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(Unaudited)
2. PROPERTY 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, inclusive of the assumption of debt and certain other obligations of
Lariat. The consideration included the issuance of approximately 1.9 million
shares of the Company's common stock valued at $68 million. For financial
accounting purposes, the Company allocated $438 million to oil and gas
properties, which included a $105 million step-up associated with deferred
income taxes.
This acquisition has been accounted for as a purchase and, accordingly,
income and expenses for Lariat 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 had occurred on January 1, 2001 are as follows (in thousands, except
per share amounts):
<Table>
<Caption>
Nine Months Ended
September 30, 2001
------------------
(unaudited)
Proforma:
Revenue ................................................. $ 598,974
Income from operations .................................. 258,271
Income before cumulative effect of change in
accounting principle ................................. 162,640
Cumulative effect of change in accounting principles .... (4,794)
Net income .............................................. 157,846
Basic earnings per common share before cumulative
effect of change in accounting principle ............. $ 3.67
Basic earnings per common share ......................... $ 3.56
Diluted earnings per common share before cumulative
effect of change in accounting principle ............. $ 3.41
Diluted earnings per common share ....................... $ 3.31
</Table>
The pro forma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisition taken
place at January 1, 2001 or future results of operations.
7
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 that these matters will
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)
4. GEOGRAPHIC INFORMATION:
<Table>
<Caption>
Other
United States Australia International Total
------------- ------------ ------------- ------------
Three Months Ended September 30, 2002
Oil and gas revenues ................................... $ 141,978 $ 10,632 $ -- $ 152,610
Operating expenses:
Lease operating ................................... 20,309 4,756 -- 25,065
Production and other taxes ........................ 3,738 1,897 -- 5,635
Transportation .................................... 1,730 -- -- 1,730
Depreciation, depletion and amortization .......... 69,910 2,384 -- 72,294
Allocated income taxes ............................ 16,202 479 --
------------ ------------ ------------
Net income from oil and gas operations ........ $ 30,089 $ 1,116 $ --
============ ============ ============
General and administrative ........................ 13,776
------------
Total operating expenses ...................... 118,500
------------
Income from operations ................................. 34,110
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (5,759)
Unrealized commodity derivative expense ........... (13,952)
------------
Income before income taxes ............................. $ 14,399
============
Total long-lived assets ................................ $ 1,370,707 $ 24,593 $ 35,186 $ 1,430,486
============ ============ ============ ============
Additions to long-lived assets ......................... $ 151,657 $ 9,654 $ 4,875 $ 166,186
============ ============ ============ ============
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 ........................ 12,135
------------
Total operating expenses ...................... 121,275
------------
Income from operations ................................. 61,984
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (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
============ ============ ============ ============
</Table>
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
<Table>
<Caption>
Other
United States Australia International Total
------------- ------------ ------------- ------------
Nine Months Ended September 30, 2002
Oil and gas revenues ................................... $ 437,926 $ 24,334 $ -- $ 462,260
Operating expenses:
Lease operating ................................... 63,297 10,527 -- 73,824
Production and other taxes ........................ 11,009 1,897 -- 12,906
Transportation .................................... 4,377 -- -- 4,377
Depreciation, depletion and amortization .......... 215,938 5,590 -- 221,528
Allocated income taxes ............................ 50,157 1,896 --
------------ ------------ ------------
Net income from oil and gas operations ........ $ 93,148 $ 4,424 $ --
============ ============ ============
General and administrative ........................ 39,084
------------
Total operating expenses ...................... 351,719
------------
Income from operations ................................. 110,541
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (19,937)
Unrealized commodity derivative expense ........... (25,477)
------------
Income before income taxes ............................. $ 65,127
============
Total long-lived assets ................................ $ 1,370,707 $ 24,593 $ 35,186 $ 1,430,486
============ ============ ============ ============
Additions to long-lived assets ......................... $ 221,991 $ 18,012 $ 6,998 $ 247,001
============ ============ ============ ============
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 ........................ 35,359
------------
Total operating expenses ...................... 336,202
------------
Income from operations ................................. 257,130
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (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
============ ============ ============ ============
</Table>
10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
5. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
The Company maintains a commodity-price risk management strategy that
utilizes derivative instruments, primarily swaps, collars and floor contracts,
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 counterparties to such instruments will be
unable to meet the financial terms of such contracts.
With respect to any particular swap transaction, the counterparty 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 counterparty if 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 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 counterparty if the settlement price for any settlement period is
above the ceiling price of such transaction. For any particular floor contract,
the counterparty 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 contract.
As of January 1, 2001, all derivatives are recognized on the balance sheet
at their fair value. Substantially all of the Company's hedging transactions are
settled based upon reported prices on the NYMEX. The estimated fair value of
these transactions is based upon various factors that include closing exchange
prices on the NYMEX, over-the-counter quotations, volatility and the time value
of options. The calculation of the fair value of collars and floors requires the
use of the Black-Scholes option-pricing model. 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 and 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.
Any hedge ineffectiveness (which represents the amount by which the change
in the fair value of the derivative differs from the change in the cash flows of
the forecasted sale of production) is recorded in current-period earnings. On
January 1, 2002, the Company began assessing hedge effectiveness based on the
total changes in cash flows on its collar and floor contracts as described by
the Derivative Implementation Group (DIG) Issue G20, "Cash Flow Hedges:
Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash
Flow Hedge." Accordingly, prospectively the Company has elected to record
subsequent changes in the fair value, including changes associated with time
value, in accumulated other comprehensive income (loss). Gains or losses on
these collar and floor contracts will be reclassified out of other comprehensive
income (loss) and into earnings when the forecasted sale of production occurs.
For the three and nine month periods ended September 30, 2002, the Company
recorded expense of $14.0 million and $25.5 million, respectively, under the
income statement caption "Unrealized commodity derivative expense." These losses
are associated with the settlement of option contracts during the three and nine
month periods ended September 30, 2002 and primarily reflect the reversal of
time value gains that were previously recognized on these same open option
contracts during 2001, prior to the adoption of DIG Issue G20.
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, then the Company will discontinue hedge accounting
prospectively. The gain or loss on the derivative will remain in accumulated
other
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
comprehensive income (loss) and will be reclassified into earnings when the
forecasted sale of production affects earnings. The Company records
ineffectiveness as a "commodity derivative expense" line item while the
proceeds, net of premiums paid, on the settlement of derivative financial
instruments are recognized in "oil and gas revenues." 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.
NATURAL GAS
As of September 30, 2002, 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 the remainder
of 2002 and for 2003.
<Table>
<Caption>
NYMEX Contract Price Per MMBtu
-----------------------------------------------------------------------------
Collars
---------------------------------------------
Floors Ceilings Floor Contracts
Swaps ---------------------- --------------------- --------------------
Volume in (Weighted Weighted Weighted Weighted Fair Value
Period and Type of Contract MMMBtus Average) Range Average Range Average Range Average (in millions)
- --------------------------- --------- --------- ----------- -------- ----------- -------- ----------- -------- -------------
October 2002 - December 2002
Price Swap Contracts ..... 6,500 $ 4.02 -- -- -- -- -- -- --
Collar Contracts ......... 11,600 -- $2.65-$4.00 $ 3.58 $3.73-$6.10 $ 4.74 -- -- $ 0.2
Floor Contracts .......... 6,950 -- -- -- -- -- $2.88-$3.73 $ 3.54 1.8
January 2003 - March 2003
Price Swap Contracts ..... 6,300 3.84 -- -- -- -- -- -- (2.8)
Collar Contracts ......... 4,050 -- 3.50-3.54 3.51 4.20 - 5.00 4.76 -- -- (0.7)
April 2003 - June 2003
Price Swap Contracts ..... 5,105 3.78 -- -- -- -- -- -- (0.7)
Collar Contracts ......... 4,650 -- 3.50-3.54 3.51 3.90-5.00 4.65 -- -- --
July 2003 - September 2003
Price Swap Contracts ..... 2,410 3.51 -- -- -- -- -- -- (1.0)
Collar Contracts ......... 1,350 -- 3.50 3.50 3.90-4.20 4.00 -- -- (0.3)
October 2003 - December 2003
Price Swap Contracts ..... 2,410 3.51 -- -- -- -- -- -- (1.5)
Collar Contracts ......... 1,350 -- 3.50 3.50 3.90-4.20 4.00 -- -- (0.6)
</Table>
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, 2002.
<Table>
<Caption>
Weighted Average
Volume in Contract Price Fair Value
Period and Type of Contract MMMBtus Per MMBtu (in millions)
- --------------------------- --------- ---------------- -------------
October 2002 - December 2002
Price Swap Contracts.............. 920 $2.61 $(1.2)
January 2003 - March 2003
Price Swap Contracts.............. 900 2.61 (1.5)
</Table>
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
OIL AND CONDENSATE
As of September 30, 2002, 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 oil production for the remainder of 2002
and for 2003.
<Table>
<Caption>
NYMEX Contract Price Per Bbl
------------------------------------------------------------------------------
Collars
----------------------------------------------
Floors Ceilings Floor Contracts
Swaps ---------------------- ---------------------- -------------------
Volume in (Weighted Weighted Weighted Weighted Fair Value
Period and Type of Contract Bbls Average) Range Average Range Average Range Average (in millions)
- --------------------------- --------- --------- ------------- -------- ------------ -------- ------- -------- -------------
October 2002 - December 2002
Price Swap Contracts ..... 336,000 $ 24.57 -- -- -- -- -- -- $ (2.0)
Collar Contracts ......... 552,000 -- $21.00-$25.00 $ 22.83 $27.50-$30.75 $ 29.03 -- -- (1.3)
Floor Contracts .......... 138,000 -- -- -- -- -- $ 21.15 $ 21.15 --
January 2003 - March 2003
Price Swap Contracts ..... 300,000 25.08 -- -- -- -- -- -- (1.2)
Collar Contracts ......... 270,000 -- 20.00-24.00 22.00 27.46-28.25 27.77 -- -- (0.8)
Floor Contracts .......... 135,000 -- -- -- -- -- 21.15 21.15 --
April 2003 - June 2003
Price Swap Contracts ..... 165,000 25.35 -- -- -- -- -- -- (0.3)
Collar Contracts ......... 496,000 -- 20.00-24.00 22.09 27.25-28.25 27.66 -- -- (0.9)
July 2003 - September 2003
Price Swap Contracts ..... 145,000 25.36 -- -- -- -- -- -- --
Collar Contracts ......... 305,000 -- 22.00-24.00 22.61 27.25-28.25 27.67 -- -- (0.3)
October 2003 - December 2003
Price Swap Contracts ..... 105,000 25.40 -- -- -- -- -- -- 0.1
Collar Contracts ......... 105,000 -- 23.00 23.00 27.46-27.50 27.48 -- -- --
</Table>
6. PENDING EEX ACQUISITION AND RELATED FINANCING:
On May 29, 2002, the Company announced its agreement to acquire EEX
Corporation, an independent oil and gas exploration and production company with
activities focused in Texas, Louisiana and the Gulf of Mexico. The transaction
is valued at approximately $650 million, including the assumption of
approximately $400 million of debt. The Company will issue approximately 7.1
million shares of its common stock in the transaction, or approximately 12.4% of
its outstanding common stock on a fully diluted basis following the closing of
the transaction.
The acquisition is subject to the approval of EEX's common shareholders and
other conditions. The transaction is expected to close in late November 2002.
On August 13, 2002, the Company completed the issuance of $250,000,000
principal amount of its 8 3/8% Senior Subordinated Notes due 2012 priced with a
yield to maturity of 8.50%. The net proceeds from the offering of approximately
$241.8 million will be used to repay EEX debt that will become due at the
closing of the EEX acquisition and to pay transaction costs associated with the
acquisition. Pending the closing of the acquisition of EEX, the net proceeds of
the notes (before expenses) have been placed in an escrow account. If the EEX
acquisition does not close on or prior to December 31, 2002 or the merger
agreement relating to the acquisition of EEX is terminated or abandoned earlier,
the funds in the escrow account, together with additional funds provided by the
Company, will be used to redeem all of the notes at a redemption price equal to
101% of their principal amount, plus accrued and unpaid interest to the date of
redemption. Interest accruing prior to the closing of the EEX acquisition will
be capitalized as a cost of the transaction.
The notes are unsecured senior subordinated obligations that rank junior in
right of payment to all of the Company's present and future senior indebtedness.
The indenture governing the notes limits the Company's ability to, among other
things, incur additional debt, make restricted payments, pay dividends on or
redeem its capital stock, make certain investments, create liens, make certain
dispositions of assets, engage in transactions with affiliates and engage in
mergers, consolidations and certain sales of assets.
13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas. Prices for oil and gas fluctuate widely. Oil
and gas prices affect:
o the amount of cash flow available for capital expenditures;
o our ability to borrow and raise additional capital;
o the amount of oil and gas that we can economically produce; and
o the accounting for our oil and gas activities.
We use hedging transactions with respect to a portion of our oil and gas
production to achieve more predictable cash flows and to reduce our exposure to
price fluctuations.
Our future success depends on our ability to find, develop and acquire oil
and gas reserves that are economically recoverable. As is generally the case,
our producing properties in the Gulf of Mexico and the onshore Gulf Coast often
have high initial production rates, followed by steep declines. As a result, we
must locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. Substantial capital expenditures are required to
find, develop, acquire and produce oil and gas reserves.
CRITICAL ACCOUNTING POLICIES
Our 2001 annual report describes the accounting policies that we believe
are critical to the reporting of our financial position and operating results
and that require management's most difficult, subjective or complex judgments.
Our most significant estimates are:
o remaining proved oil and gas reserves;
o timing of our future drilling activities;
o future costs to develop and abandon our oil and gas properties; and
o the value of derivative positions.
This report should be read together with the discussion contained in
our 2001 annual report regarding these critical accounting policies.
OTHER FACTORS AFFECTING OUR BUSINESS AND FINANCIAL RESULTS
In addition to the matters discussed above, our business, financial
condition and results of operations are affected by a number of other factors.
This report should be read together with the discussion in our 2001 annual
report regarding these other factors.
14
RESULTS OF OPERATIONS
REVENUES. All of our revenues are derived from the sale of our oil and
gas production and the settlement of hedging contracts associated with our
production. Our revenues may vary significantly from quarter to quarter as a
result of changes in commodity prices. Revenues for the third quarter and nine
months ended September 30, 2002 were 17% and 22%, respectively, lower than the
comparable periods of 2001 primarily because of lower natural gas prices, a
decrease in oil and condensate production and downtime in the Gulf of Mexico
associated with Tropical Storm Isidore.
<Table>
<Caption>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
PRODUCTION:
United States
Natural gas (Bcf) .............. 34.8 35.0 106.5 101.3
Oil and condensate (MBbls) ..... 1,185 1,418 3,863 4,034
Total (Bcfe) ................... 41.9 43.5 129.7 125.4
Australia(1)
Oil and condensate (MBbls) ..... 388 359 964 941
Total (Bcfe) ................... 2.3 2.2 5.8 5.7
Total
Natural gas (Bcf) .............. 34.8 35.0 106.5 101.3
Oil and condensate (MBbls) ..... 1,573 1,778 4,827 4,975
Total (Bcfe) ................... 44.2 45.7 135.5 131.1
AVERAGE REALIZED PRICES(2):
United States
Natural gas (per Mcf) .......... $ 3.19 $ 3.94 $ 3.22 $ 4.59
Oil and condensate (per Bbl) ... 24.84 24.52 23.52 24.55
Australia
Oil and condensate (per Bbl) ... $ 27.39 $ 25.40 $ 25.24 $ 26.58
Total
Natural gas (per Mcf) .......... $ 3.19 $ 3.94 $ 3.22 $ 4.59
Oil and condensate (per Bbl) ... 25.47 24.70 23.86 24.93
</Table>
- ----------
(1) Represents volumes sold regardless of when produced.
(2) For purposes of this table, average realized prices for natural gas
and oil and condensate are presented net of all applicable
transportation expenses, which reduced the realized price of
natural gas by $0.03 and $0.02 for the three months ended September
30, 2002 and 2001, respectively, and by $0.03 and $0.03 for the
nine months ended September 30, 2002 and 2001, respectively. The
realized price of oil and condensate is reduced by $0.35 and $0.28
for the three months ended September 30, 2002 and 2001,
respectively, and by $0.29 and $0.27 for the nine months ended
September 30, 2002 and 2001, respectively. Average realized prices
include the effects of hedging. See "Effect of Hedging on Realized
Prices" below.
PRODUCTION. During the first quarter of 2002, we voluntarily curtailed
approximately one Bcfe of production in response to low commodity prices. During
the second quarter of 2002, we resolved several open accounting matters relating
to prior periods, including the calculation of royalties due to the Minerals
Management Service and accounting for production from a recent acquisition. As a
result of the resolution of these matters, we recorded an additional 1.9 Bcf of
gas production and related revenue, depreciation, depletion and amortization
expense and income tax expense in the second quarter. During the third quarter
of 2002, we shut in approximately 1.5 Bcfe of our Gulf Coast production due to
Tropical Storm Isidore. Early in the fourth quarter 2002, we shut in an
additional 2.5 Bcfe of our Gulf Coast production as a result of Hurricane Lili.
The table above reflects volumes sold regardless of when the volumes were
produced. Primarily because of the timing of liftings of oil and condensate from
our FPSOs, we experienced an 8% and 2% increase in the volumes sold in Australia
during the three and nine month periods ended September 30, 2002, respectively,
as compared to the same periods of 2001.
15
EFFECTS OF HEDGING ON REALIZED PRICES. The following table presents
information about the effect of our hedging program on realized prices.
<Table>
<Caption>
Average
Realized Prices Ratio of
--------------------------- Hedged to
With Without Non-Hedged
Hedge Hedge Price(1)
------------ ------------ ------------
Natural Gas
Three months ended September 30, 2002 .... $ 3.19 $ 3.02 106%
Three months ended September 30, 2001 .... $ 3.94 $ 2.83 139%
Nine months ended September 30, 2002 ..... $ 3.22 $ 2.86 113%
Nine months ended September 30, 2001 ..... $ 4.59 $ 4.72 97%
Crude Oil and Condensate
Three months ended September 30, 2002 .... $ 25.47 $ 26.42 96%
Three months ended September 30, 2001 .... $ 24.70 $ 25.30 98%
Nine months ended September 30, 2002 ..... $ 23.86 $ 23.84 100%
Nine months ended September 30, 2001 ..... $ 24.93 $ 26.15 95%
</Table>
- ----------
(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, 2002 and 2001.
<Table>
<Caption>
Unit of Production (Per Mcfe) Amount (in thousands)
------------------------------------- -------------------------------------
Three Months Ended Three Months Ended
September 30, Percentage September 30, Percentage
----------------------- Increase ----------------------- Increase
2002 2001 (Decrease) 2002 2001 (Decrease)
---------- ---------- ---------- ---------- ---------- ----------
United States:
Lease operating ............................ $ 0.48 $ 0.60 (20)% $ 20,309 $ 26,097 (22)%
Production and other taxes ................. 0.09 0.08 13% 3,738 3,357 11%
Transportation ............................. 0.04 0.03 33% 1,730 1,325 31%
Depreciation, depletion and amortization ... 1.67 1.66 1% 69,910 72,075 (3)%
General and administrative (exclusive of
stock compensation) .................... 0.30 0.25 20% 12,657 10,971 15%
Total operating ........................ 2.59 2.61 (1)% 108,344 113,825 (5)%
Australia:
Lease operating ............................ $ 2.04 $ 1.92 6% $ 4,756 $ 4,148 15%
Production and other taxes ................. 0.81 (0.02) 4150% 1,897 (46) 4224%
Transportation ............................. -- -- -- -- -- --
Depreciation, depletion and amortization ... 1.02 1.01 1% 2,384 2,184 9%
General and administrative (exclusive of
stock compensation) .................... 0.17 0.20 (15)% 388 435 (11)%
Total operating ........................ 4.05 3.12 30% 9,425 6,721 40%
Total:
Lease operating ............................ $ 0.57 $ 0.66 (14)% $ 25,065 $ 30,245 (17)%
Production and other taxes ................. 0.13 0.07 86% 5,635 3,311 70%
Transportation ............................. 0.04 0.03 33% 1,730 1,325 31%
Depreciation, depletion and amortization ... 1.64 1.63 1% 72,294 74,259 (3)%
General and administrative (exclusive of
stock compensation) .................... 0.30 0.25 20% 13,045 11,406 14%
Total operating ....................... 2.66 2.64 1% 117,769 120,546 (2)%
</Table>
o Domestic lease operating expense was higher in the third quarter of
2001 because of a $5.5 million expense associated with a non-recurring
workover of a well at South Marsh Island 160. Without the effect of
such workover, domestic lease operating expenses per unit would have
been flat as compared to the comparable period in 2002.
o The increase in domestic production and other taxes resulted from
higher natural gas and crude oil and condensate prices during the
third quarter of 2002.
o The increase in domestic general and administrative expense for the
third quarter of 2002 is due primarily to our growing workforce.
o Maintenance on our FPSOs in the third quarter of 2002 resulted in
higher Australian lease operating expense during the quarter.
o Deductible Australian capital expenditures offset production taxes
otherwise payable. Production taxes are reported on a June 30 fiscal
year. The estimate of such taxes for the current year reflects lower
anticipated future capital expenditures in Australia. During the
third quarter of 2001, we revised our estimate of such taxes for
the fiscal year ended June 30, 2001 downward and anticipated
sufficient future deductible capital expenditures to offset production
taxes otherwise payable for the Australian production tax fiscal year
to end on June 30, 2002.
16
The following table presents information about our operating expenses
for the nine months ended September 30, 2002 and 2001.
<Table>
<Caption>
Unit of Production Amount
(Per Mcfe) (in thousands)
------------------------------------ ------------------------------------
Nine Months Ended Nine Months Ended
September 30, Percentage September 30, Percentage
----------------------- Increase ----------------------- Increase
2002 2001 (Decrease) 2002 2001 (Decrease)
---------- ---------- ---------- ---------- ---------- ----------
United States:
Lease operating ............................ $ 0.49 $ 0.50 (2)% $ 63,297 $ 62,890 1%
Production and other taxes ................. 0.08 0.10 (20)% 11,009 12,217 (10)%
Transportation ............................. 0.03 0.03 -- 4,377 4,150 5%
Depreciation, depletion and amortization ... 1.66 1.61 3% 215,938 201,850 7%
General and administrative (exclusive of
stock compensation) ...................... 0.28 0.26 8% 35,701 32,463 10%
Total operating ........................ 2.55 2.50 2% 330,322 313,570 5%
Australia:
Lease operating ............................ $ 1.82 $ 1.94 (6)% $ 10,527 $ 10,929 (4)%
Production and other taxes ................. 0.33 0.65 (49)% 1,897 3,675 (48)%
Transportation ............................. -- -- -- -- -- --
Depreciation, depletion and amortization ... 0.97 0.91 7% 5,590 5,132 9%
General and administrative (exclusive of
stock compensation) ...................... 0.23 0.15 53% 1,317 869 52%
Total operating ........................ 3.34 3.65 (8)% 19,331 20,605 (6)%
Total:
Lease operating ............................ $ 0.54 $ 0.56 (4)% $ 73,824 $ 73,819 --
Production and other taxes ................. 0.10 0.12 (17)% 12,906 15,892 (19)%
Transportation ............................. 0.03 0.03 -- 4,377 4,150 5%
Depreciation, depletion and amortization ... 1.63 1.58 3% 221,528 206,982 7%
General and administrative (exclusive of
stock compensation) ...................... 0.27 0.25 8% 37,018 33,332 11%
Total operating ........................ 2.58 2.55 1% 349,653 334,175 5%
</Table>
o Lease operating expense during the nine months ended September 30,
2001 included a $5.5 million non-recurring expense associated with a
workover of a well at South Marsh Island 160. Without the effect of
the workover, domestic lease operating expenses would have increased
10%, or $0.03 per unit, as a result of several non-routine repairs
to gathering lines and other offshore facilities related to our Gulf
of Mexico operations and a slight increase in well service costs in
the Mid-Continent.
o The decrease in domestic production and other taxes resulted from
lower natural gas and crude oil and condensate prices in the first
nine months of 2002.
o The increase in the domestic DD&A rate for 2002 is primarily related
to the increased cost of reserve additions arising from both the
quantity of proved reserves added and increases in the cost of
drilling goods and services and platform and facilities construction
during the first half of 2001. The increase is partially offset by
our fourth quarter 2001 non-cash ceiling test writedown.
o The increase in domestic general and administrative expense for the
first nine months of 2002 is due primarily to our growing workforce.
o Maintenance on our FPSOs in 2001 resulted in higher Australian lease
operating expense during the first nine months of 2001.
o Deductible Australian capital expenditures offset production taxes
otherwise payable. As a result of deductible capital expenditures
during the twelve months ended June 30, 2002(the applicable
reporting period for Australian production taxes), no such taxes
were recorded in the first six months of 2002.
o The increase in the Australian DD&A rate during the first nine
months of 2002 is primarily a result of our unsuccessful exploratory
drilling efforts in 2002 and 2001.
o The significant increase in per unit Australian general and
administrative expense for the first nine months of 2002 relates to
costs incurred in the first half of 2002 in connection with the
relocation of the previous manager of our Australian operations to
our Tulsa, Oklahoma office and the relocation of the current manager
of our Australian operations from Houston to Perth, Australia.
17
INTEREST EXPENSE. We incurred 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. Interest accruing on our 8 3/8% Senior
Subordinated Notes due 2012 will be capitalized as a transaction cost.
Outstanding borrowings under our credit arrangements may vary significantly from
period to period. Distributions are paid on our 6.5% convertible trust preferred
securities issued in August 1999. We capitalize a portion of our interest
expense each quarter based upon our unproved property balance. This amount may
vary significantly from period to period based upon the timing and size of
acquisitions and the evaluation of unproved properties.
<Table>
<Caption>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(in millions) (in millions)
Gross interest expense ................... $ 7.0 $ 6.9 $ 21.4 $ 20.5
Capitalized interest ..................... (2.3) (2.4) (6.6) (6.5)
------------ ------------ ------------ ------------
Net interest expense ..................... 4.7 4.5 14.8 14.0
Distributions on preferred securities .... 2.3 2.3 7.0 7.0
------------ ------------ ------------ ------------
Total interest expense and dividends ..... $ 7.0 $ 6.8 $ 21.8 $ 21.0
============ ============ ============ ============
</Table>
UNREALIZED COMMODITY DERIVATIVE EXPENSE. We recorded $14.0 million of expense
and $11.1 million of income for the three months ended September 30, 2002 and
2001, respectively, and $25.5 million of expense and $15.3 million of income for
the nine months ended September 30, 2002 and 2001, respectively. The gains in
2001 primarily reflect the change in the time value of open hedging contracts.
The losses in 2002 are associated with the settlement of those same hedging
contracts and primarily reflect the reversal of the time value gains that were
previously recognized during 2001.
OTHER. During 2001, other income was primarily comprised of interest income.
Other income during 2002 also includes currency gains and losses associated with
transactions by our Australian operations in U.S. dollars. The three months
ended September 30, 2002 includes $1.1 million of net currency gains and the
nine months ended September 30, 2002 includes $1.7 million of net currency
losses. Also included in the nine month period is a reversal of $2.2 million of
accrued liabilities associated with contingencies relating to the 1999
acquisition of our Australian operations that were resolved favorably in the
second quarter of 2002.
TAXES. The effective tax rate for the three and nine month periods ended
September 30, 2002 was 35% and 36%, respectively, as compared to 35% and 36%,
respectively, for the comparable periods of 2001. Estimates of future taxable
income can be significantly affected by changes in oil and natural gas prices,
estimates of the timing and amount of future production and estimates of future
operating and capital costs. During the three month period ended September 30,
2002, we had a significant shift in our tax expense from deferred to current.
This is a result of changes in the amount and timing of deductible capital
expenditures anticipated for 2002.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. Our working capital balance is not a good indicator of our
liquidity because it fluctuates as a result of the timing and amount of
borrowings or repayments under our credit arrangements. We had a working capital
deficit of $2.3 million as of September 30, 2002. This compares to working
capital of $65.6 million as of December 31, 2001. Historically, we have funded
our oil and gas activities through cash flow from operations, equity capital,
public debt and bank borrowings.
CASH FLOW FROM OPERATIONS. Our net cash flow from operations for the nine months
ended September 30, 2002 decreased 36%, from $463.1 million for the comparable
period of 2001 to $295.4 million. Net cash flow from operations before changes
in operating assets and liabilities for the nine months ended September 30, 2002
was $282.6 million compared to $415.6 million for the same period of 2001. These
decreases are primarily attributable to lower natural gas prices, a decrease in
oil and condensate production and a higher portion of current cash taxes paid.
We anticipated that all taxes during the fourth quarter of 2002 will be current
cash taxes.
CASH FLOW FROM FINANCING ACTIVITIES. Pursuant to our equity shelf program, in
March 2002, we sold 20,800 shares of our common stock for net proceeds (before
expenses other than commissions to our sales agent) of approximately $750,000.
We may sell additional shares under this program from time to time in the
future. An additional $5.1 million of proceeds were received from the exercise
of stock options and shares purchased through the employee stock purchase plan
during 2002. The net proceeds were used for general corporate purposes.
DEBT. At September 30, 2002, we had $45 million outstanding under our credit
facility and an additional $16 million outstanding under our money market lines
of credit with various banks. At September 30, 2002, our long-term debt was $361
million, which includes the above amounts and $125 million of our 7.45% Senior
Notes due 2007 and $175 million of our 7 5/8% Senior Notes due 2011.
18
The amount available under our credit facility is subject to a calculated
borrowing base determined by banks holding 75% of the aggregate commitments. The
borrowing base is reduced by the aggregate outstanding principal amount of our
senior notes ($300 million). The borrowing base is currently $520 million and is
redetermined at least semi-annually. No assurances can be given that the banks
will not elect to reduce 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 on January 23,
2004. As of November 6, 2002 we had $175 million available under our credit
facility and had outstanding borrowings of $45 million.
We also have money market lines of credit with various banks in an amount
limited by the credit facility to $40 million. As of November 6, 2002, we had $3
million of outstanding borrowings under these lines of credit.
Our credit arrangements are not subject to any debt rating or similar
triggers or conditions. However, applicable commitment fees and interest rates
under our credit facility vary based on our senior unsecured credit rating.
CAPITAL EXPENDITURES. In the first nine months of 2002, our capital spending
totaled $247 million. We invested $28 million for proved property acquisitions,
$108 million in domestic development, $86 million in domestic exploration and
$25 million internationally.
Exclusive of the EEX transaction, we currently expect to invest $340
million in capital spending in 2002. Of that amount, we expect to spend
approximately $27 million for proved property acquisitions, $138 million for
development, $145 million for domestic exploration and $30 million for
international projects. Acquisitions are opportunistic and are not budgeted
under our capital program unless specifically identified at the time the budget
is prepared. We continue to pursue attractive acquisition opportunities;
however, the timing, size and purchase price of acquisitions are unpredictable.
We anticipate that our capital expenditure program for the remainder of 2002
(exclusive of the EEX acquisition and any other acquisitions not included in the
initial budget) will be funded principally from cash flow from operations and
working capital.
Our annual capital budget is established at the beginning of each year.
Because of the nature of the properties we own, only a small portion of our
capital budget is nondiscretionary. The size of our budget is driven by expected
cash flow from operations. 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.
PENDING EEX ACQUISITION AND RELATED FINANCING
On May 29, 2002, we announced our agreement to acquire EEX Corporation, an
independent oil and gas exploration and production company with activities
focused in Texas, Louisiana and the Gulf of Mexico. The transaction is valued at
approximately $650 million, including the assumption of approximately $400
million of debt. We will issue approximately 7.1 million shares of our common
stock in the transaction, or approximately 12.4% of our outstanding common stock
on a fully diluted basis following the closing of the transaction.
The assets and operations of EEX are complementary to ours. EEX's onshore
properties are located in our core South Texas focus area, and the acquisition
will make us one of the largest independent producers in this area. The
acquisition also will provide us with increased balance between our onshore and
offshore assets. In addition, EEX's acreage position and interests in
undeveloped discoveries in the Gulf of Mexico will further our efforts to
establish operations in the deepwater. We expect to reduce EEX's current general
and administrative expense by as much as 50%.
The acquisition is subject to the approval of EEX's common shareholders and
other conditions. We expect the transaction to close in late November 2002.
On August 13, 2002, we completed the issuance of $250,000,000 principal
amount of our 8 3/8% Senior Subordinated Notes due 2012 priced with a yield to
maturity of 8.50%. The net proceeds from the offering of approximately $241.8
million will be used to repay EEX debt that will become due at the closing of
the EEX acquisition and to pay transaction costs associated with the
acquisition. Pending the closing of the acquisition of EEX, the net proceeds of
the notes (before expenses) have been placed in an escrow account. If the EEX
acquisition does not close on or prior to December 31, 2002 or the merger
agreement relating to the acquisition of EEX is terminated or abandoned earlier,
the funds in the escrow account, together with additional funds we will provide,
will be used to redeem all of the notes at a redemption price equal to 101% of
their principal amount, plus accrued and unpaid interest to the date of
redemption. Interest accruing prior to the closing of the EEX acquisition will
be capitalized as a cost of the transaction.
19
The notes are unsecured senior subordinated obligations that rank junior in
right of payment to all of our present and future senior indebtedness. The
indenture governing the notes limits our ability to, among other things, incur
additional debt, make restricted payments, pay dividends on or redeem our
capital stock, make certain investments, create liens, make certain dispositions
of assets, engage in transactions with affiliates and engage in mergers,
consolidations and certain sales of assets.
EEX currently has outstanding $100.8 million of notes that are secured by
EEX's interest in certain pipelines and a combination deepwater drilling
rig/processing facility located in the Gulf of Mexico. We intend to sell these
assets after the closing of the transaction. Pending their sale, the secured
notes will remain outstanding. We intend to finance other EEX obligations and
remaining transaction costs with borrowings under our existing revolving credit
facility. The lenders under our credit facility have agreed that our borrowing
base will increase to $730 million upon consummation of the acquisition. The
borrowing base will be reduced by 100% of the principal amount of our senior
notes ($300 million) and EEX's secured notes and 30% of the principal amount of
our senior subordinated notes. Immediately following the acquisition of EEX, we
expect to have approximately $108 million of borrowings under our credit
facility and money market lines of credit and remaining borrowing capacity of
approximately $186 million. Upon the sale of the assets securing EEX's notes,
the borrowing base will be reduced by $30 million and the notes must be repaid.
To the extent that we receive less than $30 million of net proceeds for these
assets, our available borrowing capacity will be reduced.
HEDGING
We enter into various commodity price hedging contracts with respect to a
portion of our anticipated future natural gas and crude oil 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 transactions also involves the risk that the counterparties
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 and tables in Note 5, "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, 2002 and the fair value of those contracts as of that date.
Since September 30, 2002, we have entered into the additional natural gas
price hedging contracts with respect to our Gulf Coast natural gas production
set forth in the table below. We continue to evaluate additional hedging
transactions for the remainder of 2002 and future years.
<Table>
<Caption>
NYMEX Contract Price Per MMBtu
-----------------------------------------------------------------------------------
Collars
-------------------------------------------------
Floors Ceilings Floor Contracts
Swaps -------------------- ------------------------- ---------------------
Volume in (Weighted Weighted Weighted Weighted
Period and Type of Contract MMMBtus Average) Range Average Range Average Range Average
- --------------------------- --------- --------- ---------- -------- ----------- ------------ ----------- --------
October 2002 - December 2002
Collar Contracts ............ 1,050 -- $4.00 $4.00 $4.69-$4.92 $4.83 -- --
Floor Contracts ............. 2,400 -- -- -- -- -- $4.05-$4.07 $4.06
January 2003 - March 2003
Price Swap Contracts ........ 555 $3.81 -- -- -- -- -- --
Collar Contracts ............ 4,395 -- 3.50-4.00 3.96 4.16-4.92 4.73 -- --
April 2003 - June 2003
Price Swap Contracts ........ 2,355 3.96 -- -- -- -- -- --
Collar Contracts ............ 345 -- 3.50 3.50 4.16 4.16 -- --
July 2003 - September 2003
Price Swap Contracts ........ 4,155 3.94 -- -- -- -- -- --
Collar Contracts ............ 345 -- 3.50 3.50 4.16 4.16 -- --
October 2003 - December 2003
Price Swap Contracts ........ 1,755 3.91 -- -- -- -- -- --
Collar Contracts ............ 345 -- 3.50 3.50 4.16 4.16 -- --
January 2004 - December 2005
Price Swap Contracts ........ 4,440 3.81 -- -- -- -- -- --
Collar Contracts ............ 2,760 -- 3.50 3.50 4.16 4.16 -- --
</Table>
20
Since September 30, 2002, we have also entered into the additional oil and
condensate price hedging contracts with respect to our Gulf Coast oil production
set forth in the table below. We continue to evaluate additional hedging
transactions for the remainder of 2002 and future years.
<Table>
<Caption>
NYMEX Contract Price Per Bbl
----------------------------
Swaps
Volume in (Weighted
Period and Type of Contract Bbls Average)
- --------------------------- ---------- ---------
January 2003 - December 2003
Price Swap Contracts................. 156,000 $ 25.95
January 2004 - December 2004
Price Swap Contracts................. 96,000 23.23
January 2005 - December 2005
Price Swap Contracts................. 204,000 22.63
</Table>
Substantially all of our hedging transactions are settled based upon
reported settlement prices on the NYMEX. We believe there is no material basis
risk with respect to our natural gas price hedging contracts because
substantially all our Gulf Coast natural gas production is sold under spot
contracts that have historically correlated to the settlement price, and because
all of the hedging contracts assumed from Lariat are settled against the same
pipelines into which our production in Oklahoma is sold. In addition, because
substantially all of our U.S. Gulf Coast 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 our oil
price hedging contracts.
NEW ACCOUNTING STANDARDS
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. It will require that the
fair value of the obligation be recognized in the period in which it is incurred
if a reasonable estimate of fair value can be made, and that the associated
asset retirement costs be capitalized as part of the carrying amount of the
asset. We plan to implement this standard on January 1, 2003. We are currently
assessing the impact of this standard.
OPERATING ESTIMATES; HEDGING POSITIONS; 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 and hedging positions. @NFX also includes our
latest publicly announced estimates of expected production volumes, costs and
expenses for the then current quarter. All recent editions of @NFX are available
on our web page. To receive @NFX directly by email, please forward your email
address to pmcknight@newfld.com or visit our web page and sign up.
FORWARD-LOOKING INFORMATION
This report contains information that is forward-looking or relates to
anticipated future events or results such as planned capital expenditures, the
availability of capital resources to fund capital expenditures, our financial
position and expected reductions in EEX's general and administrative expense.
Although we believe that the expectations reflected in this information are
reasonable, this information is 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.
21
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.
FPSO. A floating production, storage and off-loading vessel, commonly
used overseas to produce oil locations where pipeline
infrastructure may not exist.
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.
ITEM 4. CONTROLS AND PROCEDURES
Within the 90 day period prior to the filing date of this report, we
carried out an evaluation, under the supervision and with the participation of
our management, including our chief executive officer and chief financial
officer, of the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rule 13a-14(c) of the Securities Exchange
Act of 1934). Based upon that evaluation, our chief executive officer and chief
financial officer concluded that our disclosure controls and procedures are
effective in ensuring that material information is accumulated and communicated
to management, and made known to our chief executive officer and chief financial
officer, on a timely basis to allow disclosure as required in this report. There
have been no significant changes in our internal controls or in other factors
which could significantly affect internal controls subsequent to the date we
carried out our evaluation.
22
PART II
ITEM 5. OTHER INFORMATION
The certifications by our chief executive officer and chief financial
officer required by Section 906 of the Sarbanes-Oxley Act of 2002 have been
provided to the Securities and Exchange Commission accompanying this report.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
None
(b) Reports on Form 8-K:
On July 24, 2002, we filed a Current Report on Form 8-K in connection
with the announcement of our financial and operating results for the second
quarter of 2002 and our operating estimates for the third quarter of 2002.
On August 5, 2002, we filed a Current Report on Form 8-K that included
EEX's consolidated financial statements as of December 31, 2000 and 2001 and as
of March 31, 2001 and 2002 as a result of the proposed acquisition of EEX
announced on May 29, 2002.
On August 13, 2002, we filed a Current Report on Form 8-K in connection
with our agreement to offer, issue and sell $250 million of our 8 3/8% Senior
Subordinated Notes due 2012.
On August 14, 2002, we filed a Current Report on Form 8-K to furnish
copies of the certifications of our Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 2002 by our Chief Executive Officer and Chief
Financial Officer as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
On September 27, 2002, we filed a Current Report on Form 8-K to provide
a copy of an amendment to our credit agreement entered into in connection with
the offering of $250 million of our 8 3/8% Senior Subordinated Notes due 2012
and the proposed acquisition of EEX Corporation.
23
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THE
REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE
UNDERSIGNED THEREUNTO DULY AUTHORIZED.
NEWFIELD EXPLORATION COMPANY
DATE: NOVEMBER 11, 2002 BY: /s/ TERRY W. RATHERT
------------------------------------------
TERRY W. RATHERT
VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
(AUTHORIZED OFFICER AND PRINCIPAL
FINANCIAL OFFICER)
24
CERTIFICATION
I, David A. Trice, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Newfield
Exploration Company ("Registrant");
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of Registrant as of, and for, the periods presented in this
quarterly report;
4. Registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for Registrant and
have:
a. designed such disclosure controls and procedures to ensure
that material information relating to Registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in
which this quarterly report is being prepared;
b. evaluated the effectiveness of Registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date");
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. Registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to Registrant's auditors and the audit
committee of Registrant's Board of Directors (or persons performing
the equivalent functions):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect Registrant's
ability to record, process, summarize and report financial
data and have identified for Registrant's auditors any
material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management
or other employees who have a significant role in
Registrant's internal controls; and
6. Registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to the
significant deficiencies and material weaknesses.
Date: November 11, 2002
/s/ DAVID A. TRICE
--------------------------------------
David A. Trice
President and Chief Executive Officer
CERTIFICATION
I, Terry W. Rathert, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Newfield
Exploration Company ("Registrant");
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of Registrant as of, and for, the periods presented in this
quarterly report;
4. Registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for Registrant and
have:
a. designed such disclosure controls and procedures to ensure
that material information relating to Registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in
which this quarterly report is being prepared;
b. evaluated the effectiveness of Registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date");
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. Registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to Registrant's auditors and the audit
committee of Registrant's Board of Directors (or persons performing
the equivalent functions):
d. all significant deficiencies in the design or operation of
internal controls which could adversely affect Registrant's
ability to record, process, summarize and report financial
data and have identified for Registrant's auditors any
material weaknesses in internal controls; and
e. any fraud, whether or not material, that involves management
or other employees who have a significant role in
Registrant's internal controls; and
6. Registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to the
significant deficiencies and material weaknesses.
Date: November 11, 2002
/s/ TERRY W. RATHERT
------------------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer