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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(MARK ONE)
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from ____________to____________.
COMMISSION FILE NUMBER: 1-12534
NEWFIELD EXPLORATION COMPANY
(Exact name of Registrant as specified in its charter)
DELAWARE 72-1133047
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
363 NORTH SAM HOUSTON PARKWAY EAST
SUITE 2020
HOUSTON, TEXAS 77060
(Address and Zip Code of principal executive offices)
(281) 847-6000
(Registrant's telephone number, including area code)
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 twelve months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the Registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2).
Yes [X] No [ ]
As of May 9, 2003, there were 52,151,443 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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TABLE OF CONTENTS
Page
----
PART I
Item 1. Unaudited Financial Statements:
Consolidated Balance Sheet as of March 31, 2003 and December 31, 2002.............................. 1
Consolidated Statement of Income for the three months ended
March 31, 2003 and 2002............................................................................ 2
Consolidated Statement of Cash Flows for the three months ended
March 31, 2003 and 2002............................................................................ 3
Consolidated Statement of Stockholders' Equity for the three
months ended March 31, 2003........................................................................ 4
Notes to Consolidated Financial Statements......................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................................................. 15
Item 3. Quantitative and Qualitative Disclosures about Market Risk............................................ 24
Item 4. Controls and Procedures............................................................................... 24
PART II
Item 1. Legal Proceedings..................................................................................... 25
Item 2. Changes in Securities and Use of Proceeds............................................................. 25
Item 3. Defaults upon Senior Securities....................................................................... 25
Item 4. Submission of Matters to a Vote of Security Holders................................................... 25
Item 5. Other Information..................................................................................... 25
Item 6. Exhibits and Reports on Form 8-K...................................................................... 26
ii
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents.................................................... $ 42,586 $ 48,898
Accounts receivable--oil and gas............................................. 209,864 130,489
Inventories.................................................................. 7,223 7,910
Commodity derivatives........................................................ 22,002 2,655
Deferred taxes............................................................... 18,075 12,801
Other current assets......................................................... 29,810 36,074
----------- -----------
Total current assets..................................................... 329,560 238,827
----------- -----------
Oil and gas properties (full cost method, of which $279,742 at March 31, 2003
and $268,732 at December 31, 2002 were excluded from amortization)........... 3,610,337 3,349,254
Less--accumulated depreciation, depletion and amortization...................... (1,394,732) (1,339,249)
----------- -----------
2,215,605 2,010,005
----------- -----------
Assets held for sale............................................................ 35,000 35,000
Furniture, fixtures and equipment, net.......................................... 8,747 8,030
Commodity derivatives........................................................... 4,533 4,439
Other assets.................................................................... 20,952 19,452
----------- -----------
Total assets.............................................................. $ 2,614,397 $ 2,315,753
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................................. $ 15,887 $ 27,593
Current portion of secured notes payable..................................... 5,884 11,215
Accrued liabilities.......................................................... 189,569 203,776
Advances from joint owners................................................... 2,084 3,613
Current portion of asset retirement obligation............................... 10,174 --
Commodity derivatives........................................................ 69,798 49,610
----------- -----------
Total current liabilities................................................. 293,396 295,807
----------- -----------
Other liabilities............................................................... 16,906 16,976
Commodity derivatives........................................................... 12,777 10,610
Long-term debt.................................................................. 778,903 709,615
Asset retirement obligation..................................................... 157,566 --
Deferred taxes.................................................................. 141,595 129,309
----------- -----------
Total long-term liabilities............................................... 1,107,747 866,510
----------- -----------
Company-obligated, mandatorily redeemable, convertible preferred securities of
Newfield Financial Trust I................................................... 143,750 143,750
Minority interest............................................................... -- 455
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;
52,934,899 and 52,603,662 shares issued and outstanding
at March 31, 2003 and December 31, 2002, respectively).................... 529 526
Additional paid-in capital...................................................... 643,970 636,317
Treasury stock (at cost; 883,024 and 872,927 shares at March 31, 2003 and
December 31, 2002, respectively)............................................. (26,552) (26,213)
Unearned compensation........................................................... (12,936) (6,479)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment...................................... 131 (3,888)
Commodity derivatives........................................................ (36,042) (27,295)
Retained earnings............................................................... 500,404 436,263
----------- -----------
Total stockholders' equity................................................ 1,069,504 1,009,231
----------- -----------
Total liabilities and stockholders' equity................................ $ 2,614,397 $ 2,315,753
=========== ===========
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 SHARE AND PER SHARE DATA)
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
Oil and gas revenues ........................................................... $ 279,284 $ 148,039
--------- ---------
Operating expenses:
Lease operating ............................................................. 32,256 23,053
Production and other taxes .................................................. 12,574 3,410
Transportation .............................................................. 1,563 1,331
Depreciation, depletion and amortization .................................... 96,700 71,207
General and administrative (includes stock compensation
of $679 and $578 for the three months ended March 31, 2003
and 2002, respectively) ................................................... 17,582 12,345
Loss on gas sales obligation settlement ..................................... 9,998 --
--------- ---------
Total operating expenses .............................................. 170,673 111,346
--------- ---------
Income from operations ......................................................... 108,611 36,693
Other income (expenses):
Interest .................................................................... (16,686) (7,201)
Capitalized interest ........................................................ 3,819 2,130
Dividends on convertible preferred securities of Newfield Financial Trust I.. (2,336) (2,336)
Unrealized commodity derivative expense ..................................... (1,217) (5,645)
Other ....................................................................... (1,229) 1,816
--------- ---------
(17,649) (11,236)
--------- ---------
Income before income taxes ..................................................... 90,962 25,457
Income tax provision:
Current ..................................................................... 23,639 6,227
Deferred .................................................................... 8,757 2,904
--------- ---------
32,396 9,131
--------- ---------
Income before cumulative effect of change in accounting principle .............. 58,566 16,326
Cumulative effect of change in accounting principle, net of tax:
Adoption of SFAS No. 143 ................................................... 5,575 --
--------- ---------
Net income ............................................................ $ 64,141 $ 16,326
========= =========
Earnings per share:
Basic --
Income before cumulative effect of change in accounting principle ....... $ 1.13 $ 0.37
Cumulative effect of change in accounting principle, net of tax ......... 0.11 --
--------- ---------
Net income ............................................................ $ 1.24 $ 0.37
========= =========
Diluted --
Income before cumulative of change in accounting principle .............. $ 1.07 $ 0.37
Cumulative effect of change in accounting principle, net of tax ......... 0.10 --
--------- ---------
Net income ............................................................ $ 1.17 $ 0.37
========= =========
Weighted average number of shares outstanding for basic earnings per share ..... 51,886 44,212
========= =========
Weighted average number of shares outstanding for diluted earnings per share ... 56,208 48,745
========= =========
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)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
Cash flows from operating activities:
Net income .......................................................... $ 64,141 $ 16,326
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization .......................... 96,700 71,207
Deferred taxes .................................................... 8,757 2,904
Stock compensation ................................................ 679 578
Unrealized commodity derivatives .................................. 1,217 5,645
Cumulative effect of change in accounting principle ............... (5,575) --
Loss on gas sales obligation settlement ........................... 9,998 --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable -- oil and gas ...... (78,989) 5,263
Decrease in inventories ........................................ 1,994 451
Increase in other current assets ............................... (3,904) (1,086)
Decrease (increase) in other assets ............................ (1,606) 288
Decrease in accounts payable and accrued liabilities ........... (26,975) (2,478)
Decrease in advances from joint owners ......................... (1,529) (53)
Increase (decrease) in other liabilities ....................... 747 (396)
--------- ---------
Net cash provided by operating activities ................... 65,655 98,649
--------- ---------
Cash flows from investing activities:
Additions to oil and gas properties ................................. (123,992) (84,489)
Additions to furniture, fixtures and equipment ...................... (1,891) (826)
--------- ---------
Net cash used in investing activities ....................... (125,883) (85,315)
--------- ---------
Cash flows from financing activities:
Proceeds from borrowings under credit arrangements .................. 744,000 128,000
Repayments of borrowings under credit arrangements .................. (575,000) (146,000)
Deliveries under the gas sales obligation ........................... (8,442) --
Proceeds from issuance of common stock .............................. 726 3,396
Repurchases of secured notes ........................................ (33,869) --
Repayments of secured notes ......................................... (11,215) --
Gas sales obligation settlement ..................................... (62,017) --
Purchases of treasury stock ......................................... (339) (218)
--------- ---------
Net cash provided by (used in) financing activities ......... 53,844 (14,822)
--------- ---------
Effect of exchange rate changes on cash and cash equivalents ........... 72 6
--------- ---------
Decrease in cash and cash equivalents .................................. (6,312) (1,482)
Cash and cash equivalents, beginning of period ......................... 48,898 26,610
--------- ---------
Cash and cash equivalents, end of period ............................... $ 42,586 $ 25,128
========= =========
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)
COMMON STOCK TREASURY STOCK ADDITIONAL
------------------- -------------------- PAID-IN UNEARNED RETAINED
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION EARNINGS
---------- ------ -------- --------- ---------- ------------ --------
BALANCE, DECEMBER 31, 2002........................ 52,603,662 $ 526 (872,927) $ (26,213) $636,317 $ (6,479) $436,263
Issuance of common stock......................... 117,937 1 (1,022)
Issuance of restricted stock,
less amortization of $32....................... 213,300 2 7,134 (7,104)
Treasury stock, at cost.......................... (10,097) (339)
Amortization of stock
compensation................................... 647
Tax benefit from exercise of
stock options.................................. 1,541
Comprehensive income:
Net income..................................... 64,141
Foreign currency translation
adjustment, net of tax
of $2,164....................................
Reclassification adjustments
for settled contracts, net of tax
of $6,705....................................
Changes in fair value of
outstanding hedging
positions, net of tax
of $2,000....................................
Total comprehensive income...................
---------- ------ -------- --------- -------- -------- --------
BALANCE, MARCH 31, 2003........................... 52,934,899 $ 529 (883,024) $ (26,552) $643,970 $(12,936) $500,404
========== ====== ======== ========= ======== ======== ========
ACCUMULATED
OTHER TOTAL
COMPREHENSIVE STOCKHOLDERS'
INCOME (LOSS) EQUITY
------------- -------------
BALANCE, DECEMBER 31, 2002........................ $ (31,183) $1,009,231
Issuance of common stock......................... (1,021)
Issuance of restricted stock,
less amortization of $32....................... 32
Treasury stock, at cost.......................... (339)
Amortization of stock
compensation................................... 647
Tax benefit from exercise of
stock options.................................. 1,541
Comprehensive income:
Net income..................................... 64,141
Foreign currency translation
adjustment, net of tax
of $2,164.................................... 4,019 4,019
Reclassification adjustments
for settled contracts, net of tax
of $6,705.................................... (12,451) (12,451)
Changes in fair value of
outstanding hedging
positions, net of tax
of $2,000.................................... 3,704 3,704
----------
Total comprehensive income................... 59,413
--------- ----------
BALANCE, MARCH 31, 2003........................... $ (35,911) $1,069,504
========= ==========
The accompanying notes to consolidated financial statements are an
integral part of this financial statement.
4
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
ORGANIZATION AND PRINCIPLES OF CONSOLIDATION
We are an independent oil and gas company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. Our company
was founded in 1989 and we acquired our first property in 1990. Our initial
focus area was the Gulf of Mexico. In the mid-1990s, we began to expand our
operations to other select areas. Our areas of operation now include the U.S.
onshore Gulf Coast, West Texas, the Anadarko Basin and offshore northwest
Australia.
Our financial statements include the accounts of Newfield Exploration
Company, a Delaware corporation, and its subsidiaries. All significant
intercompany balances and transactions have been eliminated. Unless otherwise
specified or the context otherwise requires, all references in these notes to
"Newfield," "we," "us" or "our" are to Newfield Exploration Company and its
subsidiaries.
These unaudited consolidated financial statements reflect, in the opinion
of our management, all adjustments, consisting only of normal and recurring
adjustments, necessary to present fairly our financial position as of, and
results of operations for, the periods presented. These 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 financial statements and notes should be read in conjunction with our
consolidated financial statements and the notes thereto for the year ended
December 31, 2002 included in our Annual Report on Form 10-K.
DEPENDENCE ON OIL AND GAS PRICES
As an independent oil and gas producer, our revenue, profitability and
future growth depend substantially on prevailing prices for oil and gas, 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 the price for oil or gas
could have a material adverse effect on our financial position, results of
operations, cash flows and our access to capital and on the quantities of
reserves that may be economically produced.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect the reported amounts of assets and liabilities;
disclosure of contingent assets and liabilities at the date of the financial
statements; the reported amounts of revenues and expenses during the reporting
period; and the reported amounts of proved oil and gas reserves. Actual results
could differ from these estimates. Our most significant financial estimates
are based on remaining proved oil and gas reserves.
RECLASSIFICATIONS
Certain reclassifications have been made to prior period's reported amounts
in order to conform with the current period presentation. These
reclassifications did not impact our net income or stockholders' equity.
STOCK-BASED COMPENSATION
We account for our employee stock options using the intrinsic value method
prescribed by Accounting Principles Board (APB) Opinion No. 25.
5
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
If the fair value based method of accounting under Statement of Financial
Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation,"
had been applied, our net income and earnings per common share for the three
months ended March 31, 2003 and 2002 would have approximated the pro forma
amounts below:
THREE MONTHS ENDED MARCH 31,
------------------------------
2003 2002
------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income:
As reported .............................. $ 64,141 $ 16,326
Pro forma stock-based compensation
expense (net of taxes) ................. (432) (1,267)
Pro forma ................................ 63,709 15,059
Earnings per share:
Basic - as reported
Income before cumulative effect of
change in accounting principle ....... $ 1.13 $ 0.37
Cumulative effect of change in
accounting principle ................. 0.11 --
------------ ------------
Net income ............................. $ 1.24 $ 0.37
============ ============
Basic - pro forma
Income before cumulative effect of
change in accounting principle ....... $ 1.12 $ 0.34
Cumulative effect of change in
accounting principle ................. 0.11 --
------------ ------------
Net income ............................. $ 1.23 $ 0.34
============ ============
Diluted - as reported
Income before cumulative effect of
change in accounting principle ....... $ 1.07 $ 0.37
Cumulative effect of change in
accounting principle ................. 0.10 --
------------ ------------
Net income ............................. $ 1.17 $ 0.37
============ ============
Diluted - pro forma
Income before cumulative effect of
change in accounting principle ....... $ 1.06 $ 0.34
Cumulative effect of change in
accounting principle ................. 0.10 --
------------ ------------
Net income ............................. $ 1.16 $ 0.34
============ ============
6
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NEW ACCOUNTING STANDARDS
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS. In 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement changes the method of accounting for
costs associated with the retirement of long-lived assets (e.g. oil and gas
production facilities, etc.) that we are obligated to incur. The statement
requires 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 asset retirement cost be capitalized as part of the carrying amount of
the associated asset. Prior to January 1, 2003, we recognized the cost to
abandon our oil and gas properties over their productive lives on a
unit-of-production basis.
We adopted SFAS No. 143 as of January 1, 2003. Upon initial application of
SFAS No. 143, a cumulative effect of a change in accounting principle was
required in order to recognize a liability for our existing asset retirement
obligation (ARO) adjusted for cumulative accretion to the date of adoption, an
increase in the capitalized costs with respect to the associated long-lived
assets and accumulated depreciation on the additional capitalized costs.
Subsequent to initial measurement of our ARO, liabilities will be accreted to
their present value each period and the capitalized asset retirement costs will
be depreciated over the estimated useful life of the related assets.
We recorded a liability representing expected future costs associated with
site reclamation, facilities dismantlement, and plugging and abandonment of
wells as follows (in thousands):
Initial ARO as of January 1, 2003............. $151,929
Accretion expense for the three
months ended March 31, 2003................. 3,311
Additions during the three months ended
March 31, 2003.............................. 12,500
--------
Balance of ARO as of March 31, 2003........... $167,740
========
As a result of our adoption of SFAS No. 143, we also recorded a $160.4
million increase in the net capitalized costs of our oil and gas properties and
recognized an after-tax gain of $5.6 million for the cumulative effect of the
change in accounting principle. Had SFAS No. 143 been applied retroactively to
the three months ended March 31, 2002, our net income and earnings per share
would have approximated the pro forma amounts below (in thousands except per
share amounts):
Net income:
As reported ...................... $ 16,326
Pro forma ........................ $ 15,809
Earnings per share:
Basic --
As reported ........................ $ 0.37
Pro forma .......................... $ 0.36
Diluted --
As reported ........................ $ 0.37
Pro forma .......................... $ 0.35
7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER STANDARDS. In the second quarter of 2002, the FASB issued SFAS No.
145, "Recision of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement
No. 13, and Technical Corrections as of April 2002." The statement provides
guidance for income statement classifications of gains and losses on
extinguishment of debt and accounting for certain lease modifications that have
economic effects that are similar to sale-leaseback transactions. Our adoption
of SFAS No. 145 on January 1, 2003 had no effect on our financial statements.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires
that a liability for costs associated with an exit or disposal activity be
recognized when the liability is incurred and establishes that fair value is the
objective for initial measurement of the liability. The provisions of SFAS No.
146 are effective for exit or disposal activities that are initiated after
December 31, 2002. Our adoption of SFAS No. 146 on January 1, 2003 had no effect
on our financial statements.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts and hedging activities under SFAS No.
133. The amendments set forth in SFAS No. 149 require that contracts with
comparable characteristics be accounted for similarly. SFAS No. 149 is generally
effective for contracts entered into or modified after June 20, 2003 (with a few
exceptions) and for hedging relationships designated after June 30, 2003. The
guidance is to be applied prospectively only. We are currently evaluating the
impact of the standard on our financial statements.
In November 2002, the FASB issued Interpretation No. (FIN) 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." FIN 45 requires certain guarantees to be
recorded at fair value. FIN 45 has a dual effective date. The initial
recognition and measurement provisions are applicable on a prospective basis
only to guarantees issued or modified after December 31, 2002. The disclosure
requirements in the interpretation are effective for financial statements for
interim or annual periods ending after December 15, 2002. The adoption of FIN 45
did not have a material effect on our financial statements.
8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, an interpretation of ARB 51." The primary objectives of FIN
46 are to provide guidance on the identification of entities for which control
is achieved through means other than through voting rights (these entities are
referred to as "variable interest entities" or "VIEs") and how to determine if a
business enterprise should consolidate the VIE. This new model for consolidation
applies to an entity for which either (1) the equity investors (if any) do not
have a controlling financial interest or (2) the equity investment at risk is
insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. In addition, FIN 46 requires
that all enterprises with a significant variable interest in a VIE make
additional disclosures regarding their relationship with the VIE. We are
currently evaluating the impact of FIN 46 on our financial statements; however
we do not have any VIEs that will require consolidation in our
financial statements under this interpretation.
2. EARNINGS PER SHARE:
Basic earnings per common share (EPS) is computed by dividing net income
(the numerator) by the weighted average number of common shares outstanding for
the period (the denominator). Diluted EPS is similarly calculated using the
treasury stock method except that the denominator is increased to reflect the
potential dilution that could occur if outstanding stock options and convertible
securities outstanding at the end of the applicable period were exercised for or
converted into common stock.
The following is a calculation of basic and diluted weighted average shares
outstanding for the three months ended March 31, 2003 and 2002:
THREE MONTHS ENDED
MARCH 31,
----------------------------
2003 2002
--------- ---------
(IN THOUSANDS, EXCEPT SHARE
AND PER SHARE DATA)
Income (numerator):
Income before cumulative effect of change
in accounting principle.................................... $ 58,566 $ 16,326
Cumulative effect of change in accounting
principle, net of tax...................................... 5,575 --
--------- ---------
Income -- basic.............................................. 64,141 16,326
After tax dividends on convertible trust
preferred securities....................................... 1,518 1,518
--------- ---------
Income -- diluted............................................ $ 65,659 $ 17,844
========= =========
Shares (denominator):
Shares -- basic.............................................. 51,886 44,212
Dilution effect of stock options outstanding
at end of period........................................... 399 610
Dilution effect of convertible trust
preferred securities....................................... 3,923 3,923
--------- ---------
Shares -- diluted............................................ 56,208 48,745
========= =========
Earnings per share:
Basic before change in accounting principle.................. $ 1.13 $ 0.37
Basic........................................................ $ 1.24 $ 0.37
Diluted before change in accounting principle................ $ 1.07 $ 0.37
Diluted...................................................... $ 1.17 $ 0.37
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 1,582,850 and
800,500 shares for the three months ended March 31, 2003 and 2002, respectively,
because to do so would have been antidilutive.
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. EEX ACQUISITION:
On November 26, 2002, we acquired EEX Corporation to expand our onshore
operations. The EEX properties are very complementary to our previously existing
South Texas property base. The acquisition also accelerated our expansion into
deepwater.
The unaudited pro forma results presented below for the three months ended
March 31, 2002 have been prepared to illustrate the effects of the EEX
acquisition on our results of operations under the purchase method of accounting
as if we had acquired EEX on January 1, 2002. The pro forma results do not
purport to represent what the results of operations would actually have been if
the acquisition had in fact occurred on such date or to project our results of
operations for any future date or period.
THREE MONTHS
ENDED
MARCH 31,
2002
-----------------
(IN THOUSANDS,
EXCEPT PER SHARE)
Pro forma:
Revenue .................................... $188,550
Income from operations ..................... 43,220
Net income ................................. 17,127
Basic earnings per share ................... $ 0.33
Diluted earnings per share.................. $ 0.33
4. DEBT:
As of the indicated dates, our long-term debt consisted of the following:
MARCH 31, DECEMBER 31,
2003 2002
----------- -----------
(IN THOUSANDS)
Senior unsecured debt:
Bank revolving credit facility:
Prime rate based loans........................................ $ -- $ --
LIBOR based loans............................................. 205,000 28,000
----------- -----------
Total bank revolving credit facility....................... 205,000 28,000
----------- -----------
Money market lines of credit(1)................................... -- 8,000
----------- -----------
Total credit arrangements.................................. 205,000 36,000
----------- -----------
7.45% Senior Notes due 2007....................................... 124,791 124,781
7 5/8% Senior Notes due 2011...................................... 174,897 174,895
----------- -----------
Total senior unsecured notes............................... 299,688 299,676
----------- -----------
Total senior unsecured debt................................ 504,688 335,676
----------- -----------
8 3/8% Senior Subordinated Notes due 2012............................ 248,005 247,971
Secured notes........................................................ 26,210 65,963
Gas sales obligation(1).............................................. -- 60,005
----------- -----------
Total long-term debt....................................... $ 778,903 $ 709,615
=========== ===========
- --------------------
(1) Because capacity under our credit facility was available to repay
borrowings under our money market lines of credit and to pay current
amounts due under the gas sales obligation, these obligations were
classified as long-term at December 31, 2002.
10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
GAS SALES OBLIGATION SETTLEMENT
Pursuant to a gas forward sales contract entered into in 1999, EEX
committed to deliver approximately 50 Bcf of production to Bob West Treasure
L.L.C. (BWT) in exchange for proceeds of $105 million. As of the date of our
acquisition of EEX, we recorded a liability of approximately $62 million, which
represented the then current market value of approximately 16 Bcf of reserves
remaining under the gas sales contract. We accounted for the obligation under
the gas sales contract as debt in our consolidated balance sheet.
On March 31, 2003, pursuant to a settlement agreement with BWT and by the
other parties to related transactions, the gas sales contract, the swaps
entered into by BWT in connection with the gas sales contract and all other
agreements related to the gas sales contract, including the guarantee and all
liens and other security interests on EEX's properties, were terminated in
exchange for a payment by us of approximately $73 million. This payment
represented:
o the remaining unamortized obligation under the gas sales contract;
o the fair market value of certain swaps entered into by BWT in
conjunction with the gas sales contract;
o various transaction fees related to the termination; and
o an agreed upon value for BWT's limited membership interest in an EEX
subsidiary.
In connection with the settlement, we recognized a loss of $10.0 million
under the caption "Loss on gas sales obligation settlement" in our consolidated
income statement. About $9.0 million of the loss was related to the change in
the fair market value of the committed production and the swaps between the
acquisition date and the settlement date.
5. CONTINGENCIES:
We have 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, we do not expect that these matters will have a
material adverse effect on our financial position, cash flows or results of
operations.
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
6. GEOGRAPHIC INFORMATION:
OTHER
UNITED STATES AUSTRALIA INTERNATIONAL TOTAL
------------- ---------- ------------- -----------
(IN THOUSANDS)
THREE MONTHS ENDED MARCH 31, 2003:
Oil and gas revenues................................. $ 267,891 $ 11,393 $ -- $ 279,284
Operating expenses:
Lease operating.................................. 27,807 4,449 -- 32,256
Production and other taxes....................... 10,207 2,367 -- 12,574
Transportation................................... 1,563 -- -- 1,563
Depreciation, depletion and amortization......... 93,318 3,382 -- 96,700
Allocated income taxes........................... 47,153 440 --
----------- ---------- ----------
Net income from oil and gas properties....... $ 87,843 $ 755 $ --
=========== ========== ==========
Gas sales obligation settlement.................. 9,998
General and administrative (inclusive of stock
compensation)(1)............................... 17,582
-----------
Total operating expenses..................... 170,673
-----------
Income from operations............................... 108,611
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (16,432)
Unrealized commodity derivative expense.......... (1,217)
-----------
Income before income taxes........................... $ 90,962
===========
Total long-lived assets(2)........................... $2,127,080 $ 49,799 $ 38,726 $ 2,215,605
========== ========== ========== ===========
Additions to long-lived assets(2).................... $ 229,793 $ 24,715 $ 2,382 $ 256,890
========== ========== ========== ===========
THREE MONTHS ENDED MARCH 31, 2002:
Oil and gas revenues................................. $ 141,473 $ 6,566 $ -- $ 148,039
Operating expenses:
Lease operating.................................. 20,156 2,897 -- 23,053
Production and other taxes....................... 3,410 -- -- 3,410
Transportation................................... 1,331 -- -- 1,331
Depreciation, depletion and amortization......... 69,633 1,574 -- 71,207
Allocated income taxes........................... 16,427 629 --
---------- ---------- ----------
Net income from oil and gas properties....... $ 30,516 $ 1,466 $ --
========== ========== ==========
General and administrative (inclusive of stock
compensation)(1)............................... 12,345
-----------
Total operating expenses..................... 111,346
-----------
Income from operations............................... 36,693
Interest expense and dividends, net of interest
income, capitalized interest and other......... (5,591)
Unrealized commodity derivative expense.......... (5,645)
-----------
Income before income taxes........................... $ 25,457
===========
Total long-lived assets.............................. $1,367,832 $ 17,709 $ 32,214 $ 1,417,755
========== ========== ========== ===========
Additions to long-lived assets....................... $ 69,589 $ 6,961 $ 4,026 $ 80,576
========== ========== ========== ===========
- -------------------
(1) General and administrative expense includes stock compensation charges of
$679 and $578 for the three months ended March 31, 2003 and 2002,
respectively.
(2) Includes domestic additions of $113.1 million and Australia additions of
21.1 million for capitalized asset retirement obligations.
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
We maintain 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 our oil and gas production. While the use of these derivative
instruments limits the downside risk of adverse price movements, their use also
may limit future revenues from favorable price movements.
With respect to any particular swap transaction, the counterparty is
required to make a payment to us if the settlement price for any settlement
period is less than the swap price for such transaction, and we are required to
make payment to the counterparty 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 us if the
settlement price for any settlement period is below the floor price for such
transaction, and we are required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price of such
transaction. For any particular floor contract, the counterparty is required to
make a payment to us if the settlement price for any settlement period is below
the floor price for such transaction. We are not required to make any payment in
connection with the settlement of a floor contract.
Substantially all of our hedging transactions are settled based upon
reported settlement 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 we enter into a
derivative contract, we designate the derivative as a hedge of the variability
in cash flows associated with the forecasted sale of our 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 the sale of
the hedged oil and gas production. Gains or losses on our hedging transactions
are reported in oil and gas revenues on the consolidated statement of income.
Within the next 12 months, we expect to reclassify to earnings $37.8
million in after tax losses associated with commodity derivative out of the net
$36.0 million in after tax losses recorded in other comprehensive income at
March 31, 2003.
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, we began assessing hedge effectiveness based on the total
changes in cash flows on our collar and floor contracts as described by DIG
Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a
Purchased Option Used in a Cash Flow Hedge." As a result, amounts recorded in
the first quarter of 2002 primarily reflect the reversal of the time value gains
that were previously recognized in 2001 and a diminutive amount representing the
ineffective portion of our hedges. For the same period of 2003, we recorded
expense of $1.2 million related to hedge ineffectiveness. Pursuant to the
guidance in DIG Issue G20, we have elected to prospectively 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.
We formally document all relationships between hedging instruments and
hedged items, as well as our 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. We also formally assess (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, we will discontinue
hedge accounting prospectively. If hedge accounting is discontinued and the
derivative remains outstanding, we 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
presented for any hedging instruments.
13
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NATURAL GAS
As of March 31, 2003, we had entered into commodity price hedging contracts
with respect to our natural gas production for April 2003 through December 2005
as follows:
NYMEX CONTRACT PRICE PER MMBTU
----------------------------------------------------------------
COLLARS
---------------------------------------------------
FLOORS CEILINGS
SWAPS ----------------------- -----------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED
PERIOD AND TYPE OF CONTRACT MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE
--------------------------- --------- --------- ------------- -------- ------------- --------
April 2003 - June 2003
Price swap contracts........ 16,440 $3.94 -- -- -- --
Collar contracts............ 12,885 -- $3.50 - $4.50 $ 4.02 $3.90 - $5.63 $ 4.95
Floor contracts............. 14,500 -- -- -- -- --
July 2003 - September 2003
Price swap contracts........ 17,373 3.99 -- -- -- --
Collar contracts............ 9,585 -- 3.50 - 4.50 4.20 3.90 - 5.63 4.96
Floor contracts............. 15,000 -- -- -- -- --
October 2003 - December 2003
Price swap contracts........ 10,557 3.78 -- -- -- --
Collar contracts............ 4,395 -- 3.50 - 4.50 4.07 3.90 - 5.63 4.87
Floor contracts............. 5,000 -- -- -- -- --
January 2004 - December 2004
Price swap contracts........ 2,220 3.81 -- -- -- --
Collar contracts............ 1,380 -- 3.50 3.50 4.16 4.16
January 2005 - December 2005
Price swap contracts........ 2,220 3.81 -- -- -- --
Collar contracts............ 1,380 -- 3.50 3.50 4.16 4.16
NYMEX CONTRACT PRICE PER MMBTU
------------------------------
FLOOR CONTRACTS ESTIMATED
------------------------ FAIR VALUE
WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT RANGE AVERAGE (IN MILLIONS)
--------------------------- ------------- -------- -----------------
April 2003 - June 2003
Price swap contracts........ -- -- $(18.8)
Collar contracts............ -- -- (4.6)
Floor contracts............. $4.85 - $4.88 $ 4.87 5.4
July 2003 - September 2003
Price swap contracts........ -- -- (17.7)
Collar contracts............ -- -- (5.0)
Floor contracts............. 4.85 - 4.88 4.87 8.8
October 2003 - December 2003
Price swap contracts........ -- -- (12.9)
Collar contracts............ -- -- (2.9)
Floor contracts............. 4.85 - 4.88 4.87 3.6
January 2004 - December 2004
Price swap contracts........ -- -- (1.8)
Collar contracts............ -- -- (1.0)
January 2005 - December 2005
Price swap contracts........ -- -- (1.1)
Collar contracts............ -- -- (0.8)
------
$(48.8)
======
OIL
As of March 31, 2003, we had entered into commodity price hedging contracts
with respect to our oil production for April 2003 through December 2005 as
follows:
NYMEX CONTRACT PRICE PER BBL
----------------------------------------------------------------------
COLLARS
---------------------------------------------------------
FLOORS CEILINGS
SWAPS ------------------------- ---------------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED
PERIOD AND TYPE OF CONTRACT BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE
--------------------------- --------- --------- --------------- -------- ----------- --------
April 2003 - June 2003
Price swap contracts......... 272,000 $25.97 -- -- -- --
Collar contracts............. 631,000 -- $20.00 - $24.00 $ 22.14 $27.25 - $29.70 $27.86
July 2003 - September 2003
Price swap contracts......... 259,000 25.58 -- -- -- --
Collar contracts............. 707,000 -- 22.00 - 24.00 22.53 26.35 - 29.70 27.78
October 2003 - December 2003
Price swap contracts......... 144,000 25.55 -- -- -- --
Collar contracts............. 627,000 -- 22.00 - 24.00 22.47 26.35 - 29.70 27.83
January 2004 - December 2004
Price swap contracts......... 96,000 23.23 -- -- -- --
Collar contracts............. 405,000 -- 22.00 22.00 26.35 26.35
January 2005 - December 2005
Price swap contracts......... 204,000 22.63 -- -- -- --
NYMEX CONTRACT PRICE PER BBL
----------------------------
FLOOR CONTRACTS ESTIMATED
------------------------ FAIR VALUE
WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT RANGE AVERAGE (IN MILLIONS)
--------------------------- ----- -------- -----------------
April 2003 - June 2003
Price swap contracts......... -- -- $ (0.9)
Collar contracts............. -- -- (1.7)
July 2003 - September 2003
Price swap contracts......... -- -- (0.4)
Collar contracts............. -- -- (1.4)
October 2003 - December 2003
Price swap contracts......... -- -- (0.1)
Collar contracts............. -- -- (0.7)
January 2004 - December 2004
Price swap contracts......... -- -- (0.1)
Collar contracts............. -- -- (1.6)
January 2005 - December 2005
Price swap contracts......... -- -- (0.3)
------
$ (7.2)
======
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
We are an independent oil and gas company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. Our
company was founded in 1989 and we acquired our first property in 1990. Our
initial focus area was the Gulf of Mexico. In the mid-1990s we began to expand
our operations to other select areas. Our areas of operation now include the
U.S. onshore Gulf Coast, West Texas, the Anadarko Basin and offshore northwest
Australia. Unless otherwise specified or the context otherwise requires, all
references in these notes to "Newfield," "we," "us" or "our" are to Newfield
Exploration Company and its subsidiaries. If you are not familiar with any of
the oil and gas terms used in this report, please refer to the explanation of
such terms under the caption "Commonly Used Oil and Gas Terms" at the end of
this item.
Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas and our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. A substantial or
extended decline in the prices for oil or gas could have a material adverse
effect on us. The preparation of our financial statements in conformity with
generally accepted accounting principles requires us to make estimates and
assumptions that affect our reported results of operations and the amount of
reported assets, liabilities and proved oil and gas reserves. Actual results
could differ from these estimates and assumptions. We use the full cost method
of accounting for our oil and gas activities.
OIL AND GAS PRICES. Prices for oil and gas fluctuate widely. Oil and gas
prices affect:
- the amount of cash flow available for capital expenditures;
- our ability to borrow and raise additional capital;
- the amount of oil and gas that we can economically produce; and
- the accounting for our oil and gas activities.
We generally hedge a substantial, but varying, portion of our anticipated
future oil and gas production to, among other things, reduce our exposure to
commodity price fluctuations.
RESERVE REPLACEMENT. 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 and acquire oil
and gas reserves.
SIGNIFICANT ESTIMATES. We believe the most difficult, subjective or complex
judgments and estimates we must make in connection with the preparation of our
financial statements are:
- remaining proved oil and gas reserves;
- timing of our future drilling activities;
- future costs to develop and abandon our oil and gas properties;
- allocating the purchase price associated with business combinations; and
- the valuation of our derivative positions.
Please see "Critical Accounting Policies and Estimates" and "Other Factors
Affecting Our Business and Financial Results" in Item 7 of our annual report
for the year ended December 31, 2002 for a more detailed discussion of the
foregoing matters and a discussion of a number of other factors that affect our
business, financial condition and results of operations. This report should be
read together with these discussions.
15
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 period to period as a
result of changes in commodity prices. Revenues for the first quarter of 2003
were 89% higher than the first quarter of 2002 because of higher commodity
prices and higher production.
THREE MONTHS ENDED
MARCH 31,
---------------------
2003 2002
--------- ---------
PRODUCTION:
United States:
Natural gas (Bcf).................. 44.0 33.9
Oil and condensate (MBbls)......... 1,516.4 1,349.5
Total (Bcfe)....................... 53.1 42.0
Australia(1):
Oil (MBbls)........................ 357.6 298.3
Total:
Natural gas (Bcf).................. 44.0 33.9
Oil and condensate (MBbls)......... 1,873.9 1,647.8
Total (Bcfe)....................... 55.2 43.8
AVERAGE REALIZED PRICES(2):
United States:
Natural gas (per Mcf).............. $ 5.05 $ 3.26
Oil and condensate (per Bbl)....... 29.03 22.03
Australia:
Oil (per Bbl)...................... $ 31.86 $ 22.01
Total:
Natural gas (per Mcf).............. $ 5.05 $ 3.26
Oil and condensate (per Bbl)....... 29.57 22.03
Natural gas equivalent (per Mcfe).. 5.03 3.35
- -----------
(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 $0.02 and $0.03 for the
three months ended March 31, 2003 and 2002, respectively. The realized
price of oil and condensate was reduced by $0.27 and $0.23 for the three
months ended March 31, 2003 and 2002, respectively. Average realized prices
include the effects of hedging.
PRODUCTION. Our total oil and gas production (stated on a natural gas
equivalent basis) increased 26% in the first quarter of 2003 when compared to
the same period in 2002. Production increased primarily because of our
acquisition of EEX, other small acquisitions and successful drilling efforts.
NATURAL GAS. Our first quarter 2003 natural gas production increased 30%
when compared to the first quarter of 2002. The increase was primarily the
result of the acquisition of EEX in late 2002 and successful drilling in the
Gulf of Mexico. The gains in production were partially offset by natural field
declines from other producing properties.
CRUDE OIL AND CONDENSATE. Our first quarter 2003 oil production increased
14% over the first quarter of 2002. These increases were primarily the result of
the timing of liftings of oil from our FPSOs in Australia. While actual
Australian production during the first quarter of 2003 was lower than production
during the same period of 2002, more oil was lifted and sold during the first
quarter of 2003.
16
EFFECT OF HEDGING ON REALIZED PRICES. The following table presents
information about the effect of our hedging program on realized prices.
AVERAGE
REALIZED PRICES RATIO OF
-------------------------- HEDGED TO
WITH WITHOUT NON-HEDGED
HEDGE HEDGE PRICE(1)
------- ------- ----------
Natural Gas:
Three months ended March 31, 2003................. $ 5.05 $ 6.30 80%
Three months ended March 31, 2002................. 3.26 2.30 142%
Crude Oil and Condensate:
Three months ended March 31, 2003................. $ 29.57 $32.34 91%
Three months ended March 31, 2002................. 22.03 20.64 107%
- --------------------
(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 first quarter of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT
(PER MCFE) (IN THOUSANDS)
------------------------------------ ----------------------------------------
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, PERCENTAGE MARCH 31, PERCENTAGE
-------------------- INCREASE ----------------------- INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
------ ------ ---------- -------- -------- ----------
United States:
Lease operating........................... $ 0.52 $ 0.48 8% $ 27,807 $ 20,156 38%
Production and other taxes................ 0.19 0.08 138% 10,207 3,410 199%
Transportation............................ 0.03 0.03 -- 1,563 1,331 17%
Depreciation, depletion and amortization.. 1.76 1.66 6% 93,318 69,633 34%
General and administrative (exclusive of
stock compensation)..................... 0.31 0.27 15% 16,315 11,236 45%
Total operating..................... 2.81 2.52 12% 149,210 105,766 41%
Australia:
Lease operating........................... $ 2.07 $ 1.62 28% $ 4,449 $ 2,897 54%
Production and other taxes................ 1.10 -- -- 2,367 -- --
Transportation............................ -- -- -- -- -- --
Depreciation, depletion and amortization.. 1.58 0.88 80% 3,382 1,574 115%
General and administrative (exclusive of
stock compensation)..................... 0.27 0.30 (10%) 578 531 9%
Total operating..................... 5.02 2.80 79% 10,776 5,002 115%
Total:
Lease operating........................... $ 0.58 $ 0.53 9% $ 32,256 $ 23,053 40%
Production and other taxes................ 0.23 0.08 188% 12,574 3,410 269%
Transportation............................ 0.03 0.03 -- 1,563 1,331 17%
Depreciation, depletion and amortization.. 1.75 1.63 7% 96,700 71,207 36%
General and administrative (exclusive of
stock compensation(1)).................. 0.31 0.27 15% 16,893 11,767 44%
Total operating..................... 2.90 2.54 14% 159,986 110,768 44%
- -----------------
(1) Stock compensation charges were $679, or $0.01 per Mcfe, and $578, or $0.01
per Mcfe, for the three months ended March 31, 2003 and 2002, respectively.
Total operating expense, inclusive of these charges, was $160,665, or $2.91
per Mcfe, and $111,346, or $2.54 per Mcfe, for the three months ended March
31, 2003 and 2002, respectively.
17
Our total operating expense for the first quarter of 2003, stated on a
unit-of-production basis, increased 14% over the same period in 2002. The
increase was primarily related to the following items.
DOMESTIC OPERATIONS:
- Lease operating expense for the first quarter of 2003 was 8% higher on
a Mcfe basis than the first quarter of 2002 primarily due to workovers
along the onshore Gulf Coast in South Louisiana and South Texas.
- Production taxes increased in the first quarter of 2003 due to higher
production and commodity prices when compared to the first quarter of
2002 and a greater percentage of our production (onshore) being subject
to production taxes.
- Our depreciation, depletion and amortization (DD&A) rate for our full
cost pool (which excludes furniture, fixtures and equipment) for the
first quarter of 2003 was $1.70 on a unit-of-production basis compared
to $1.64 for the first quarter of 2002. The increase is a result of the
increased cost of reserve additions since the first quarter of 2002.
DD&A for the first quarter of 2003 also includes approximately $0.03 on
a unit-of-production basis attributable to the accretion of our Asset
Retirement Obligation associated with SFAS No. 143 (see "--Adoption of
SFAS No. 143 below).
- General and administrative expense increased primarily because of
higher incentive compensation expense and our growing domestic
workforce. Partially offsetting higher general and administrative
expense was an increase in capitalized direct internal costs. During
the first quarter of 2003, we capitalized $6.8 million of direct
internal costs. During the first quarter of 2002, we capitalized $2.3
million.
AUSTRALIAN OPERATIONS:
- Lease operating expense for the first quarter of 2003 was 28% higher
on a unit-of-production basis due to the weakening of the U.S. dollar
compared to the Australian dollar and increased costs of purchased fuel
for the operation of our FPSOs in Australia.
- Australian capital expenditures are deductible against production taxes
otherwise payable. Production taxes are due on a June 30 fiscal year.
We accrue production taxes during the tax fiscal year based on our
estimate of revenues and capital expenditures for the fiscal year. As a
result of actual and anticipated capital expenditures during the period
from July 2001 to June 2002, no Australian production taxes were
recorded in the first quarter of 2002.
- The DD&A increase was primarily a result of our unsuccessful
exploratory drilling efforts in 2002.
INTEREST EXPENSE. In the first quarter of 2003, interest expense increased
compared to the first quarter of 2002 primarily because of debt incurred in
connection with the EEX acquisition in late 2002.
THREE MONTHS ENDED
MARCH 31,
-------------------------
2003 2002
-------- --------
(IN MILLIONS)
Gross interest expense..................................... $ 16.7 $ 7.2
Capitalized interest....................................... (3.8) (2.1)
-------- --------
Net interest expense....................................... 12.9 5.1
Distributions on preferred securities...................... 2.3 2.3
-------- --------
Total interest expense and distributions............ $ 15.2 $ 7.4
======== ========
18
UNREALIZED COMMODITY DERIVATIVE EXPENSE. The $1.2 million of expense for
the first quarter of 2003 represented the hedge ineffectiveness associated with
our hedging program. The unrealized expense of $5.6 million during the first
quarter of 2002 primarily reflects the reversal of the time value gains that
were previously recognized during 2001. For a further description of these
items, please see Note 7, "Commodity Derivative Instruments and Hedging
Activities," to our consolidated financial statements appearing earlier in this
section.
OTHER. First quarter 2003 other expenses consisted of $2.0 million in
foreign currency transaction losses. The first quarter of 2002 reflects a
reversal of accruals of certain contingencies related to our acquisition of Gulf
Australia in 1999. Offsetting this net gain were foreign currency losses of $1.0
million.
TAXES. The effective tax rate for the first quarter of 2003 and the first
quarter of 2002 were about the same.
GAS SALES OBLIGATION SETTLEMENT. Pursuant to a gas forward sales contract
entered into in 1999, EEX committed to deliver approximately 50 Bcf of
production to Bob West Treasure L.L.C. (BWT) in exchange for proceeds of $105
million. As of the date of our acquisition of EEX, we recorded a liability of
approximately $62 million, which represented the then current market value of
approximately 16 Bcf of reserves remaining under the gas sales contract. We
Accounted for the obligation under the gas sales contract as debt in our
consolidated balance sheet.
On March 31, 2003, pursuant to a settlement agreement with BWT and the
other parties to related transactions, the gas sales contract, the swaps entered
into by BWT in connection with the gas sales contract and all other agreements
related to the gas sales contract, including the guarantee and all liens and
other security interests on EEX's properties, were terminated in exchange for a
payment by us of approximately $73 million. This payment represented:
o the remaining unamortized obligation under the gas sales contract;
o the fair market value of certain swaps entered into by BWT in conjunction
with the gas sales contract;
o various transactions fees related to the termination; and
o as agreed upon value for BWT's limited membership interest in EEX
subsidiary.
In connection with the settlement, we recognized a loss of $10 million
under the caption "Loss on gas sales obligation settlement" in our consolidated
income statement. About $9 million of the loss was related to the change in the
fair market value of the committed production and the swaps between the
acquisition date and the settlement date.
As a result of the termination of the gas sales contract, the remaining
committed volumes of approximately 6.0 Bcf for 2003 and 6.7 Bcf for 2004 became
available to be sold on the open market at current market prices. Simultaneously
with the termination of the gas sales contract, we hedged the May 2003 through
October 2003 volumes at a volume-weighted average price of $5.21 per MMBtu.
Proceeds from these previously committed volumes will be recognized in revenues.
ADOPTION OF SFAS NO. 143. We adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," as of January 1, 2003. The statement changes the method
of accounting for costs associated with the retirement of long-lived assets
(e.g. oil and gas production facilities, etc.) that we are obligated to incur.
The statement requires 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 asset retirement cost be capitalized as part of the carrying
amount of the associated asset. Under our previous accounting method, we
recognized the cost to abandon our oil and gas properties over their productive
lives on a unit-of-production basis.
Upon initial application of SFAS No. 143, a cumulative effect of a change
in accounting principle was required in order to recognize a liability for our
existing asset retirement obligation (ARO) adjusted as required by SFAS No. 143.
The amount of that liability at March 31, 2003 is reflected on our consolidated
balance sheet under the caption "Asset retirement obligation" We also recorded a
$160.4 million increase in the net capitalized costs of our oil and gas
properties and recognized an after-tax gain of $5.6 million for the cumulative
effect of the change in accounting principle.
Subsequent to initial measurement of our ARO, liabilities will be
accreted to their present value each period (resulting in additional DD&A
expense) and the capitalized asset retirement costs will be depreciated over the
estimated useful life of the related assets.
For further discussion of SFAS No. 143 and the effects of our adoption of
this standard, please see Note 1, "Organization and Summary of Significant
Accounting Policies - New Accounting Standards - Accounting for Asset Retirement
Obligations," to our consolidated financial statements appearing earlier in this
report.
19
LIQUIDITY AND CAPITAL RESOURCES
Our 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
relates to the contractual obligations to invest in particular properties. 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.
We anticipate that our 2003 capital expenditures will be funded from cash
flow from operations. Based on current commodity prices and our hedges, we
currently anticipate that our cash flow will significantly exceed our 2003
capital budget (which is discussed in greater detail below). This excess should
allow us to pay down debt or repurchase shares of our common stock during the
year. To the extent that cash receipts during the remainder of the year are
lower than capital needs, we will make up the shortfall with borrowings under
our credit arrangements.
CREDIT ARRANGEMENTS AND DEBT. We maintain our reserve-based revolving
credit facility with JPMorgan Chase Manhattan Bank, as agent. The facility
matures on January 23, 2005. The banks participating in the facility have
committed to lend us 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. The borrowing base is reduced by the principal amount of
outstanding senior notes ($300 million at April 30, 2003), 30% of the principal
amount of any outstanding senior subordinated notes (a reduction of $75 million
at April 30, 2003) and the outstanding principal amount of the secured notes
($32 million at April 30, 2003). The borrowing base will be redetermined at
least semi-annually and, after reduction for the foregoing items, was $323.0
million at April 30, 2003. 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.
We also have money market lines of credit with various banks. Our credit
facility limits our borrowings under these lines to $40 million. At April 30,
2003, we had outstanding borrowings under our credit facility of $165 million
and no outstanding borrowings under our money market lines. Consequently, at
April 30, 2003, we had approximately $198 million of available capacity under
our credit arrangements.
At March 31, 2003 and December 31, 2002, the interest rate was 2.75% and
3.25%, respectively, for LIBOR based loans under our credit facility and 2.56%
and 3.18%, respectively, for the loans outstanding under the money market lines
of credit.
For further information regarding our outstanding debt as of March 31,
2003, please see Note 4, "Debt," to our consolidated financial statements
appearing earlier in this report. During early May 2003, we repurchased secured
notes with an aggregate outstanding principal amount of $21.1 million.
WORKING CAPITAL. Our working capital balance fluctuates as a result of the
timing and amount of borrowings or repayments under our credit arrangements.
Generally, we use excess cash to pay down borrowings under our credit
arrangements. We had a working capital surplus of $36.2 million as of March 31,
2003. This compares to a working capital deficit of $57.0 million as of December
31, 2002.
CASH FLOW FROM OPERATIONS. Our net cash from operations for the first
quarter of 2003 declined 33% compared to the first quarter of 2002. This
decrease was primarily due to higher working capital requirements partially
offset by higher operating income primarily due to higher commodity prices.
CAPITAL EXPENDITURES. Our capital spending during the first quarter of 2003
was $122.7 million, a 48% increase over the same period last year. During the
first quarter of 2003, we invested approximately $37 million in proved and
unproved property acquisitions, $43 million in U.S. development, $33 million in
U.S. exploration, $4 million in other U.S. operations and $6 million
internationally.
20
We budgeted $450 million for capital spending in 2003. The budget includes
$26 million for an acquisition completed in the first quarter of 2003; otherwise
the budget excludes potential acquisitions. We expect that 55-60% of this budget
will be invested in the Gulf of Mexico (including deepwater), 35-40% in onshore
U.S. and the balance in international projects. We continue to pursue attractive
acquisition opportunities; however, the timing, size and purchase price of
acquisitions are unpredictable. Historically, we have completed several
acquisitions of varying sizes each year. Depending on the timing of an
acquisition, we may spend additional capital during the year of acquisition for
drilling and development activities on the acquired properties.
HEDGING
We generally hedge a substantial, but varying, portion of our anticipated
oil and gas production for the next 18-24 months as part of our risk management
program. We use hedging to reduce price volatility, help ensure that we have
adequate cash flow to fund our capital programs and manage price risks and
return on some of our acquisitions. Our decision on the quantity and price at
which we choose to hedge our production is based in part on our view of current
and future market conditions. Approximately 78% of our production on an Mcfe
basis target for the nine months ending December 31, 2003 is hedged. 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.
Please see the discussion and tables in Note 7, "Commodity Derivative
Instruments and Hedging Activities," to our consolidated financial statements
appearing earlier in this report for a further description of our hedging
program and a listing of open hedging contracts as of March 31, 2003 and the
fair value of those contracts as of that date. Between March 31, 2003 and May
12, 2003, we did not enter into any hedging transactions.
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 of our hedged natural gas production is sold at market prices
that historically have highly correlated to the settlement price. Because
substantially all of our U.S. Gulf Coast production is sold at current market
prices that historically have highly correlated to the NYMEX West Texas
Intermediate price, we believe that we have no material basis risk with respect
to our oil hedging transactions. The actual cash price we receive, however,
generally is about $2.00 per barrel less than the NYMEX West Texas Intermediate
price when adjusted for location and quality differences. Our Australian
production is not hedged.
21
NEW ACCOUNTING STANDARDS
We adopted SFAS No. 143, "Accounting for Asset Retirement
Obligations," as of January 1, 2003. The statement changes the method of
accounting for costs associated with the retirement of long-lived assets (e.g.
oil and gas production facilities, etc.) that we are obligated to incur. The
statement requires 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 asset retirement cost be capitalized as part of the carrying
amount of the associated asset. Under our previous accounting method, we
recognized the cost to abandon our oil and gas properties over their productive
lives on a unit-of-production basis. For a further discussion of SFAS No. 143
and the effects of our adoption of this standard, please see "-- Results of
Operations -- Adoption of SFAS No. 143" and Note 1, "Organization and Summary of
Significant Accounting Policies -- New Accounting Standards -- Accounting for
Asset Retirement Obligations," to our consolidated financial statements
appearing earlier in this report.
For a discussion of other recently issued accounting standards and
interpretations, please see "-- Results of Operations -- Adoption of SFAS No.
143" and Note 1, "Organization and Summary of Significant Accounting Policies --
New Accounting Standards -- Other Standards," to our consolidated financial
statements appearing earlier in this report.
22
GENERAL INFORMATION
General information about us can be found at www.newfld.com. In conjunction
with our web page, we also maintain our electronic publication entitled @NFX.
@NFX is periodically published to provide updates on our operating activities
and 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 [email protected] or visit our web page and sign up.
Our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current
reports on Form 8-K, as well as any amendments and exhibits to those reports,
are available free of charge through our website as soon as reasonably
practicable after we file or furnish them to the SEC.
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 and anticipated
cash flow. 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.
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, used
herein in reference to crude oil or condensate.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil or condensate.
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 or
condensate.
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 or
condensate.
NYMEX. The New York Mercantile Exchange.
23
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk from changes in oil and gas prices, interest
rates and foreign currency exchange rates as discussed below:
OIL AND GAS PRICES
We generally hedge a substantial, but varying, portion of our anticipated
oil and gas production for the next 18-24 months as part of our risk management
program. We use hedging to reduce price volatility, help ensure that we have
adequate cash flow to fund our capital programs and manage price risks and
return on some of our acquisitions. Our decision on the quantity and price at
which we choose to hedge our production is based in part on our view of current
and future market conditions. While hedging limits the downside risk of adverse
price movements, it may also limit future revenues from favorable price
movements. Please see the discussion and tables in Note 7, "Commodity Derivative
Instruments and Hedging Activities," to our consolidated financial statements
appearing earlier in this report and the discussion under the caption "Hedging"
in Item 2 of this report for a further description of our hedging program and a
listing of open hedging contracts as of March 31, 2003 and the fair value of
those contracts as of that date.
INTEREST RATES AND FOREIGN CURRENCY EXCHANGE RATES
We considered our interest rate exposure at March 31, 2003 to be minimal
because the majority, about 74%, of our long-term debt obligations were at fixed
rates. At March 31, 2003, we had no open interest rate hedge positions to affect
our exposure to changes in interest rates.
Our cash flow from certain international operations is based on the U.S.
dollar equivalent of cash flows measured in foreign currencies. We consider our
current risk exposure to exchange rate movements, based on net cash flows, to be
immaterial. We did not have any open derivative contracts relating to foreign
currencies at March 31, 2003.
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 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.
24
PART II
ITEM 1. LITIGATION
We have been named as a defendant in certain lawsuits in the ordinary
course of business. While the outcome of these lawsuits cannot be predicted with
certainty, we do not expect these matters to have a material adverse effect on
our financial position, cash flows or results of operations.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Not applicable this quarter.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable this quarter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable this quarter.
ITEM 5. OTHER INFORMATION
The following disclosure is being provided in accordance with the SEC's
filing guidance regarding the provision of notice of certain information
relating to a pension fund blackout period pursuant to new Item 11 of Form 8-K.
Among other restrictions, our insider trading policy generally prohibits
our directors and all of our officers and employees from trading in our
securities during the period beginning on the first day of each calendar quarter
and ending at the close of trading on the second trading following the release
of our earnings announcement for that quarter. As a result, a "blackout period"
(as defined in Regulation BTR promulgated under the Securities Exchange Act of
1934) commenced on April 1, 2003 and ended after the close of trading on April
25, 2003. During the blackout period, the participants in our 401(k) Plan were
prohibited from changing the percentage of future contributions to be invested
in our common stock investment option under the plan and from transferring or
reallocating prior contributions from or to our common stock investment option.
Inquiries about the blackout period may be directed to C. William Austin by
phone at (281) 847-6069 or in writing to Newfield Exploration Company, 363 N.
Sam Houston Parkway E., Suite 2020, Houston, Texas 77060.
25
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit Number Description
- -------------- -----------
10.1 Fifth Amendment Agreement, dated as of March 24, 2003, among
Newfield, JPMorgan Chase Bank (formerly known as The Chase
Manhattan Bank), as Agent, the lenders signatory thereto and
the terminating banks signatory thereto amending the Credit
Agreement, dated as of January 23, 2001, among Newfield, The
Chase Manhattan Bank, as Agent, and the banks signatory
thereto
99.1 Certification of Chief Executive Officer of Newfield pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
99.2 Certification of Chief Financial Officer of Newfield pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
(b) Reports on Form 8-K:
On February 19, 2003, we filed a Current Report on Form 8-K
announcing that we had hedged additional production.
On February 13, 2003, we filed a Current Report on Form 8-K
announcing our financial and operating results for the fourth quarter
and full-year 2002 and furnishing operating and financial guidance for
2003 and the first quarter of 2003.
On February 10, 2003, we filed a Current Report on Form 8-K/A
with respect to our acquisition of EEX to provide the required
historical and pro forma financial information. The following financial
statements were filed with the report:
o EEX's consolidated financial statements as of December 31,
2000 and 2001 and for each of the calendar years in the three
year period ending December 31, 2001 and related notes;
o EEX's consolidated financial statements as of September 30,
2001 and 2002 and for each of the three month and nine month
periods then ended and related notes; and
o our unaudited pro forma combined condensed financial
statements as of September 30, 2002 and for the nine months
ended September 30, 2002 and the calendar year ended December
31, 2001 that give effect to our acquisition of EEX and the
issuance of our 8 3/8% Senior Subordinated Notes due 2012.
On January 23, 2003, we filed a Current Report on Form 8-K
providing an operational update and furnishing 2003 production
guidance.
26
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: May 13, 2003 By: /s/ TERRY W. RATHERT
---------------------------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal Financial Officer)
27
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 significant
deficiencies and material weaknesses.
Date: May 13, 2003 /s/ DAVID A. TRICE
-------------------------------------
David A. Trice
President and Chief Executive Officer
28
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):
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 significant
deficiencies and material weaknesses.
Date: May 13, 2003 /s/ TERRY W. RATHERT
------------------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
29
EXHIBIT INDEX
Exhibit Number Description
- -------------- -----------
10.1 Fifth Amendment Agreement, dated as of March 24, 2003, among Newfield, JPMorgan Chase Bank
(formerly known as The Chase Manhattan Bank), as Agent, the lenders signatory thereto and the
terminating banks signatory thereto amending the Credit Agreement, dated as of January 23,
2001, among Newfield, The Chase Manhattan Bank, as Agent, and the banks signatory thereto
99.1 Certification of Chief Executive Officer of Newfield pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.2 Certification of Chief Financial Officer of Newfield pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002