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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 JUNE 30, 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 August 5, 2003, there were 55,809,524 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 June 30, 2003 and December 31, 2002................................. 1
Consolidated Statement of Income for the three and six months ended
June 30, 2003 and 2002............................................................................... 2
Consolidated Statement of Cash Flows for the six months ended
June 30, 2003 and 2002............................................................................... 3
Consolidated Statement of Stockholders' Equity for the six months
ended June 30, 2003.................................................................................. 4
Notes to Consolidated Financial Statements........................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................................................ 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk.............................................. 29
Item 4. Controls and Procedures................................................................................. 29
PART II
Item 1. Litigation.............................................................................................. 30
Item 2. Changes in Securities and Use of Proceeds............................................................... 30
Item 3. Defaults upon Senior Securities......................................................................... 30
Item 4. Submission of Matters to a Vote of Security Holders..................................................... 30
Item 5. Other Information....................................................................................... 31
Item 6. Exhibits and Reports on Form 8-K........................................................................ 31
ii
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
ASSETS
Current assets:
Cash and cash equivalents ................................................ $ 44,423 $ 48,898
Accounts receivable--oil and gas ......................................... 168,246 130,489
Inventories .............................................................. 14,474 7,910
Commodity derivatives .................................................... 11,039 2,655
Deferred taxes ........................................................... 15,031 12,801
Other current assets ..................................................... 28,301 36,074
----------- ------------
Total current assets ................................................. 281,514 238,827
----------- ------------
Oil and gas properties (full cost method, of which $299,493 at June 30, 2003
and $268,732 at December 31, 2002 were excluded from amortization) ....... 3,712,802 3,349,254
Less--accumulated depreciation, depletion and amortization ................... (1,495,982) (1,339,249)
----------- ------------
2,216,820 2,010,005
----------- ------------
Assets held for sale ......................................................... 35,000 35,000
Furniture, fixtures and equipment, net ....................................... 7,877 8,030
Commodity derivatives ........................................................ 4,057 4,439
Other assets ................................................................. 17,223 19,452
----------- ------------
Total assets ......................................................... $ 2,562,491 $ 2,315,753
=========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ......................................................... $ 9,619 $ 27,593
Current portion of secured notes payable ................................. 1,168 11,215
Accrued liabilities ...................................................... 182,062 203,776
Advances from joint owners ............................................... 4,434 3,613
Current portion of asset retirement obligation ........................... 9,498 --
Commodity derivatives .................................................... 58,562 49,610
----------- ------------
Total current liabilities ............................................ 265,343 295,807
----------- ------------
Other liabilities ............................................................ 14,229 16,976
Commodity derivatives ........................................................ 13,513 10,610
Long-term debt ............................................................... 692,943 709,615
Asset retirement obligation .................................................. 161,691 --
Deferred taxes ............................................................... 151,455 129,309
----------- ------------
Total long-term liabilities .......................................... 1,033,831 866,510
----------- ------------
Company-obligated, mandatorily redeemable, convertible preferred securities of
Newfield Financial Trust I ............................................... -- 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;
56,676,729 and 52,603,662 shares issued and outstanding
at June 30, 2003 and December 31, 2002, respectively) ................ 567 526
Additional paid-in capital ................................................... 781,243 636,317
Treasury stock (at cost; 883,649 and 872,927 shares at June 30, 2003 and
December 31, 2002, respectively) ......................................... (26,575) (26,213)
Unearned compensation ........................................................ (12,482) (6,479)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment .................................. 6,722 (3,888)
Commodity derivatives .................................................... (32,377) (27,295)
Retained earnings ............................................................ 546,219 436,263
----------- ------------
Total stockholders' equity ........................................... 1,263,317 1,009,231
----------- ------------
Total liabilities and stockholders' equity ........................... $ 2,562,491 $ 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Oil and gas revenues ....................................................... $ 255,552 $ 161,611 $ 534,836 $ 309,650
--------- --------- --------- ---------
Operating expenses:
Lease operating ........................................................ 26,582 25,706 58,838 48,759
Production and other taxes ............................................. 6,532 3,861 19,106 7,271
Transportation ......................................................... 1,859 1,316 3,422 2,647
Depreciation, depletion and amortization ............................... 99,660 78,027 196,360 149,234
Ceiling test writedown ................................................. 7,300 -- 7,300 --
General and administrative (includes stock compensation of $807
and $757 for the three months ended June 30, 2003 and 2002,
respectively, and $1,486 and $1,335 for the six months ended
June 30, 2003 and 2002, respectively) ................................ 15,672 12,963 33,254 25,308
Gas sales obligation settlement and redemption of securities ........... 10,477 -- 20,475 --
--------- --------- --------- ---------
Total operating expenses .......................................... 168,082 121,873 338,755 233,219
--------- --------- --------- ---------
Income from operations ..................................................... 87,470 39,738 196,081 76,431
Other income (expenses):
Interest expense ....................................................... (14,982) (7,134) (31,668) (14,348)
Capitalized interest ................................................... 3,899 2,130 7,718 4,273
Dividends on convertible preferred securities of
Newfield Financial Trust I ........................................... (2,245) (2,336) (4,581) (4,672)
Unrealized commodity derivative expense ................................ (1,629) (5,880) (2,846) (11,525)
Other .................................................................. (3,091) (1,247) (4,320) 569
--------- --------- --------- ---------
(18,048) (14,467) (35,697) (25,703)
--------- --------- --------- ---------
Income before income taxes ................................................. 69,422 25,271 160,384 50,728
Income tax provision (benefit):
Current ................................................................ 13,031 10,195 36,670 16,422
Deferred ............................................................... 10,576 (1,194) 19,333 1,710
--------- --------- --------- ---------
23,607 9,001 56,003 18,132
--------- --------- --------- ---------
Income before cumulative effect of change in accounting principle .......... 45,815 16,270 104,381 32,596
Cumulative effect of change in accounting principle, net of tax:
Adoption of SFAS No. 143 ............................................... -- -- 5,575 --
--------- --------- --------- ---------
Net income ........................................................ $ 45,815 $ 16,270 $ 109,956 $ 32,596
========= ========= ========= =========
Earnings per share:
Basic --
Income before cumulative effect of change in accounting principle .... $ 0.86 $ 0.37 $ 1.98 $ 0.74
Cumulative effect of change in accounting principle, net of tax ...... -- -- 0.11 --
--------- --------- --------- ---------
Net income ........................................................ $ 0.86 $ 0.37 $ 2.09 $ 0.74
========= ========= ========= =========
Diluted --
Income before cumulative effect of change in accounting principle .... $ 0.82 $ 0.36 $ 1.88 $ 0.73
Cumulative effect of change in accounting principle, net of tax ...... -- -- 0.10 --
--------- --------- --------- ---------
Net income ........................................................ $ 0.82 $ 0.36 $ 1.98 $ 0.73
========= ========= ========= =========
Weighted average number of shares outstanding for basic earnings per share 53,468 44,376 52,679 44,295
========= ========= ========= =========
Weighted average number of shares outstanding for diluted earnings per share 57,701 48,928 56,956 48,838
========= ========= ========= =========
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)
SIX MONTHS ENDED
JUNE 30,
----------------------------
2003 2002
----------- -----------
Cash flows from operating activities:
Net income .......................................................... $ 109,956 $ 32,596
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization ......................... 196,360 149,234
Ceiling test writedown ........................................... 7,300 --
Gas sales obligation settlement and redemption of securities ..... 20,475 --
Stock compensation ............................................... 1,486 1,335
Unrealized commodity derivative expense .......................... 2,846 11,525
Deferred taxes ................................................... 19,333 1,710
Cumulative effect of change in accounting principle .............. (5,575) --
Changes in operating assets and liabilities:
Increase in accounts receivable -- oil and gas ................ (45,962) (27,919)
Decrease in inventories ....................................... 796 1,239
Decrease (increase) in other current assets ................... (2,825) 3,301
Decrease in other assets ...................................... 2,545 577
Increase (decrease) in accounts payable and accrued
liabilities.................................................. (28,846) 17,945
Decrease in advances from joint owners ........................ 822 2,288
Increase (decrease) in other liabilities ...................... (1,201) 2,597
----------- -----------
Net cash provided by operating activities ................. 277,510 196,428
----------- -----------
Cash flows from investing activities:
Additions to oil and gas properties ................................. (231,572) (164,983)
Additions to furniture, fixtures and equipment ...................... (2,404) (1,557)
----------- -----------
Net cash used in investing activities ..................... (233,976) (166,540)
----------- -----------
Cash flows from financing activities:
Proceeds from borrowings under credit arrangements .................. 1,019,000 261,000
Repayments of borrowings under credit arrangements .................. (915,000) (314,000)
Proceeds from issuance of common stock .............................. 137,683 4,829
Purchases of treasury stock ......................................... (362) (336)
Repurchases of secured notes ........................................ (59,595) --
Repayments of secured notes ......................................... (11,215) --
Deliveries under the gas sales obligation ........................... (8,442) --
Gas sales obligation settlement ..................................... (62,017) --
Redemption of trust preferred securities ............................ (148,448) --
----------- -----------
Net cash used in financing activities ..................... (48,396) (48,507)
----------- -----------
Effect of exchange rate changes on cash and cash equivalents ............ 387 (334)
----------- -----------
Decrease in cash and cash equivalents ................................... (4,475) (18,953)
Cash and cash equivalents, beginning of period .......................... 48,898 26,610
----------- -----------
Cash and cash equivalents, end of period ................................ $ 44,423 $ 7,657
=========== ===========
The accompanying notes to consolidated financial statements
are an integral part of this financial statement.
3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
ACCUMULATED
COMMON STOCK TREASURY STOCK ADDITIONAL OTHER TOTAL
------------------ ------------------- PAID-IN UNEARNED RETAINED COMPREHENSIVE STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION EARNINGS INCOME (LOSS) EQUITY
---------- ------- -------- -------- -------- ------------ -------- ------------- -------------
BALANCE, DECEMBER 31, 2002.. 52,603,662 $ 526 (872,927) $(26,213) $636,317 $ (6,479) $436,263 $ (31,183) $1,009,231
Issuance of common stock... 3,850,103 39 135,896 135,935
Issuance of restricted
stock, less
amortization of $312... 222,964 2 7,487 (7,177) 312
Treasury stock, at cost.... (10,722) (362) (362)
Amortization of stock
compensation........... 1,174 1,174
Tax benefit from exercise
of stock options....... 1,543 1,543
Comprehensive income:
Net income............... 109,956 109,956
Foreign currency
translation
adjustment, net of tax
of $5,713.............. 10,610 10,610
Reclassification
adjustments for settled
contracts, net of tax
of $14,781............. (27,452) (27,452)
Changes in fair value of
outstanding hedging
positions, net of tax
of $12,080............. 22,370 22,370
----------
Total comprehensive
income............... 115,484
---------- ------- -------- -------- -------- -------- -------- --------- ----------
BALANCE, JUNE 30, 2003...... 56,676,729 $ 567 (883,649) $(26,575) $781,243 $(12,482) $546,219 $ (25,655) $1,263,317
========== ======= ======== ======== ======== ======== ======== ========= ==========
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 also 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 our financial statements in conformity with generally
accepted accounting principles requires our management 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.
RECLASSIFICATIONS
Certain reclassifications have been made to reported amounts for prior
periods 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 and
six months ended June 30, 2003 and 2002 would have approximated the pro forma
amounts below:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------- ----------------------------
2003 2002 2003 2002
---------- ----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income:
As reported ........................ $ 45,815 $ 16,270 $ 109,956 $ 32,596
Pro forma stock-based compensation
expense (net of taxes) ........... (1,765) (1,417) (3,426) (2,685)
Pro forma .......................... 44,050 14,853 106,530 29,911
Earnings per share:
Basic - as reported
Income before cumulative effect of
change in accounting principle.. $ 0.86 $ 0.37 $ 1.98 $ 0.74
Cumulative effect of change in
accounting principle ........... -- -- 0.11 --
---------- ----------- ----------- -----------
Net income ......................... $ 0.86 $ 0.37 $ 2.09 $ 0.74
========== =========== =========== ===========
Basic - pro forma
Income before cumulative effect of
change in accounting principle.. $ 0.82 $ 0.33 $ 1.92 $ 0.68
Cumulative effect of change in
accounting principle ........... -- -- 0.11 --
---------- ----------- ----------- -----------
Net income ......................... $ 0.82 $ 0.33 $ 2.03 $ 0.68
========== =========== =========== ===========
Diluted - as reported
Income before cumulative effect of
change in accounting principle.. $ 0.82 $ 0.36 $ 1.88 $ 0.73
Cumulative effect of change in
accounting principle ........... -- -- 0.10 --
---------- ----------- ----------- -----------
Net income ......................... $ 0.82 $ 0.36 $ 1.98 $ 0.73
========== =========== =========== ===========
Diluted - pro forma
Income before cumulative effect of
change in accounting principle.. $ 0.79 $ 0.33 $ 1.82 $ 0.67
Cumulative effect of change in
accounting principle ........... -- -- 0.10 --
---------- ----------- ----------- -----------
Net income ......................... $ 0.79 $ 0.33 $ 1.92 $ 0.67
========== =========== =========== ===========
6
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," as
of January 1, 2003. This statement changes the method of accounting for expected
future costs associated with our obligation to perform site reclamation,
dismantle facilities and plug and abandon wells. Prior to January 1, 2003, we
recognized the undiscounted estimated cost to abandon our oil and gas properties
over their estimated productive lives on a unit-of-production basis and no
liability or capitalized costs associated with such abandonment were recorded on
our consolidated balance sheet. SFAS No. 143 requires that, if a reasonable
estimate of the fair value of an abandonment obligation can be made, a liability
(an "asset retirement obligation" or "ARO") will be recorded on our consolidated
balance sheet and the asset retirement cost will be capitalized in oil and gas
properties in the period in which the retirement obligation is incurred.
In general, the amount of an ARO and the costs capitalized will be equal to
the future cost to satisfy the abandonment obligation using current prices that
are escalated by an assumed inflation factor after discounting the future cost
back to the date that the abandonment obligation was incurred using an assumed
cost of funds for our company. After recording, these amounts, the ARO will be
accreted to its future estimated value using the same assumed cost of funds and
the additional capitalized costs will be depreciated on a unit-of-production
basis over the productive life of the related properties. Both the accretion and
the depreciation will be included in depreciation, depletion and amortization on
our consolidated statement of income.
At adoption of SFAS No. 143, a cumulative effect of change in accounting
principle was required in order to recognize:
- an initial ARO as a liability on our consolidated balance sheet;
- an increase in oil and gas properties for the cost to abandon our oil
and gas properties; and
- accumulated depreciation on the additional capitalized costs included
in oil and gas properties.
The initial ARO was established as described above but was accreted to January
1, 2003.
The change in our ARO since adoption of SFAS No. 143 is set forth below (in
thousands):
Initial ARO as of January 1, 2003............................... $ 151,929
Accretion expense............................................... 4,111
Foreign currency translation.................................... 4,237
Additions....................................................... 12,500
Satisfaction of ARO............................................. (1,588)
-----------
Balance of ARO as of June 30, 2003.............................. $ 171,189
===========
As a result of our adoption of SFAS No. 143, we 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 (the after-tax amount by which
additional capitalized costs, net of accumulated depreciation, exceeded the
initial ARO) for the cumulative effect of change in accounting principle. Had
SFAS No. 143 been applied retroactively to the six months ended June 30, 2002,
our net income and earnings per share (without any cumulative effect of change
in accounting principle) would have approximated the pro forma amounts below (in
thousands except per share amounts):
THREE MONTHS SIX MONTHS
ENDED ENDED
JUNE 30, 2002 JUNE 30, 2002
------------- -------------
Net income:
As reported .................. $ 16,270 $ 32,596
Pro forma .................... $ 15,819 $ 31,627
Earnings per share:
Basic--
As reported .................. $ 0.37 $ 0.74
Pro forma .................... $ 0.36 $ 0.71
Diluted--
As reported .................. $ 0.36 $ 0.73
Pro forma .................... $ 0.35 $ 0.70
7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER NEW ACCOUNTING 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." This statement provides guidance for
income statement classification 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 as of
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 as of January 1, 2003 has 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 30, 2003 (with a few
exceptions) and for hedging relationships designated after June 30, 2003. The
guidance is to be applied prospectively only. Our adoption of SFAS No. 149 as of
July 1, 2003 will have no effect on our financial statements.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement establishes standards for how an issuer classifies and measures on its
balance sheet certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances) because that financial instrument embodies an obligation of the
issuer. SFAS No. 150 was effective for financial instruments entered into or
modified after May 31, 2003, and was otherwise effective for us as of July 1,
2003. Our adoption of the applicable provisions of this statement as of the
indicated dates has had or will have no effect 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 had 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 were effective for us as of October 1, 2002.
The adoption of the applicable provisions of FIN 45 at the indicated dates has
not had a material effect on our financial statements.
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 VIEs. This new model for
consolidation applies to an entity for which either:
- the equity investors (if any) do not have a controlling financial
interest; or
- the equity investment at risk is insufficient to finance the 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. The provisions of this interpretation were effective for us on
January 1, 2003. Our adoption of the provisions of this statement as of
January 1, 2003 has had no effect our financial statements.
8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RECENT ACCOUNTING DEVELOPMENTS
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires
that all business combinations initiated after June 30, 2001 to be accounted for
using the purchase method and that certain intangible assets be disaggregated
and reported separately from goodwill. SFAS No. 142 establishes new guidelines
for accounting for goodwill and other intangible assets. Under the statement,
goodwill and certain other intangible assets are reviewed annually for
impairment but are not amortized. It is our understanding that the staffs of the
FASB and the Securities and Exchange Commission are currently considering the
appropriate application of SFAS Nos. 141 and 142 to oil and gas rights and
interests held under leases, governmental licenses or other contractual
arrangements (leasehold interests).
Based on our understanding of current discussions, if all leasehold
interests were deemed to be intangible assets, for companies like us that use
the full cost method of accounting for oil and gas activities:
- leasehold interests with proved reserves that were acquired after June
30, 2001 and leasehold interests with no proved reserves would be
classified as intangible assets and would not be included in oil and
gas properties on our consolidated balance sheet;
- our results of operations and cash flows would not be affected because
leasehold costs would continue to be amortized in accordance with full
cost accounting rules; and
- the disclosures required by SFAS Nos. 141 and 142 relative to
intangibles would be included in the notes to our financial
statements.
If SFAS Nos. 141 and SFAS 142 were applied as described above, at June 30,
2003 we had undeveloped leasehold interests of approximately $250 million
(without reduction for depreciation) that would be classified on our
consolidated balance sheet as "intangible undeveloped leaseholds" and we had
developed leasehold interests of approximately $531 million (without reduction
for depreciation) that would be classified on our consolidated balance sheet as
"intangible developed leaseholds."
We have had no contact with the staff of the FASB or the SEC regarding
these matters. The foregoing discussion is based on information provided to us
by other industry participants and by members of the accounting and legal
profession. To our knowledge, all other publicly traded oil and gas companies
have continued to include leasehold interests as part of oil and gas properties
after SFAS No. 141 and SFAS No. 142 became effective. We will continue to
classify our leasehold interests as tangible oil and gas properties until
further guidance is provided.
2. EARNINGS PER SHARE:
Basic earnings per share (EPS) is calculated by dividing net income (the
numerator) by the weighted average number of shares of common stock outstanding
during the period (the denominator). Diluted earnings per share incorporates the
incremental shares issuable (if dilutive) upon the assumed exercise of stock
options (using the treasury stock method) and upon the assumed conversion of our
trust preferred securities as if exercise or conversion to common stock had
occurred at the beginning of the accounting period. Net income has also been
increased for distributions accrued during the period on our trust preferred
securities.
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a calculation of basic and diluted weighted average shares
outstanding and EPS for the three and six months ended June 30, 2003 and 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- ---------------------
2003 2002 2003 2002
-------- -------- -------- --------
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
Income (numerator):
Income before cumulative effect of change
in accounting principle ................... $ 45,815 $ 16,270 $104,381 $ 32,596
Cumulative effect of change in accounting
principle, net of tax ..................... -- -- 5,575 --
-------- -------- -------- --------
Income-- basic .............................. 45,815 16,270 109,956 32,596
After-tax dividends on convertible trust
preferred securities ...................... 1,459 1,518 2,978 3,037
-------- -------- -------- --------
Income-- diluted ............................ $ 47,274 $ 17,788 $112,934 $ 35,633
======== ======== ======== ========
Weighted average shares (denominator):
Weighted average shares-- basic ............. 53,468 44,376 52,679 44,295
Dilutive effect of stock options outstanding
at end of period .......................... 467 629 432 620
Dilutive effect of convertible trust
preferred securities ...................... 3,766 3,923 3,845 3,923
-------- -------- -------- --------
Weighted average shares-- diluted ........... 57,701 48,928 56,956 48,838
======== ======== ======== ========
Earnings per share:
Basic before change in accounting principle.. $ 0.86 $ 0.37 $ 1.98 $ 0.74
Basic ....................................... $ 0.86 $ 0.37 $ 2.09 $ 0.74
Diluted before change in accounting
principle.................................. $ 0.82 $ 0.36 $ 1.88 $ 0.73
Diluted ..................................... $ 0.82 $ 0.36 $ 1.98 $ 0.73
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 853,450 and 645,590
shares for the three months ended June 30, 2003 and 2002, respectively, and
1,002,050 and 707,640 shares for the six months ended June 30, 2003 and 2002,
respectively, because to do so would have been antidilutive.
On May 27, 2003, we completed the issuance and sale of 3.5 million shares
of our common stock for net proceeds of approximately $131.2 million.
10
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 and six
months ended June 30, 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 our actual results of operations would 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 SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
------------------ ----------------
(IN THOUSANDS, EXCEPT PER SHARE)
Pro forma:
Revenue......................................................... $ 200,253 $ 388,803
Income from operations.......................................... 41,655 84,881
Net income...................................................... 11,718 28,846
Basic earnings per share........................................ $ 0.23 $ 0.56
Diluted earnings per share...................................... $ 0.22 $ 0.55
4. OIL AND GAS ASSETS:
Oil and gas properties at the indicated dates consisted of the following:
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
(IN THOUSANDS)
Subject to amortization .................... $ 3,413,309 $ 3,080,522
Not subject to amortization
Exploration wells in progress .......... 6,410 8,212
Development wells in progress .......... 24,184 13,906
Capitalized interest ................... 18,715 14,036
Other capital costs:
Incurred in 2003 ................... 32,202 --
Incurred in 2002 ................... 130,123 135,641
Incurred in 2001 ................... 59,801 63,302
Incurred in 2000 and prior ......... 28,058 33,635
----------- -----------
Total not subject to amortization.. 299,493 268,732
----------- -----------
Gross oil and gas properties ............... 3,712,802 3,349,254
----------- -----------
Accumulated depreciation, depletion and
amortization ........................... (1,495,982) (1,339,249)
----------- -----------
Net oil and gas properties ................. $ 2,216,820 $ 2,010,005
=========== ===========
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. DEBT:
As of the indicated dates, long-term debt consisted of the following:
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
(IN THOUSANDS)
Senior unsecured debt:
Bank revolving credit facility:
Prime rate based loans ................ $ 140,000 $ --
LIBOR based loans ..................... -- 28,000
----------- ------------
Total bank revolving credit facility.. 140,000 28,000
----------- ------------
Money market lines of credit (1) .......... -- 8,000
----------- ------------
Total credit arrangements .......... 140,000 36,000
----------- ------------
7.45% Senior Notes due 2007 ............... 124,801 124,781
7 5/8% Senior Notes due 2011 .............. 174,900 174,895
----------- ------------
Total senior unsecured notes ....... 299,701 299,676
----------- ------------
Total senior unsecured debt ........ 439,701 335,676
----------- ------------
8 3/8% Senior Subordinated Notes due 2012 ..... 248,041 247,971
Secured notes ................................. 5,201 65,963
Gas sales obligation (1) ...................... -- 60,005
----------- ------------
Total long-term debt ............... $ 692,943 $ 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.
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 on 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
and security interests related to the gas sales contract were terminated in
exchange for a payment by us of approximately $73 million. This payment
represented:
- the remaining unamortized obligation under the gas sales contract;
- the fair market value of swaps entered into by BWT in conjunction with
the gas sales contract;
- various transaction fees related to the termination; and
- an agreed upon value for BWT's membership interest in an EEX
subsidiary.
In connection with the settlement, we recognized a loss of $10.0 million
under the caption "Gas sales obligation settlement and redemption of securities"
on our consolidated statement of income. 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 date we acquired EEX and the settlement date.
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. CONVERTIBLE PREFERRED SECURITIES OF NEWFIELD FINANCIAL TRUST I:
We redeemed all of the outstanding 6 1/2% Cumulative Quarterly Income
Convertible Preferred Securities of Newfield Financial Trust I on June 27, 2003
for an aggregate redemption price of approximately $148.4 million or $38.31 on a
per share of underlying common stock basis (excluding in each case accrued but
unpaid distributions). The holders of only a small number of the securities
elected to convert their securities into shares of our common stock prior to the
redemption date (a total of 48,076 shares of common stock were issued). Included
in the aggregate redemption price is $6.5 million of optional redemption
premium. The premium and $4.0 million of unamortized offering costs (which were
being amortized over the 30-year life of the securities) were recorded as an
operating expense under the caption "Gas sales obligation settlement and
redemption of securities" on our consolidated statement of income.
We financed the redemption with the net proceeds from the issuance and sale
of 3.5 million shares of our common stock on May 27, 2003 (approximately $131.2
million, or $37.49 per share) and borrowings under our revolving credit
facility.
7. 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.
13
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. GEOGRAPHIC INFORMATION:
OTHER
UNITED STATES AUSTRALIA INTERNATIONAL TOTAL
------------- --------- ------------- ----------
(IN THOUSANDS)
THREE MONTHS ENDED JUNE 30, 2003:
Oil and gas revenues................................... $ 255,552 $ -- $ -- $ 255,552
Operating expenses:
Lease operating.................................... 26,582 -- -- 26,582
Production and other taxes......................... 7,463 (931) -- 6,532
Transportation..................................... 1,859 -- -- 1,859
Depreciation, depletion and amortization........... 99,191 469 -- 99,660
Ceiling test writedown............................. -- 7,300 7,300
Allocated income taxes............................. 42,160 (2,051) --
------------- --------- -------------
Net income (loss) from oil and gas properties.... $ 78,297 $ (4,787) $ --
============= ========= =============
Gas sales obligation settlement and redemption of
securities....................................... 10,477
General and administrative (inclusive of stock
compensation) (1)................................ 15,672
----------
Total operating expenses....................... 168,082
----------
Income from operations................................. 87,470
Interest expense and dividends, net of interest
income, capitalized interest and other .......... (16,419)
Unrealized commodity derivative expense............ (1,629)
----------
Income before income taxes............................. $ 69,422
==========
Total long-lived assets................................ $ 2,129,083 $ 45,415 $ 42,322 $2,216,820
============= ========= ============= ==========
Additions to long-lived assets (2)..................... $ 109,315 $ 9,354 $ 3,596 $ 122,265
============= ========= ============= ==========
THREE MONTHS ENDED JUNE 30, 2002:
Oil and gas revenues................................... $ 154,475 $ 7,136 $ -- $ 161,611
Operating expenses:
Lease operating.................................... 22,832 2,874 -- 25,706
Production and other taxes......................... 3,861 -- -- 3,861
Transportation..................................... 1,316 -- -- 1,316
Depreciation, depletion and amortization........... 76,395 1,632 -- 78,027
Allocated income taxes............................. 17,528 789 --
------------- --------- -------------
Net income from oil and gas properties......... $ 32,543 $ 1,841 $ --
============= ========= =============
General and administrative (inclusive of stock
compensation) (1)................................ 12,963
----------
Total operating expenses....................... 121,873
----------
Income from operations................................. 39,738
Interest expense and dividends, net of interest
income, capitalized interest and other........... (8,587)
Unrealized commodity derivative expense............ (5,880)
----------
Income before income taxes............................. $ 25,271
==========
Total long-lived assets................................ $ 1,362,561 $ 22,848 $ 34,337 $1,419,746
============= ========= ============= ==========
Additions to long-lived assets......................... $ 68,165 $ 8,358 $ 2,123 $ 78,646
============= ========= ============= ==========
- ------------------
(1) General and administrative expense includes stock compensation charges of
$807 and $757 for the three months ended June 30, 2003 and 2002,
respectively.
(2) The effects of the Australian ceiling test writedown are excluded.
14
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
OTHER
UNITED STATES AUSTRALIA INTERNATIONAL TOTAL
------------- --------- ------------- ----------
(IN THOUSANDS)
SIX MONTHS ENDED JUNE 30, 2003:
Oil and gas revenues................................... $ 523,443 $ 11,393 $ -- $ 534,836
Operating expenses:
Lease operating.................................... 54,389 4,449 -- 58,838
Production and other taxes......................... 17,670 1,436 -- 19,106
Transportation..................................... 3,422 -- -- 3,422
Depreciation, depletion and amortization........... 192,509 3,851 -- 196,360
Ceiling test writedown............................. -- 7,300 -- 7,300
Allocated income taxes............................. 89,409 (1,693) --
------------- --------- -------------
Net income (loss) from oil and gas properties.. $ 166,044 $ (3,950) $ --
============= ========= =============
Gas sales obligation settlement and redemption of
securities....................................... 20,475
General and administrative (inclusive of stock
compensation) (1)................................ 33,254
----------
Total operating expenses....................... 338,755
----------
Income from operations................................. 196,081
Interest expense and dividends, net of interest
income, capitalized interest and other .......... (32,851)
Unrealized commodity derivative expense............ (2,846)
----------
Income before income taxes............................. $ 160,384
==========
Total long-lived assets................................ $ 2,129,083 $ 45,415 $ 42,322 $2,216,820
============= ========= ============= ==========
Additions to long-lived assets (2) (3)................. $ 330,801 $ 34,069 $ 5,978 $ 370,848
============= ========= ============= ==========
SIX MONTHS ENDED JUNE 30, 2002:
Oil and gas revenues................................... $ 295,948 $ 13,702 $ -- $ 309,650
Operating expenses:
Lease operating.................................... 42,988 5,771 -- 48,759
Production and other taxes......................... 7,271 -- -- 7,271
Transportation..................................... 2,647 -- -- 2,647
Depreciation, depletion and amortization........... 146,028 3,206 -- 149,234
Allocated income taxes............................. 33,955 1,418 --
------------- --------- -------------
Net income from oil and gas properties......... $ 63,059 $ 3,307 $ --
============= ========= =============
General and administrative (inclusive of stock
compensation) (1)................................ 25,308
----------
Total operating expenses....................... 233,219
----------
Income from operations................................. 76,431
Interest expense and dividends, net of interest
income, capitalized interest and other........... (14,178)
Unrealized commodity derivative expense............ (11,525)
----------
Income before income taxes............................. $ 50,728
==========
Total long-lived assets................................ $ 1,362,561 $ 22,848 $ 34,337 $1,419,746
============= ========= ============= ==========
Additions to long-lived assets......................... $ 137,754 $ 15,319 $ 6,149 $ 159,222
============= ========= ============= ==========
- -----------------------
(1) General and administrative expense includes stock compensation charges of
$1,486 and $1,335 for the six months ended June 30, 2003 and 2002,
respectively.
(2) Includes gross domestic additions of $113.1 million and Australia additions
of $21.1 million for capitalized asset retirement obligations.
(3) The effects of the Australian ceiling test writedown are excluded.
15
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
We utilize swap, collar and floor derivative contracts 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 a swap contract, 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 contract, 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 contract. For a collar 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 contract, we are required to make
payment to the counterparty if the settlement price for any settlement period is
above the ceiling price for such contract and neither party is required to make
a payment to the other party if the settlement price for any settlement period
is between the floor price and the ceiling price for such contract. For a 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 contract. We
are not required to make any payment in connection with the settlement of a
floor contract.
Substantially all of our oil and gas derivative contracts are settled based
upon reported prices on the NYMEX. The estimated fair value of these contracts
is based upon various factors, including closing exchange prices on the NYMEX,
over-the-counter quotations, volatility and, in the case of collars and floors,
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 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. After-tax 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
under the caption "Other comprehensive income (loss) - commodity derivatives" on
our consolidated balance sheet until the sale of the hedged oil and gas
production. Upon the sale of the hedged production, the net after-tax change in
the fair value of the associated derivative recorded under the caption "Other
comprehensive income (loss) - commodity derivatives" is reversed and the gain or
loss on the hedge, to the extent that it is effective, is reported in "Oil and
gas revenues" on our consolidated statement of income. At June 30, 2003, we had
a net $32.4 million in after-tax losses recorded under the caption "Other
comprehensive income--commodity derivatives." We expect hedged production
associated with commodity derivatives accounting for a net $32.3 of such amount
to be sold within the next 12 months.
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 reported currently each period under the
caption "Unrealized commodity derivative income (expense)" on our consolidated
statement of income.
Prior to January 1, 2002, the periodic changes in the time value component
of our collar and floor contracts were treated as ineffective and were reported
under the caption "Unrealized commodity derivative income (expense)" on our
consolidated statement of income for the period in which the change occurred. On
January 1, 2002, we began assessing hedge effectiveness based on the total
changes in cash flows on our collar and floor contracts without adjustment for
time value as described by DIG Issue G20, "Cash Flow Hedges: Assessing and
Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge."
Pursuant to the guidance in DIG Issue G20, we elected to prospectively record
subsequent changes in fair value associated with time value under the caption
"Accumulated other comprehensive income (loss)" on our consolidated balance
sheet. As a result, amounts recorded in the second quarter and first half of
2002 primarily reflect the reversal of the time value gains that were recognized
in 2001 and a diminutive amount representing the ineffective portion of our
hedges.
We formally document all relationships between derivative instruments and
hedged production, as well as our risk management objective and strategy for
particular derivative contracts. 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
derivative's inception and on an ongoing basis) whether the derivatives being
utilized have been highly effective in offsetting changes in the cash flows of
hedged production 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 our
consolidated balance sheet and recognize all subsequent changes in the fair
value of the derivative on our consolidated statement of income for the period
in which the change occurred. Hedge accounting was not discontinued during the
periods presented for any hedging instruments.
16
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NATURAL GAS
As of June 30, 2003, we had entered into commodity price hedging
contracts with respect to our future natural gas production as follows:
NYMEX CONTRACT PRICE PER MMBtu
-------------------------------------------------------------------
FLOORS CEILINGS ESTIMATED
SWAPS -------------------------- -------------------------- FAIR VALUE
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT MMMBtus AVERAGE) RANGE AVERAGE RANGE AVERAGE (IN MILLIONS)
- --------------------------- --------- --------- ------------- ---------- ------------- ---------- -----------------
July 2003 - September 2003
Price swap contracts....... 16,453 $4.04 -- -- -- -- $ (23.8)
Collar contracts........... 19,585 -- $3.50 - $4.88 $4.54 $3.90 - $6.50 $ 5.75 (5.4)
Floor contracts............ 5,000 -- 4.85 - 4.88 4.87 -- -- 0.4
October 2003 - December 2003
Price swap contracts....... 10,607 4.06 -- -- -- -- (16.4)
Collar contracts........... 13,635 -- 3.50 - 5.50 4.75 3.90 - 15.00 7.95 (2.0)
Floor contracts............ -- -- -- -- -- -- --
January 2004 - December 2004
Price swap contracts....... 6,660 4.96 -- -- -- -- (1.5)
Collar contracts........... 7,740 -- 3.50 - 5.50 5.00 4.16 - 15.00 11.30 1.0
January 2005 - December 2005
Price swap contracts....... 2,220 3.81 -- -- -- -- (2.2)
Collar contracts........... 1,380 -- 3.50 3.50 4.16 4.16 (1.3)
----------------
$ (51.2)
================
OIL
As of June 30, 2003, we had entered into commodity price hedging
contracts with respect to our future oil production as follows:
NYMEX CONTRACT PRICE PER Bbl
-------------------------------------------------------------------
FLOORS CEILINGS ESTIMATED
SWAPS -------------------------- -------------------------- FAIR VALUE
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT Bbls AVERAGE) RANGE AVERAGE RANGE AVERAGE (IN MILLIONS)
- --------------------------- --------- --------- --------------- -------- --------------- -------- -----------------
July 2003 - September 2003
Price swap contracts....... 259,000 $25.58 -- -- -- -- $ (1.0)
Collar contracts........... 707,000 -- $22.00 - $24.00 $22.53 $26.35 - $29.70 $27.78 (1.8)
October 2003 - December 2003
Price swap contracts....... 144,000 25.55 -- -- -- -- (0.4)
Collar contracts........... 627,000 -- 22.00 - 24.00 22.47 26.35 - 29.70 27.83 (1.2)
January 2004 - December 2004
Price swap contracts....... 96,000 23.23 -- -- -- -- (0.3)
Collar contracts........... 765,000 -- 22.00 - 24.00 22.69 26.04 - 29.70 27.16 (0.8)
January 2005 - December 2005
Price swap contracts....... 204,000 22.63 -- -- -- -- (0.3)
----------------
$ (5.8)
================
17
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 also 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;
- future costs to develop and abandon our oil and gas
properties;
- timing of our future drilling, development and abandonment
activities;
- 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.
18
RESULTS OF OPERATIONS
EARNINGS PER SHARE. We redeemed all of the outstanding preferred
securities of Newfield Financial Trust I on June 27, 2003. We primarily financed
the redemption with the net proceeds from the issuance and sale of 3.5 million
shares of our common stock on May 27, 2003. For a further description of these
transactions, please see "--Redemption of Trust Preferred Securities." Our
diluted earnings per share for the three and six months ended June 30, 2003 were
negatively impacted by the continuing dilutive effect of the convertible trust
preferred securities following the issuance of the 3.5 million shares of our
common stock.
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 second quarter of 2003
were 58% higher than the second quarter of 2002 because of higher commodity
prices and higher natural gas production, partially offset by lower oil
production. Revenues for the first six months of 2003 were 73% higher than the
same period of last year due to higher commodity prices and higher production.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, PERCENTAGE JUNE 30, PERCENTAGE
------------------------ INCREASE ------------------------ INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
---------- ---------- ------------ ---------- ---------- -----------
PRODUCTION:
United States:
Natural gas (Bcf)................... 46.8 37.9 23% 90.8 71.8 26%
Oil and condensate (MBbls).......... 1,579.4 1,328.8 19% 3,095.7 2,678.3 16%
Total (Bcfe)........................ 56.2 45.8 23% 111.5 87.8 27%
Australia (1):
Oil (MBbls)......................... -- 277.5 (100%) 357.6 575.8 (38%)
Total:
Natural gas (Bcf)................... 46.8 37.9 23% 90.8 71.8 26%
Oil and condensate (MBbls).......... 1,579.4 1,606.2 (2%) 3,453.3 3,254.0 6%
Total (Bcfe)........................ 56.2 47.5 18% 111.5 91.3 22%
AVERAGE REALIZED PRICES(2):
United States:
Natural gas (per Mcf)............... $ 4.50 $ 3.21 40% $ 4.77 $ 3.23 48%
Oil and condensate (per Bbl)........ 27.54 23.84 16% 28.27 22.93 25%
Australia:
Oil (per Bbl)....................... -- $ 25.72 N/M(3) $ 31.86 $ 23.80 34%
Total:
Natural gas (per Mcf)............... $ 4.50 $ 3.21 40% $ 4.77 $ 3.23 48%
Oil and condensate (per Bbl)........ 27.54 24.17 14% 28.64 23.08 24%
Natural gas equivalent (per Mcfe)... 4.51 3.37 34% 4.77 3.36 42%
- --------------
(1) Represents volumes sold or lifted 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 for
the three months ended June 30, 2003 and 2002, and by $0.02 and $0.03
for the six months ended June 30, 2003 and 2002, respectively. The
realized price of oil and condensate was reduced by $0.45 and $0.29 for
the three months ended June 30, 2003 and 2002, respectively, and by
$0.35 and $0.26 for the six months ended June 30, 2003 and 2002,
respectively. Average realized prices include the effects of hedging.
(3) Not meaningful.
PRODUCTION. Our total oil and gas production (stated on a natural gas
equivalent basis) increased in the second quarter and the first six months of
2003 when compared to the same periods in 2002 primarily because of our
acquisition of EEX, other small acquisitions and successful drilling efforts.
Additionally, production in the first half of 2002 was negatively impacted by
our election to defer liftings of oil production in Australia and by our
voluntary curtailment of approximately one Bcfe of production in response to low
commodity prices.
NATURAL GAS. Our second quarter and first six months of 2003 natural
gas production increased primarily because of our acquisition of EEX and
successful drilling in the Gulf of Mexico in late 2002.
CRUDE OIL AND CONDENSATE. We had no liftings of oil production in
Australia in the second quarter of 2003 because we elected to defer liftings for
resource rent tax (production tax) planning purposes. Our domestic oil
production for the second quarter and the first half of 2003 as compared to the
same periods of the prior year increased primarily because of our acquisition of
EEX and other small acquisitions.
19
EFFECTS OF HEDGING ON REALIZED PRICES. The following table presents
information about the effects 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 June 30, 2003.................. $ 4.50 $ 5.23 86%
Three months ended June 30, 2002.................. 3.21 3.22 99%
Six months ended June 30, 2003.................... 4.77 5.75 83%
Six months ended June 30, 2002.................... 3.23 2.78 116%
Crude Oil and Condensate:
Three months ended June 30, 2003.................. $ 27.54 $ 28.30 97%
Three months ended June 30, 2002.................. 24.17 24.60 98%
Six months ended June 30, 2003.................... 28.64 30.50 94%
Six months ended June 30, 2002.................... 23.08 22.60 102%
- -------------
(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 second quarter of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT
(PER Mcfe) (IN THOUSANDS)
-------------------------------------- -----------------------------------------
THREE MONTHS ENDED THREE MONTHS ENDED
JUNE 30, PERCENTAGE JUNE 30, PERCENTAGE
----------------------- INCREASE --------------------------- INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
---------- --------- ----------- ----------- ------------ -----------
United States:
Lease operating ............................ $ 0.47 $ 0.50 (6%) $ 26,582 $ 22,832 16%
Production and other taxes ................. 0.13 0.08 63% 7,463 3,861 93%
Transportation ............................. 0.03 0.03 -- 1,859 1,316 41%
Depreciation, depletion and amortization ... 1.76 1.67 5% 99,191 76,395 30%
General and administrative (exclusive of
stock compensation)....................... 0.26 0.26 -- 14,382 11,808 22%
Total ................................ 2.65 2.54 4% 149,477 116,212 29%
Australia:
Lease operating ............................ $ -- $ 1.73 (100%) $ -- $ 2,874 (100%)
Production and other taxes ................. N/M(1) -- N/M(1) (931) -- N/M(1)
Transportation ............................. -- -- -- -- -- --
Depreciation, depletion and amortization ... N/M(1) 0.98 N/M(1) 469 1,632 (71%)
General and administrative (exclusive of
stock compensation)....................... N/M(1) 0.24 N/M(1) 483 398 21%
Total ................................ N/M(1) 2.95 N/M(1) 21 4,904 (100%)
Total:
Lease operating ............................ $ 0.47 $ 0.54 (13%) $ 26,582 $ 25,706 3%
Production and other taxes ................. 0.12 0.08 50% 6,532 3,861 69%
Transportation ............................. 0.03 0.03 -- 1,859 1,316 41%
Depreciation, depletion and amortization ... 1.77 1.64 8% 99,660 78,027 28%
General and administrative (exclusive of
stock compensation(2)).................... 0.26 0.26 -- 14,865 12,206 22%
Total ................................ 2.65 2.55 4% 149,498 121,116 23%
- ---------------------
(1) Not meaningful.
(2) Stock compensation charges were $807, or $0.01 per Mcfe, and $757, or
$0.02 per Mcfe, for the three months ended June 30, 2003 and 2002,
respectively. Total operating expense, inclusive of these charges but
excluding the Australian ceiling test writedown and the gas sales
obligation settlement and redemption of securities, was $150,305, or
$2.67 per Mcfe, and $121,873, or $2.57 per Mcfe, for the three months
ended June 30, 2003 and 2002, respectively.
20
Our total operating expense (excluding stock compensation, the
Australian ceiling test writedown and the gas sales obligation settlement and
redemption of securities) for the second quarter of 2003, stated on a
unit-of-production basis, increased 4% over the same period in 2002. The
increase was primarily related to the following items.
DOMESTIC OPERATIONS:
- Lease operating expense (LOE) on an Mcfe basis in the second
quarter of 2003 was less than LOE in the same period of the
prior year because workovers originally planned for the second
quarter were deferred until the third quarter. Additionally,
expenses in the second quarter of 2002 included several
non-routine repairs in the Gulf of Mexico that increased LOE
by approximately $4 million.
- Production taxes on an Mcfe basis increased in the second
quarter of 2003 due to higher commodity prices when compared
to the same period of last year. Additionally, a greater
percentage of our production is now onshore and subject to
production taxes.
- Depreciation, depletion and amortization (DD&A) (excluding
furniture, fixtures and equipment) for the second quarter of
2003 was $1.74 per Mcfe versus $1.65 for the comparable period
of 2002. Our adoption of SFAS No. 143 (see "--Adoption of SFAS
No. 143" below) resulted in $0.03 per Mcfe of the increase.
The remainder of the increase resulted from the increased cost
of reserve additions since the second quarter of 2002.
- General and administrative (G&A) expense was negatively
impacted by $1.4 million in payments made to employees located
in EEX's San Antonio, Texas office upon the closing of that
office in June 2003. G&A expense also increased as a result of
our growing domestic workforce. During the second quarter of
2003, we capitalized $7.4 million of direct internal costs
compared to $1.9 million in the second quarter of 2002.
AUSTRALIAN OPERATIONS:
- Because we did not have any oil liftings from our FPSOs during
the second quarter of 2003, we did not recognize any LOE
during the period. The LOE we incurred for the period is
included in the carrying cost of inventory.
- 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 deductible expenditures for the
fiscal year. The credit recorded in the second quarter of 2003
is due to a change in the estimate of the taxes due for the
period from July 2002 to June 2003. In the first six months of
2002, Australian allowable operating and capital deductions
offset production taxes otherwise payable. As a result, no
Australian production taxes were recorded in the first six
months of 2002.
- DD&A expense is primarily attributable to the accretion of
discount on our asset retirement obligations associated with
SFAS No. 143 (see "--Adoption of SFAS No. 143" below). Because
there were no liftings during the second quarter of 2003,
expense (other than accretion of asset retirement obligations
and furniture, fixtures and equipment depreciation) associated
with capitalized costs in the full cost pool is included as
part of our cost of inventory at the end of the period.
- G&A expense increased primarily due to a decrease in
reimbursements from other joint owners. The decrease resulted
from the lack of exploration and other reimbursable
activities.
21
The following table presents information about our operating expenses
for the first six months of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT
(PER Mcfe) (IN THOUSANDS)
-------------------------------------- ----------------------------------------
SIX MONTHS ENDED SIX MONTHS ENDED
JUNE 30, PERCENTAGE JUNE 30, PERCENTAGE
----------------------- INCREASE --------------------------- INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
---------- --------- ----------- ----------- ------------ ----------
United States:
Lease operating ............................ $ 0.50 $ 0.49 2% $ 54,389 $ 42,988 27%
Production and other taxes ................. 0.16 0.08 100% 17,670 7,271 143%
Transportation ............................. 0.03 0.03 -- 3,422 2,647 29%
Depreciation, depletion and amortization ... 1.76 1.66 6% 192,509 146,028 32%
General and administrative (exclusive of
stock compensation)....................... 0.28 0.26 8% 30,707 23,044 33%
Total ................................ 2.73 2.52 8% 298,697 221,978 35%
Australia:
Lease operating ............................ $ 2.07 $ 1.67 24% $ 4,449 $ 5,771 (23%)
Production and other taxes ................. 0.67 -- N/M(1) 1,436 -- N/M(1)
Transportation ............................. -- -- -- -- -- --
Depreciation, depletion and amortization ... 1.80 0.93 94% 3,851 3,206 20%
General and administrative (exclusive of
stock compensation)....................... 0.49 0.27 81% 1,061 929 14%
Total ................................ 5.03 2.87 75% 10,797 9,906 9%
Total:
Lease operating ............................ $ 0.53 $ 0.53 -- $ 58,838 $ 48,759 21%
Production and other taxes ................. 0.17 0.08 113% 19,106 7,271 163%
Transportation ............................. 0.03 0.03 -- 3,422 2,647 29%
Depreciation, depletion and amortization ... 1.76 1.63 8% 196,360 149,234 32%
General and administrative (exclusive of
stock compensation(2)).................... 0.28 0.26 8% 31,768 23,973 33%
Total ................................ 2.77 2.53 9% 309,494 231,884 33%
- ---------------
(1) Not meaningful.
(2) Stock compensation charges were $1,486, or $0.01 per Mcfe, and $1,335,
or $0.01 per Mcfe, for the six months ended June 30, 2003 and 2002,
respectively. Total operating expense, inclusive of these charges but
excluding the ceiling test writedown and the gas sales obligation
settlement and redemption of securities, was $310,980, or $2.79 per
Mcfe, and $233,219, or $2.55 per Mcfe, for the six months ended June
30, 2003 and 2002, respectively.
Our total operating expense (excluding stock compensation, the
Australian ceiling test writedown and the gas sales obligation settlement and
redemption of securities) for the first six months of 2003, stated on a
unit-of-production basis, increased 9% over the same period in 2002. The
increase was primarily related to the following items.
DOMESTIC OPERATIONS:
- LOE on a unit-of-production basis for the first quarter of
2003 increased over the same period of last year primarily
because of workovers along the onshore Gulf Coast in southern
Louisiana and South Texas. This increase was largely offset by
lower LOE on an Mcfe basis during the second quarter of 2003
as compared to the same period in 2002.
- Production taxes on an Mcfe basis increased in the first six
months of 2003 due to higher commodity prices when compared to
the same period of last year. Additionally, a greater
percentage of our production is now onshore and subject to
production taxes.
- DD&A (excluding furniture, fixtures and equipment) for the
first six months of 2003 was $1.75 per Mcfe versus $1.64 for
the comparable period of 2002. Our adoption of SFAS No. 143
(see "--Adoption of SFAS No. 143" below) resulted in $0.03 per
Mcfe of the increase. The remainder of the increase resulted
from the increased cost of reserve additions since the second
quarter of 2002.
- G&A expense increased primarily because of our growing
domestic workforce and $1.4 million in payments made to
employees located in EEX's San Antonio, Texas office upon the
closing of that office during the second quarter of 2003.
During the first half of 2003, we capitalized $14.2 million of
direct internal costs, as compared to $4.2 million in the
first half of 2002.
22
AUSTRALIAN OPERATIONS:
- LOE for the first six months of 2003 was 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 the first six months of 2002, Australian allowable
operating and capital deductions offset production taxes
otherwise payable. As a result, no Australian production taxes
were recorded in the first six months of 2002.
- DD&A expense increased primarily because of our unsuccessful
drilling efforts in 2002 and the accretion of discount on our
asset retirement obligations associated with SFAS No. 143 (see
"--Adoption of SFAS No. 143" below). Because there were no
liftings during the second quarter of 2003, DD&A expense
(other than accretion of asset retirement obligations and
furniture, fixtures and equipment depreciation) associated
with capitalized costs in the full cost pool is included as
part of our cost of inventory at the end of the period.
- G&A expense increased primarily due to a decrease in
reimbursements from other joint owners. The decrease resulted
from the lack of exploration and other reimbursable activities
in 2003.
WRITEDOWN OF OIL AND GAS PROPERTIES. At June 30, 2003, we had a
writedown of our Australian full cost pool. Based on oil and gas prices in
effect on June 30, 2003 ($27.43 per barrel of oil for the remainder of 2003 and
$27.20 thereafter), the unamortized cost of our Australian oil and gas
properties exceeded the cost center ceiling. Therefore, in accordance with full
cost accounting rules, we recorded a ceiling test writedown at June 30, 2003 of
$7.3 million ($5.1 million after-tax).
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 on 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:
- the remaining unamortized obligation under the gas sales
contract;
- the fair market value of swaps entered into by BWT in
conjunction with the gas sales contract;
- various transactions fees related to the termination; and
- as agreed upon value for BWT's membership interest in EEX
subsidiary.
In connection with the settlement, we recognized a loss of $10 million
under the caption "Gas sales obligation settlement and redemption of securities"
on our consolidated statement of income. 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 date we acquired EEX 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 the sale of these previously committed volumes will be recognized
in revenues.
REDEMPTION OF TRUST PREFERRED SECURITIES. We redeemed all of the
outstanding 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities
of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price
of approximately $148.4 million or $38.31 on a per share of underlying common
stock basis (excluding in each case accrued but unpaid distributions). The
holders of only a small number of the securities elected to convert their
securities into shares of our common stock prior to the redemption date (a total
of 48,076 shares of common stock were issued). Included in the aggregate
redemption price is $6.5 million of optional redemption premium. The premium and
$4.0 million of unamortized offering costs (which were being amortized over the
30-year life of the securities) were recorded as an operating expense under the
caption "Gas sales obligation settlement and redemption of securities" on our
consolidated statement of income.
23
We financed the redemption with the net proceeds from the issuance and
sale of 3.5 million shares of our common stock on May 27, 2003 (approximately
$131.2 million, or $37.49 per share) and borrowings under our revolving credit
facility.
INTEREST EXPENSE. Interest expense for the second quarter of 2003 and
the first six months of 2003 increased compared to the same periods last year
primarily because of debt incurred in connection with the EEX acquisition in
late 2002.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- ------------------------
2003 2002 2003 2002
----------- ---------- ---------- ----------
(IN MILLIONS)
Gross interest expense..................................... $ 15.0 $ 7.1 $ 31.7 $ 14.3
Capitalized interest....................................... (3.9) (2.1) (7.7) (4.3)
------ ------ ------ ------
Net interest expense....................................... 11.1 5.0 24.0 10.0
Distributions on preferred securities...................... 2.2 2.3 4.6 4.7
------ ------ ------ ------
Total interest expense and distributions............ $ 13.3 $ 7.3 $ 28.6 $ 14.7
====== ====== ====== ======
UNREALIZED COMMODITY DERIVATIVE EXPENSE. The $1.6 million and $2.8
million of expense for the second quarter of 2003 and the first six months of
2003, respectively, represents the hedge ineffectiveness associated with our
hedging program. The unrealized expense of $5.9 million during the second
quarter of 2002 and $11.5 million during the first six months of 2002 primarily
reflect the reversal of the time value gains that were previously recognized
during 2001. For a further description of these items, please see Note 9,
"Commodity Derivative Instruments and Hedging Activities," to our consolidated
financial statements appearing earlier in this report.
OTHER. Both the second quarter of 2002 and 2003 consists primarily of
foreign currency transaction losses. These losses were $3.3 million in the
second quarter of 2003 and $0.6 million in the second quarter of 2002. The U.S.
dollar continued to weaken relative to the Australian dollar, resulting in
higher foreign currency transaction losses in 2003. Both quarters' transaction
losses were partially offset by interest income and other minor items. The first
six months of 2003 consists of $5.4 million in foreign currency transaction
losses. The first six months of 2002 consists of a gain resulting from the
reversal of accruals for contingencies related to our acquisition of Gulf
Australia in 1999 and $2.6 million in foreign currency transaction losses
TAXES. The effective tax rate for the three and six month periods ended
June 30, 2003 and 2002 were about the same. Estimates of future taxable income
can be significantly affected by changes in oil and natural gas prices,
estimates of the timing and amount of future production and estimates of future
operating and capital costs.
ADOPTION OF SFAS NO. 143. We adopted SFAS No. 143, "Accounting for
Asset Retirement Obligations," as of January 1, 2003. This statement changes the
method of accounting for expected future costs associated with our obligation to
perform site reclamation, to dismantle facilities and to plug and abandon wells.
Prior to January 1, 2003, we recognized the undiscounted estimated cost to
abandon our oil and gas properties over their estimated productive lives on a
unit-of-production basis and no liability or capitalized costs associated with
such abandonment were recorded on our consolidated balance sheet. SFAS No. 143
requires that, if a reasonable estimate of the fair value of an abandonment
obligation can be made, a liability (an "asset retirement obligation" or "ARO")
will be recorded on our consolidated balance sheet and the asset retirement cost
will be capitalized in oil and gas properties at the end of the period in which
the retirement obligation is incurred.
In general, the amount of an ARO and the costs capitalized will be
equal to the future cost to satisfy the abandonment obligation using current
prices that are escalated by an assumed inflation factor after discounting the
future cost back to the date that the abandonment obligation was incurred using
an assumed cost of funds for our company. After recording, these amounts, the
ARO will be accreted to its future estimated value using the same assumed cost
of funds and the additional capitalized costs will be depreciated on a
unit-of-production basis over the productive life of the related properties.
Both the accretion and the depreciation will be included in depreciation,
depletion and amortization on our consolidated statement of income.
24
At adoption of SFAS No. 143, a cumulative effect of change in
accounting principle was required in order to recognize:
- an initial ARO as a liability on our consolidated balance
sheet;
- an increase in oil and gas properties for the cost to abandon
our oil and gas properties; and
- accumulated depreciation on the additional capitalized costs
included in oil and gas properties.
As a result of our adoption of SFAS No. 143, we 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 (the after tax amount by which
additional capitalized costs, net of accumulated depreciation, exceeded the
initial ARO) for the cumulative effect of change in accounting principle.
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 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 July 31, 2003), 30% of the principal
amount of any outstanding senior subordinated notes (a reduction of $75 million
at July 31, 2003) and the outstanding principal amount of the secured notes ($3
million at July 31, 2003). The borrowing base will be redetermined at least
semi-annually and, prior to reduction for the foregoing items, was $770 million
at July 31, 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 July
31, 2003, we had outstanding borrowings under our credit facility of $50 million
and no outstanding borrowings under our money market lines. Consequently, at
July 31, 2003, we had approximately $342 million of available capacity under our
credit arrangements.
At June 30, 2003, the interest rate for our outstanding prime rate
based loans was 4.125%. At December 31, 2002, the interest rate was 2.75% for
LIBOR based loans under our credit facility and 2.50% for the loans outstanding
under the money market lines of credit.
For further information regarding our outstanding debt as of June 30,
2003, please see Note 5, "Debt," to our consolidated financial statements
appearing earlier in this report.
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 $16.2 million as of June 30,
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
six months of 2003 increased 41% compared to the first six months of 2002. This
increase was primarily due to higher operating income.
25
CAPITAL EXPENDITURES. Our capital spending during the first six months
of 2003 was $238 million, a 47% increase over the same period of last year.
During the first six months of 2003, we invested approximately $65 million in
proved and unproved property acquisitions, $87 million in U.S. development, $60
million in U.S. exploration, $7 million in other U.S. operations and $19 million
internationally.
We have increased our capital budget for 2003 from $450 to $475
million. The budget includes $45 million for acquisitions completed in the first
half 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.
CASH FLOW FROM FINANCING ACTIVITIES. We redeemed all of the outstanding
preferred securities of Newfield Financial Trust I on June 27, 2003 for an
aggregate redemption price of approximately $148.4 million. We financed the
redemption with the net proceeds from the issuance and sale of 3.5 million
shares of our common stock (approximately $131.2 million) and borrowings under
our revolving credit facility. For a further discussion of these transactions,
please see "--Results of Operations--Redemption of Trust Preferred Securities."
During the first half of 2003 we either repurchased or repaid $70.8
million principal amount of our secured notes. During July 2003, we repurchased
secured notes with an outstanding principal amount of approximately $3 million.
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 and capital programs. 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 75% (on an
Mcfe basis) of our production target for the six 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 the transactions.
Substantially all of our hedging transactions are settled based upon
reported 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 oil 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.
Please see the discussion and tables in Note 9, "Commodity Derivative
Instruments and Hedging Activities," to our consolidated financial statements
appearing earlier in this report for a description of the accounting applicable
to our hedging program and a listing of open hedging contracts as of June 30,
2003 and the fair value of those contracts as of that date. Between June 30,
2003 and August 6, 2003, we entered into the following hedging transactions.
NYMEX CONTRACT PRICE PER MMbtu
-------------------------------------------------------------------
FLOORS CEILINGS
SWAPS -------------------------- --------------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED
PERIOD AND TYPE OF CONTRACT MMMBtus AVERAGE) RANGE AVERAGE RANGE AVERAGE
- --------------------------- --------- --------- ------------- ---------- ------------- ----------
October 2003 - December 2003
Price swap contracts....... 2,400 $5.09 -- -- -- --
Collar contracts........... 2,700 -- $ 5.00 $5.00 $6.02 - $7.05 $6.47
January 2004 - December 2004
Price swap contracts....... 2,250 5.26 -- -- -- --
Collar contracts........... 8,100 -- 4.50 - 5.00 4.83 6.60 - 7.05 6.75
January 2005 - December 2005
Price swap contracts....... 2,040 4.70 -- -- -- --
NYMEX CONTRACT PRICE PER Bbl
-------------------------------------------------------------------
FLOORS CEILINGS
SWAPS -------------------------- --------------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED
PERIOD AND TYPE OF CONTRACT Bbls AVERAGE) RANGE AVERAGE RANGE AVERAGE
- --------------------------- --------- --------- --------------- -------- --------------- --------
October 2003 - December 2003
Price swap contracts....... 69,000 $30.13 -- -- -- --
January 2004 - December 2004
Price swap contracts....... 45,000 28.80 -- -- -- --
We also entered into an additional crude oil option contract with
respect to 45,000 barrels of oil per month for January through December 2004.
The contract has a ceiling of $30.05 per barrel and a floor of $26.00 per barrel
until the price drops below $21.00 per barrel. Below $21.00 per barrel, this
contract effectively results in a realized price that is $5.00 per barrel higher
than the cash price that would otherwise be realized.
26
NEW ACCOUNTING STANDARDS
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
as of January 1, 2003. For a discussion of SFAS No. 143 and the effects of our
adoption of this statement, please see "--Results of Operations--Adoption of
SFAS No. 143" and Note 1, "Organization and Summary of Significant Accounting
Policies--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 Note 1,
"Organization and Summary of Significant Accounting Policies--Other New
Accounting Standards," to our consolidated financial statements appearing
earlier in this report.
RECENT DEVELOPMENTS
INTERPRETATION OF SFAS NOS. 141 AND 142. SFAS No. 141, "Business
Combinations," and SFAS No. 142, "Goodwill and Intangible Assets," were issued
by the FASB in June 2001 and became effective for us on July 1, 2001 and January
1, 2002, respectively. SFAS No. 141 requires that all business combinations
initiated after June 30, 2001 to be accounted for using the purchase method and
that certain intangible assets be disaggregated and reported separately from
goodwill. SFAS No. 142 establishes new guidelines for accounting for goodwill
and other intangible assets. Under the statement, goodwill and certain other
intangible assets are reviewed annually for impairment but are not amortized. It
is our understanding that the staffs of the FASB and the Securities and Exchange
Commission are currently considering the appropriate application of SFAS Nos.
141 and 142 to oil and gas rights and interests held under leases, governmental
licenses or other contractual arrangements (leasehold interests).
Based on our understanding of current discussions, if all leasehold
interests were deemed to be intangible assets, for companies like us that use
the full cost method of accounting for oil and gas activities:
- leasehold interests with proved reserves that were acquired
after June 30, 2001 and leasehold interests with no proved
reserves would be classified as intangible assets and would
not be included in oil and gas properties on our consolidated
balance sheet;
- our results of operations and cash flows would not be affected
because leasehold costs would continue to be amortized in
accordance with full cost accounting rules; and
- the disclosures required by SFAS Nos. 141 and 142 relative to
intangibles would be included in the notes to our financial
statements.
If SFAS Nos. 141 and SFAS 142 were applied as described above, at June 30, 2003
we had undeveloped leasehold interests of approximately $250 million (without
reduction for depreciation) that would be classified on our consolidated balance
sheet as "intangible undeveloped leaseholds" and we had developed leasehold
interests of approximately $531 million (without reduction for depreciation)
that would be classified on our consolidated balance sheet as "intangible
developed leaseholds."
We have had no contact with the staff of the FASB or the SEC regarding
these matters. The foregoing discussion is based on information provided to us
by other industry participants and by members of the accounting and legal
profession. To our knowledge, all other publicly traded oil and gas companies
have continued to include leasehold interests as part of oil and gas properties
after SFAS No. 141 and SFAS No. 142 became effective. We will continue to
classify our leasehold interests as tangible oil and gas properties until
further guidance is provided.
SALE OF AUSTRALIAN OPERATIONS. We are currently marketing all of our
Australian operations and expect to complete the sale in the third quarter of
2003. Our Australian producing operations consist of a 50% interest in two
producing fields (Jabiru and Challis) and two related FPSOs in the Timor Sea,
offshore northwest Australia. We also have non-producing assets in Australia,
including an existing oil discovery, known as "Montara," that is being evaluated
for development potential.
GENERAL INFORMATION
General information about us can be found at www.newfld.com. In
conjunction with our web page, we also maintain an 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. Recent
editions of @NFX are available on our web page. To receive @NFX directly by
email, please forward your email address to info@newfld.com 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.
27
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, anticipated cash
flow and the potential sale of our Australian operations. 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.
28
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
Please see the discussion and tables in Note 9, "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 description of our hedging program and a listing
of open hedging contracts as of June 30, 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 June 30, 2003 to be minimal
because the majority, about 80%, of our long-term debt obligations were at fixed
rates. At June 30, 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 minimal. We did not have any open derivative contracts relating to foreign
currencies at June 30, 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.
29
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
At the May 1, 2003 Annual Meeting of Stockholders, our stockholders
voted on two matters. As of the March 13, 2003 record date, 51,787,375 shares of
common stock were outstanding and entitled to vote at the meeting.
(1) Election of Eleven Directors:
Our stockholders elected the eleven nominees for director
until the next annual meeting by the following vote:
NOMINEE ELECTED FOR WITHHELD
- ------------------------ ----------------- -----------------
Joe B. Foster 44,379,927 3,786,648
David A. Trice 44,379,732 3,786,843
David F. Schaible 44,444,876 3,721,699
Charles W. Duncan, Jr. 47,843,671 322,904
Howard H. Newman 44,421,604 3,744,971
Thomas G. Ricks 47,793,000 373,575
Dennis R. Hendrix 47,850,208 316,367
C. E. Shultz 47,793,629 372,946
Philip J. Burguieres 47,850,835 315,740
Claire S. Farley 47,794,132 372,443
John Randolph Kemp III 47,792,987 373,588
(2) Appointment of Independent Public Accountants:
Our stockholders ratified the appointment of
PricewaterhouseCoopers LLP as our independent accountants for
2003 by the following vote:
ABSTENTIONS AND
FOR AGAINST BROKER NON-VOTES
- ---------------------------- ------------------------- -------------------------
47,331,053 379,927 5,661
30
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 day 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 July 1, 2003 and ended after the close of
trading on July 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.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit Number Description
- -------------- -----------
10.1 First Amendment to Newfield Exploration Company 1995 Omnibus
Stock Plan
10.2 Second Amendment to Newfield Exploration Company 1998 Omnibus
Stock Plan (as amended on May 7, 1998)
10.3 First Amendment to Newfield Exploration Company 2000 Omnibus
Stock Plan (as amended and restated effective February 14,
2002)
31.1 Certification of Chief Executive Officer of Newfield pursuant
to 15 U.S.C. Section 7241, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer of Newfield pursuant
to 15 U.S.C. Section 7241, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
32.1 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
32.2 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 July 23, 2003, we filed a current report on Form 8-K
announcing our second quarter 2003 financial results and third quarter
2003 guidance regarding production and significant operating and
financial data.
On June 30, 2003, we filed a current report on Form 8-K
announcing the completion of the redemption of all of our outstanding
6 1/2% Cumulative Quarterly Income Convertible Preferred Securities,
Series A (QUIPS) on June 27, 2003.
On June 2, 2003, we filed a Current Report on Form 8-K
announcing that we had received notice from BP Exploration & Production
Inc. of its intent to drill an initial well to test the Treasure Island
exploration concept, as provided for and subject to the terms and
conditions of the joint exploration agreement between BP and Newfield
(as successor to EEX Corporation).
On May 23, 2003, we filed a Current Report on Form 8-K with
respect to our agreement to issue 3.5 million shares of our common
stock for net proceeds of approximately $131.2 million and our
intention to use the proceeds to redeem our 6 1/2% Cumulative Quarterly
Income Convertible Preferred Securities, Series A (QUIPS). The
following documents were filed with the report:
- Underwriting Agreement between the various Underwriters and
us; and
- Pricing Agreement between Morgan Stanley & Company
Incorporated and us.
31
On May 20, 2003, we filed a Current Report on Form 8-K with
respect to our acquisition of EEX to provide historical and pro forma
financial information. The following financial statements were filed
with the report:
- Our unaudited pro forma combined condensed financial
statements as of December 31, 2002 that give effect to our
acquisition of EEX and the issuance of our 8 3/8% Senior
Subordinated Notes due 2012.
On May 1, 2003, we filed a Current Report on Form 8-K
announcing a significant deep shelf discovery at West Cameron 73.
On April 24, 2003, we filed a Current Report on Form 8-K
announcing our financial and operating results for the first quarter of
2003 and second quarter of 2003 guidance regarding production and
significant operating and financial data.
32
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: August 12, 2003 By: /s/ TERRY W. RATHERT
----------------------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal Financial
Officer)
33
EXHIBIT INDEX
Exhibit Number Description
- -------------- -----------
10.1 First Amendment to Newfield Exploration Company 1995 Omnibus
Stock Plan
10.2 Second Amendment to Newfield Exploration Company 1998 Omnibus
Stock Plan (as amended on May 7, 1998)
10.3 First Amendment to Newfield Exploration Company 2000 Omnibus
Stock Plan (as amended and restated effective February 14,
2002)
31.1 Certification of Chief Executive Officer of Newfield pursuant
to 15 U.S.C. Section 7241, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer of Newfield pursuant
to 15 U.S.C. Section 7241, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
32.1 Certification of Chief Executive Officer of Newfield
Exploration Company pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
32.2 Certification of Chief Financial Officer of Newfield
Exploration Company pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002