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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 SEPTEMBER 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 November 6, 2003, there were 56,019,830 shares of the
Registrant's Common Stock, par value $0.01 per share, outstanding.
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TABLE OF CONTENTS
PART I
Page
----
Item 1. Unaudited Financial Statements:
Consolidated Balance Sheet as of September 30, 2003 and December 31, 2002.......................... 1
Consolidated Statement of Income for the three and nine months ended
September 30, 2003 and 2002........................................................................ 2
Consolidated Statement of Cash Flows for the nine months ended
September 30, 2003 and 2002........................................................................ 3
Consolidated Statement of Stockholders' Equity for the nine months
ended September 30, 2003........................................................................... 4
Notes to Consolidated Financial Statements......................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................................................. 19
Item 3. Quantitative and Qualitative Disclosures about Market Risk.............................................. 29
Item 4. Controls and Procedures................................................................................. 29
PART II
Item 6. Exhibits and Reports on Form 8-K........................................................................ 30
ii
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents ...................................................... $ 24,970 $ 33,798
Accounts receivable--oil and gas ............................................... 145,966 125,670
Inventories .................................................................... 567 1,260
Derivative assets .............................................................. 35,430 2,655
Deferred taxes ................................................................. -- 13,023
Other current assets ........................................................... 39,019 30,788
Assets of discontinued operations .............................................. -- 31,633
----------- -----------
Total current assets ....................................................... 245,952 238,827
----------- -----------
Oil and gas properties (full cost method, of which $334,156 at September 30, 2003
and $261,558 at December 31, 2002 were excluded from amortization) ............. 3,895,380 3,299,022
Less--accumulated depreciation, depletion and amortization ......................... (1,562,088) (1,312,110)
----------- -----------
2,333,292 1,986,912
----------- -----------
Assets held for sale ............................................................... 35,000 35,000
Furniture, fixtures and equipment, net ............................................. 6,485 7,252
Derivative assets .................................................................. 7,401 4,439
Other assets ....................................................................... 16,725 19,452
Goodwill ........................................................................... 16,761 --
Assets of discontinued operations .................................................. -- 23,871
----------- -----------
Total assets ............................................................... $ 2,661,616 $ 2,315,753
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ............................................................... $ 17,271 $ 27,002
Accrued liabilities ............................................................ 200,090 198,084
Advances from joint owners ..................................................... 8,279 3,613
Current portion of secured notes payable ....................................... 531 11,215
Deferred taxes ................................................................. 2,626 --
Asset retirement obligation .................................................... 6,294 --
Derivative liabilities ......................................................... 24,198 49,610
Liabilities of discontinued operations ......................................... -- 6,283
----------- -----------
Total current liabilities .................................................. 259,289 295,807
----------- -----------
Other liabilities .................................................................. 13,323 15,949
Derivative liabilities ............................................................. 15,160 10,610
Long-term debt ..................................................................... 692,230 709,615
Asset retirement obligation ........................................................ 137,797 --
Liabilities of discontinued operations ............................................. -- 5,559
Deferred taxes ..................................................................... 197,293 124,777
----------- -----------
Total long-term liabilities ................................................ 1,055,803 866,510
----------- -----------
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;
56,876,630 and 52,603,662 shares issued and outstanding
at September 30, 2003 and December 31, 2002, respectively) ................. 569 526
Additional paid-in capital ......................................................... 787,689 636,317
Treasury stock (at cost; 884,704 and 872,927 shares at September 30, 2003 and
December 31, 2002, respectively) ............................................... (26,616) (26,213)
Unearned compensation .............................................................. (11,857) (6,479)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment ........................................ 294 (3,888)
Commodity derivatives .......................................................... 847 (27,295)
Retained earnings .................................................................. 595,598 436,263
----------- -----------
Total stockholders' equity ................................................. 1,346,524 1,009,231
----------- -----------
Total liabilities and stockholders' equity ................................. $ 2,661,616 $ 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 PER SHARE DATA)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------- --------- --------- ---------
2003 2002 2003 2002
--------- --------- --------- ---------
Oil and gas revenues .......................................................... $ 248,664 $ 141,978 $ 772,107 $ 437,926
--------- --------- --------- ---------
Operating expenses:
Lease operating ........................................................... 31,083 20,309 85,807 63,298
Production and other taxes ................................................ 7,488 3,738 25,159 11,009
Transportation ............................................................ 1,624 1,730 5,046 4,377
Depreciation, depletion and amortization .................................. 100,897 69,910 293,407 215,937
General and administrative (includes stock compensation of $629
and $731 for the three months ended September 30, 2003 and 2002,
respectively, and $2,115 and $2,066 for the nine months ended
September 30, 2003 and 2002, respectively) .............................. 13,815 13,387 46,008 37,766
Gas sales obligation settlement and redemption of securities .............. -- -- 20,475 --
--------- --------- --------- ---------
Total operating expenses ............................................. 154,907 109,074 475,902 332,387
--------- --------- --------- ---------
Income from operations ........................................................ 93,757 32,904 296,205 105,539
Other income (expenses):
Interest expense .......................................................... (13,357) (7,049) (45,025) (21,397)
Capitalized interest ...................................................... 4,010 2,280 11,728 6,553
Dividends on convertible preferred securities of
Newfield Financial Trust I .............................................. -- (2,336) (4,581) (7,008)
Unrealized commodity derivative income (expense) .......................... 3,569 (13,952) 723 (25,477)
Other ..................................................................... 444 137 956 4,004
--------- --------- --------- ---------
(5,334) (20,920) (36,199) (43,325)
--------- --------- --------- ---------
Income from continuing operations before income taxes ......................... 88,423 11,984 260,006 62,214
Income tax provision (benefit):
Current ................................................................... 760 15,195 36,341 33,443
Deferred .................................................................. 29,312 (10,851) 52,913 (11,178)
--------- --------- --------- ---------
30,072 4,344 89,254 22,265
--------- --------- --------- ---------
Income from continuing operations ............................................. 58,351 7,640 170,752 39,949
Income (loss) from discontinued operations, net of tax ........................ (8,972) 1,731 (16,992) 2,018
--------- --------- --------- ---------
Income before cumulative effect of change in accounting principle ............. 49,379 9,371 153,760 41,967
Cumulative effect of change in accounting principle, net of tax:
Adoption of SFAS No. 143 .................................................. -- -- 5,575 --
--------- --------- --------- ---------
Net income ........................................................... $ 49,379 $ 9,371 $ 159,335 $ 41,967
========= ========= ========= =========
Earnings per share:
Basic --
Income from continuing operations ....................................... $ 1.04 $ 0.17 $ 3.17 $ 0.90
Income (loss) from discontinued operations .............................. (0.16) 0.04 (0.31) 0.05
Cumulative effect of change in accounting principle, net of tax ......... -- -- 0.10 --
--------- --------- --------- ---------
Net income ........................................................... $ 0.88 $ 0.21 $ 2.96 $ 0.95
========= ========= ========= =========
Diluted --
Income from continuing operations ....................................... $ 1.04 $ 0.17 $ 3.06 $ 0.89
Income (loss) from discontinued operations .............................. (0.16) 0.04 (0.30) 0.04
Cumulative effect of change in accounting principle, net of tax ......... -- -- 0.10 --
--------- --------- --------- ---------
Net income ........................................................... $ 0.88 $ 0.21 $ 2.86 $ 0.93
========= ========= ========= =========
Weighted average number of shares outstanding for basic earnings per share .... 55,887 44,420 53,785 44,337
========= ========= ========= =========
Weighted average number of shares outstanding for diluted earnings per share .. 56,347 44,905 56,778 44,910
========= ========= ========= =========
The accompanying notes to consolidated financial statements are an
integral part of this financial statement.
2
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------------
2003 2002
----------- -----------
Cash flows from operating activities:
Net income ................................................................. $ 159,335 $ 41,967
Adjustments to reconcile net income to net cash provided by continuing
operating activities:
(Income) loss from discontinued operations, net of tax .................. 16,992 (2,018)
Depreciation, depletion and amortization ................................ 293,407 215,937
Gas sales obligation settlement and redemption of securities ............ 20,475 --
Stock compensation ...................................................... 2,115 2,066
Unrealized commodity derivative (income) expense ........................ (723) 25,477
Deferred taxes .......................................................... 52,913 (11,178)
Cumulative effect of change in accounting principle ..................... (5,575) --
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable -- oil and gas ............ (17,010) 3,551
Decrease in inventories .............................................. 698 158
(Increase) decrease in other current assets .......................... (14,229) 518
Decrease in other assets ............................................. 3,129 816
Decrease in accounts payable and accrued liabilities ................. (43,512) (2,717)
Increase in advances from joint owners ............................... 4,666 164
Increase (decrease) in other liabilities ............................. (14,166) 2,117
----------- -----------
Net cash provided by continuing activities ....................... 458,515 276,858
Net cash provided by discontinued activities ..................... 10,339 18,507
----------- -----------
Net cash provided by operating activities .................... 468,854 295,365
----------- -----------
Cash flows from investing activities:
Purchase of business, net of cash acquired ................................. (91,742) --
Proceeds from sale of business ............................................. 9,678 --
Additions to oil and gas properties ........................................ (358,642) (217,576)
Additions to furniture, fixtures and equipment ............................. (2,738) (2,027)
----------- -----------
Net cash used in continuing activities ........................... (443,444) (219,603)
Net cash used in discontinued activities ......................... (3,085) (16,232)
----------- -----------
Net cash used in investing activities ........................ (446,529) (235,835)
----------- -----------
Cash flows from financing activities:
Proceeds from borrowings under credit arrangements ......................... 1,285,500 490,000
Repayments of borrowings under credit arrangements ......................... (1,180,500) (558,000)
Proceeds from issuance of common stock ..................................... 142,147 5,830
Purchases of treasury stock ................................................ (403) (366)
Repurchases of secured notes ............................................... (63,068) --
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 ................................... (148,449) --
----------- -----------
Net cash used in continuing activities ........................... (46,447) (62,536)
Net cash provided by (used in) discontinued activities ........... -- --
----------- -----------
Net cash used in financing activities ........................ (46,447) (62,536)
----------- -----------
Effect of exchange rate changes on cash and cash equivalents ................... 194 90
----------- -----------
Decrease in cash and cash equivalents .......................................... (23,928) (2,916)
Cash and cash equivalents from continuing operations, beginning of period ...... 33,798 8,668
Cash and cash equivalents from discontinued operations, beginning of period .... 15,100 17,942
----------- -----------
Cash and cash equivalents, end of period ....................................... $ 24,970 $ 23,694
=========== ===========
The accompanying notes to consolidated financial statements are an
integral part of this financial statement.
3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
COMMON STOCK TREASURY STOCK ADDITIONAL
-------------------- -------------------- PAID-IN UNEARNED
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION
---------- ------ -------- -------- ---------- ------------
BALANCE, DECEMBER 31, 2002.... 52,603,662 $ 526 (872,927) $(26,213) $636,317 $ (6,479)
Issuance of common stock...... 4,049,904 41 140,360
Issuance of restricted
stock, less amortization
of $522...................... 223,064 2 7,491 (6,971)
Treasury stock, at cost....... (11,777) (403)
Amortization of stock
compensation................. 1,593
Tax benefit from exercise of
stock options................ 3,521
Comprehensive income:
Net income.................
Foreign currency
translation adjustment,
net of tax
of $(2,252)...............
Reclassification
adjustments for settled
hedging positions,
net of tax of $25,204....
Changes in fair value of
outstanding hedging
positions, net of tax
of $(40,358)..............
Total comprehensive
income ..................
---------- ------ -------- -------- ---------- -----------
BALANCE, SEPTEMBER 30, 2003... 56,876,630 $ 569 (884,704) $(26,616) $787,689 $ (11,857)
========== ====== ======== ======== ======== ===========
ACCUMULATED
OTHER TOTAL
RETAINED COMPREHENSIVE STOCKHOLDERS'
EARNINGS INCOME (LOSS) EQUITY
-------- ------------- ------------
BALANCE, DECEMBER 31, 2002.... $436,263 $(31,183) $1,009,231
Issuance of common stock...... 140,401
Issuance of restricted
stock, less amortization
of $522...................... 522
Treasury stock, at cost....... (403)
Amortization of stock
compensation................. 1,593
Tax benefit from exercise of
stock options................ 3,521
Comprehensive income:
Net income................. 159,335 159,335
Foreign currency
translation adjustment,
net of tax
of $(2,252)............... 4,182 4,182
Reclassification
adjustments for settled
hedging positions,
net of tax of $25,204.... (46,809) (46,809)
Changes in fair value of
outstanding hedging
positions, net of tax
of $(40,358).............. 74,951 74,951
----------
Total comprehensive
income .................. 191,659
-------- -------- ----------
BALANCE, SEPTEMBER 30, 2003 .. $595,598 $ 1,141 $1,346,524
======== ======== ==========
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 and the Anadarko and Arkoma Basins.
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.
On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. As a result
of the sale, the historical results of operations of Newfield Exploration
Australia Ltd. are reflected in our financial statements as "discontinued
operations." Please see Note 2, "Discontinued Operations." Except where noted
and for pro forma earnings per share, discussions in these notes relate to our
continuing activities only.
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, including those related to our discontinued operations (see
Note 2, "Discontinued Operations"), 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 nine months ended September 30, 2003 and 2002 would have
approximated the pro forma amounts below:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- ----------------------------
2003 2002 2003 2002
---------- --------- ----------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income:
As reported .................................... $ 49,379 $ 9,371 $ 159,335 $ 41,967
Pro forma stock-based compensation
expense (net of tax) ......................... (1,468) (1,449) (4,731) (4,052)
---------- --------- ----------- ----------
Pro forma ...................................... $ 47,911 $ 7,922 $ 154,604 $ 37,915
========== ========= =========== ==========
Earnings per share:
Basic --
As reported .................................. $ 0.88 $ 0.21 $ 2.96 $ 0.95
Pro forma .................................... $ 0.86 $ 0.18 $ 2.88 $ 0.86
Diluted --
As reported .................................. $ 0.88 $ 0.21 $ 2.86 $ 0.93
Pro forma .................................... $ 0.85 $ 0.18 $ 2.78 $ 0.84
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 as a component of depreciation, depletion and amortization expense 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 estimated 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 are 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;
- cumulative accretion of the ARO from the period incurred up to
the January 1, 2003 adoption date; and
- cumulative depreciation on the additional capitalized costs
included in oil and gas properties up to the January 1, 2003
adoption date.
The change in our ARO since adoption of SFAS No. 143 is set forth below
(in thousands):
Initial ARO as of January 1, 2003............................... $ 128,471
Accretion expense............................................... 5,500
Additions....................................................... 14,000
Settlement of ARO............................................... (3,880)
-----------
Balance of ARO as of September 30, 2003......................... $ 144,091
===========
6
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of our adoption of SFAS No. 143, we recorded a $134.8
million increase in the net capitalized costs of our oil and gas properties.
Additionally, we 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, including in each case discontinued operations) for
the cumulative effect of change in accounting principle. Had SFAS No. 143 been
applied retroactively to the three and nine months ended September 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 NINE MONTHS
ENDED ENDED
SEPTEMBER 30, 2002 SEPTEMBER 30, 2002
------------------ ------------------
Net income:
As reported...................... $ 9,371 $ 41,967
Pro forma........................ $ 8,854 $ 40,481
Earnings per share:
Basic --
As reported...................... $ 0.21 $ 0.95
Pro forma........................ $ 0.20 $ 0.91
Diluted --
As reported...................... $ 0.21 $ 0.93
Pro forma........................ $ 0.20 $ 0.90
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 has had 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 no effect on our financial statements.
7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 have had no effect on our
financial statements.
RECENT ACCOUNTING DEVELOPMENTS
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other 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 be
accounted for using the purchase method and that certain intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142 established
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. To our knowledge, substantially
all publicly traded oil and gas companies have continued to include oil and gas
rights and interests held under leases, governmental licenses or other
contractual arrangements (leasehold interests) as part of oil and gas
properties after SFAS No. 141 and SFAS No. 142 became effective. It is our
understanding that the staffs of the FASB and the Securities and Exchange
Commission may have questioned the oil and gas industry's application of SFAS
Nos. 141 and 142 to leasehold interests.
Based on our understanding of the SEC's and the FASB's potential
interpretation of SFAS Nos. 141 and 142, 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 142 were applied as described above, at September 30, 2003
we had undeveloped leasehold interests of approximately $106 million (without
reduction for depreciation, depletion and amortization) that would be classified
on our consolidated balance sheet as "intangible undeveloped leaseholds" and we
had developed leasehold interests of approximately $620 million (without
reduction for depreciation, depletion and amortization) 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. We will continue to classify our leasehold interests as tangible oil
and gas properties until further guidance is provided.
8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. DISCONTINUED OPERATIONS:
On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. We received
$9.7 million in proceeds, which was the agreed upon sales price plus estimated
working capital at the time of closing. We recorded a receivable for an
additional $9.6 million, which will be collected as the barrels in inventory at
the time of sale are lifted and sold by the new owner. We recognized a loss of
$9.9 million on the sale. The historical results of operations of Newfield
Exploration Australia Ltd. are reflected in our financial statements as
"discontinued operations." This reclassification affects not only the 2003
presentation of our financial statements, but also the presentation of all prior
period financial statements.
The results of operations of Newfield Exploration Australia Ltd., which
have been classified as discontinued operations for the three and nine months
ended September 30, 2003 and 2002, are summarized as follows (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2003 2002 2003 2002
-------- -------- -------- --------
Revenues ................................. $ 4,092 $ 10,632 $ 15,485 $ 24,334
Operating expenses ....................... (4,128) (9,426) (21,888) (19,332)
-------- -------- -------- --------
Income (loss) from operations ............ (36) 1,206 (6,403) 5,002
Other income (expense) ................... 1,354 1,209 (3,478) (2,089)
-------- -------- -------- --------
Income (loss) before income taxes ........ 1,318 2,415 (9,881) 2,913
Income tax benefit (provision) ........... (395) (684) 2,784 (895)
-------- -------- -------- --------
Income (loss) from operations ............ 923 1,731 (7,097) 2,018
Loss on sale ............................. (9,895) -- (9,895) --
-------- -------- -------- --------
Income (loss) from discontinued operations $ (8,972) $ 1,731 $(16,992) $ 2,018
======== ======== ======== ========
The major classes of assets and liabilities of Newfield Exploration
Australia Ltd. that have been reclassified as discontinued operations as of
December 31, 2002 are summarized as follows:
DECEMBER 31,
2002
-------------
(In thousands)
Cash and cash equivalents .............................. $15,100
Accounts receivable--oil and gas ....................... 4,819
Inventories ............................................ 6,650
Other current assets ................................... 5,064
-------
Total current assets .............................. 31,633
-------
Oil and gas properties, net of accumulated
depreciation, depletion and amortization ............ 23,093
Furniture, fixtures and equipment, net ................. 778
-------
Total other assets ................................ 23,871
-------
Total assets .................................. $55,504
=======
Accounts payable ....................................... $ 591
Accrued liabilities .................................... 5,692
-------
Total current liabilities ......................... 6,283
-------
Other liabilities ...................................... 1,027
Deferred taxes ......................................... 4,532
-------
Total other liabilities ........................... 5,559
-------
Total liabilities ............................. $11,842
=======
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. 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, to the extent outstanding at any
time during the period, as if exercise or conversion to common stock had
occurred at the beginning of the period. If the assumed conversion of our trust
preferred securities is dilutive, net income is increased for distributions
accrued on the securities during the period.
The following is a calculation of basic and diluted weighted average
shares outstanding and EPS for the three and nine months ended September 30,
2003 and 2002:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- -------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Income (numerator):
Income from continuing operations ......................................... $ 58,351 $ 7,640 $ 170,752 $ 39,949
Income (loss) from discontinued operations, net of tax .................... (8,972) 1,731 (16,992) 2,018
--------- --------- --------- ---------
Income before cumulative effect of change in accounting principle ......... 49,379 9,371 153,760 41,967
Cumulative effect of change in accounting principle, net of tax:
Adoption of SFAS No. 143 .............................................. -- -- 5,575 --
--------- --------- --------- ---------
Net income--basic ......................................................... 49,379 9,371 159,335 41,967
After-tax dividends on convertible trust preferred securities ............. -- -- 2,978 --
--------- --------- --------- ---------
Net income--diluted ....................................................... $ 49,379 $ 9,371 $ 162,313 $ 41,967
========= ========= ========= =========
Weighted average shares (denominator):
Weighted average shares-- basic ....................................... 55,887 44,420 53,785 44,337
Dilutive effect of stock options outstanding
at end of period .................................................... 460 485 443 573
Dilutive effect of convertible trust
preferred securities ................................................ -- -- 2,550 --
--------- --------- --------- ---------
Weighted average shares-- diluted ..................................... 56,347 44,905 56,778 44,910
========= ========= ========= =========
Earnings per share:
Basic --
Income from continuing operations ................................... $ 1.04 $ 0.17 $ 3.17 $ 0.90
Income (loss) from discontinued operations .......................... (0.16) 0.04 (0.31) 0.05
Cumulative effect of change in accounting principle, net of tax ..... -- -- 0.10 --
--------- --------- --------- ---------
Net income ........................................................ $ 0.88 $ 0.21 $ 2.96 $ 0.95
========= ========= ========= =========
Diluted --
Income from continuing operations ................................... $ 1.04 $ 0.17 $ 3.06 $ 0.89
Income (loss) from discontinued operations .......................... (0.16) 0.04 (0.30) 0.04
Cumulative effect of change in accounting principle, net of tax ..... -- -- 0.10 --
--------- --------- --------- ---------
Net income ........................................................ $ 0.88 $ 0.21 $ 2.86 $ 0.93
========= ========= ========= =========
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 601,650 and
1,519,900 shares for the three months ended September 30, 2003 and 2002,
respectively, and 874,050 and 798,100 shares for the nine months ended September
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.
We redeemed all of our trust preferred securities on June 27, 2003.
Please see Note 8, "Convertible Preferred Securities of Newfield Financial Trust
I."
10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. ACQUISITIONS:
EEX ACQUISITION
On November 26, 2002, we acquired EEX Corporation primarily to expand
our onshore operations. The EEX properties were complementary to our existing
South Texas property base. The acquisition also accelerated our expansion into
deepwater.
The unaudited pro forma results presented below for the three and nine
months ended September 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 that date or to project our
results of operations for any future date or period.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2002 SEPTEMBER 30, 2002
------------------ ------------------
(IN THOUSANDS, EXCEPT PER SHARE)
Pro forma:
Revenue......................................................... $ 176,689 $ 551,790
Income from operations.......................................... 32,038 112,842
Net income...................................................... 2,246 30,745
Basic earnings per share........................................ $ 0.04 $ 0.60
Diluted earnings per share...................................... $ 0.04 $ 0.59
PRIMARY NATURAL RESOURCES ACQUISITION
On September 5, 2003, we acquired Primary Natural Resources, Inc. (PNR)
for cash equal to approximately $91 million to strengthen our position in one of
our focus areas -- the Anadarko and Arkoma Basins of the Mid-Continent.
We accounted for the acquisition as a purchase using the accounting
standards established in SFAS No. 141, "Business Combinations," and SFAS No.
142, "Goodwill and Other Intangible Assets." Our consolidated financial
statements include PNR's results of operations subsequent to September 5, 2003.
We recorded the estimated fair values of the assets acquired and the liabilities
assumed at September 5, 2003, which primarily included oil and gas properties of
$94.4 million, a deferred tax liability of $19.7 million and goodwill of $16.8
million. We recorded the deferred tax liability to recognize the difference
between the historical tax basis of PNR's assets and the acquisition costs
recorded for book purposes. The recorded book value of the proved oil and gas
properties was increased and goodwill was recorded to recognize this tax basis
differential. Goodwill represents the excess of the purchase price over the
estimated fair value of the net assets acquired in the purchase. This goodwill
is not deductible for tax purposes.
5. OIL AND GAS ASSETS:
Oil and gas properties at the indicated dates consisted of the
following:
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
(IN THOUSANDS)
Subject to amortization ............................ $ 3,561,224 $ 3,037,464
Not subject to amortization
Exploration wells in progress .................. 38,624 8,212
Development wells in progress .................. 14,609 6,732
Capitalized interest ........................... 20,890 14,036
Other capital costs:
Incurred in 2003 ........................... 43,282 --
Incurred in 2002 ........................... 133,163 135,641
Incurred in 2001 ........................... 57,456 63,302
Incurred in 2000 and prior ................. 26,132 33,635
----------- -----------
Total not subject to amortization ....... 334,156 261,558
----------- -----------
Gross oil and gas properties ....................... 3,895,380 3,299,022
Accumulated depreciation, depletion and amortization (1,562,088) (1,312,110)
----------- -----------
Net oil and gas properties ......................... $ 2,333,292 $ 1,986,912
=========== ===========
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A portion of incurred (if not previously included in the amortization
base) and future development costs associated with qualifying major development
projects may be temporarily excluded from amortization. To qualify, a project
must require significant costs to ascertain the quantities of proved reserves
attributable to the properties under development (e.g., the installation of an
offshore production platform from which development wells are to be drilled).
Incurred and future costs are allocated between completed and future work. Any
temporarily excluded costs are included in the amortization base upon the
earlier of when the associated reserves are determined to be proved or
impairment is indicated.
As of September 30, 2003, we excluded from the amortization base $25.7
million associated with estimated development costs for our deepwater Gulf of
Mexico project known as Glider (Green Canyon 247/248). The amounts included and
excluded from the amortization base are based on the ratio of existing proved
reserves to total proved reserves expected to be established upon completion of
the Glider project.
6. GOODWILL:
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," have been applied to our Primary Natural Resources
acquisition (see Note 4, "Acquisitions--Primary Natural Resources Acquisition").
Accordingly, PNR's tangible assets and liabilities have been adjusted to fair
values with the remainder of the purchase price recorded as goodwill. We
allocated all of the goodwill to our Mid-Continent reporting unit. This is the
first time we have recorded goodwill in connection with an acquisition.
Goodwill is not amortized but is reviewed for impairment at least
annually or more frequently if impairment indicators arise. The impairment test
requires the allocation of goodwill and all other assets and liabilities to
reporting units. The fair value of each reporting unit is determined and
compared to the book value of that reporting unit. If the fair value of the
reporting unit is less than its book value (including goodwill) then goodwill is
reduced to its implied fair value and the amount of the writedown is charged to
earnings.
We will perform our goodwill impairment test annually on December 31,
or more frequently if impairment indicators arise. The fair value of the
Mid-Continent reporting unit is based on our estimates of future net cash flows
from proved reserves and from future exploration for and development of unproved
reserves. Downward revisions of estimated reserves or production, increases
in estimated future costs or depressed crude oil and natural gas prices could
lead to an impairment of all or a portion of goodwill in future periods.
7. DEBT:
As of the indicated dates, long-term debt consisted of the following:
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
(IN THOUSANDS)
Senior unsecured debt:
Bank revolving credit facility:
Prime rate based loans .................................. $ -- $ --
LIBOR based loans ....................................... 139,000 28,000
-------- --------
Total bank revolving credit facility ................. 139,000 28,000
Money market lines of credit (1) ............................ 2,000 8,000
-------- --------
Total credit arrangements ............................ 141,000 36,000
-------- --------
7.45% Senior Notes due 2007 ................................. 124,811 124,781
Fair value adjustment associated with interest rate hedges... 533 --
7 5/8% Senior Notes due 2011 ................................ 174,902 174,895
Fair value adjustment associated with interest rate hedges... 543 --
-------- --------
Total senior unsecured notes ......................... 300,789 299,676
-------- --------
Total senior unsecured debt .......................... 441,789 335,676
-------- --------
8 3/8% Senior Subordinated Notes due 2012 ....................... 248,077 247,971
Secured notes ................................................... 2,364 65,963
Gas sales obligation (1) ........................................ -- 60,005
-------- --------
Total long-term debt ................................. $692,230 $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 as of the indicated dates,
these obligations are classified as long-term.
At September 30, 2003 and December 31, 2002, the interest rate was
2.50% and 2.737%, respectively, for LIBOR-based loans under our credit facility
and 3.0% and 2.615%, respectively, for the loans outstanding under our money
market lines of credit.
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
INTEREST RATE SWAPS
During September 2003, we entered into interest rate swap agreements to
take advantage of low interest rates and to obtain what we view as a more
desirable proportion of variable and fixed rate debt. These swap agreements
provide for us to pay variable and receive fixed interest payments, and are
designated as fair value hedges of a portion of our outstanding senior notes. At
September 30, 2003, we hedged $50 million principal amount of our 7.45% Senior
Notes due 2007 and $50 million principal amount of our 7 5/8% Senior Notes due
2011.
SFAS No. 133 requires all derivatives to be recorded on the balance
sheet at fair value. Changes in the fair value of derivatives designated as fair
value hedges are recognized as offsets to the changes in fair value of the
exposure being hedged. The fair value of these swaps are reflected within our
derivative assets on our consolidated balance sheet. Changes in the fair value
of the swaps are recorded as an adjustment to the carrying value of the
associated long-term debt. Receipts and payments related to the interest rate
swaps are reflected in interest expense.
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.
8. 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.
9. 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)
10. GEOGRAPHIC INFORMATION:
UNITED STATES INTERNATIONAL TOTAL
------------- ------------- ----------
(IN THOUSANDS)
THREE MONTHS ENDED SEPTEMBER 30, 2003:
Oil and gas revenues................................. $ 248,664 $ -- $ 248,664
Operating expenses:
Lease operating.................................. 31,083 -- 31,083
Production and other taxes....................... 7,488 -- 7,488
Transportation................................... 1,624 -- 1,624
Depreciation, depletion and amortization......... 100,897 -- 100,897
Allocated income taxes........................... 37,650 --
---------- ----------
Net income from oil and gas properties....... $ 69,922 $ --
========== ==========
General and administrative (inclusive of stock
compensation) (1).............................. 13,815
----------
Total operating expenses..................... 154,907
---------
Income from operations............................... 93,757
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (8,903)
Unrealized commodity derivative income........... 3,569
----------
Income before income taxes........................... $ 88,423
==========
Total long-lived assets.............................. $2,287,991 $ 45,301 $2,333,292
========== ========== ==========
Additions to long-lived assets....................... $ 253,185 $ 6,393 $ 259,578
========== ========== ==========
THREE MONTHS ENDED SEPTEMBER 30, 2002:
Oil and gas revenues................................. $ 141,978 $ -- $ 141,978
Operating expenses:
Lease operating.................................. 20,309 -- 20,309
Production and other taxes....................... 3,738 -- 3,738
Transportation................................... 1,730 -- 1,730
Depreciation, depletion and amortization......... 69,910 -- 69,910
Allocated income taxes........................... 16,202 --
---------- ----------
Net income from oil and gas properties....... $ 30,089 $ --
========== ==========
General and administrative (inclusive of stock
compensation) (1).............................. 13,387
----------
Total operating expenses..................... 109,074
----------
Income from operations............................... 32,904
Interest expense and dividends, net of interest
income, capitalized interest and other......... (6,968)
Unrealized commodity derivative expense.......... (13,952)
---------
Income before income taxes........................... $ 11,984
==========
Total long-lived assets.............................. $1,370,707 $ 35,186 $1,405,893
========== ========== ==========
Additions to long-lived assets....................... $ 151,657 $ 4,875 $ 156,532
========== ========== ==========
- --------------
(1) General and administrative expense includes stock compensation charges
of $629 and $731 for the three months ended September 30, 2003 and
2002, respectively.
14
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
UNITED STATES INTERNATIONAL TOTAL
------------- ------------- ----------
(IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, 2003:
Oil and gas revenues................................. $ 772,107 $ -- $ 772,107
Operating expenses:
Lease operating.................................. 85,807 -- 85,807
Production and other taxes....................... 25,159 -- 25,159
Transportation................................... 5,046 -- 5,046
Depreciation, depletion and amortization......... 293,407 -- 293,407
Allocated income taxes........................... 126,941 --
---------- ----------
Net income from oil and gas properties....... $ 235,747 $ --
========== ==========
Gas sales obligation settlement and redemption
of securities.................................. 20,475
General and administrative (inclusive of stock
compensation) (1).............................. 46,008
----------
Total operating expenses..................... 475,902
----------
Income from operations............................... 296,205
Interest expense and dividends, net of interest
income, capitalized interest and other ........ (36,922)
Unrealized commodity derivative income........... 723
----------
Income before income taxes........................... $ 260,006
==========
Total long-lived assets.............................. $2,287,991 $ 45,301 $2,333,292
========== ========== ==========
Additions to long-lived assets (2) .................. $ 587,400 $ 8,958 $ 596,358
========== ========== ==========
NINE MONTHS ENDED SEPTEMBER 30, 2002:
Oil and gas revenues................................. $ 437,926 $ -- $ 437,926
Operating expenses:
Lease operating.................................. 63,298 -- 63,298
Production and other taxes....................... 11,009 -- 11,009
Transportation................................... 4,377 -- 4,377
Depreciation, depletion and amortization......... 215,937 -- 215,937
Allocated income taxes........................... 50,157 --
---------- ----------
Net income from oil and gas properties....... $ 93,148 $ --
========== ==========
General and administrative (inclusive of stock
compensation) (1).............................. 37,766
----------
Total operating expenses..................... 332,387
----------
Income from operations............................... 105,539
Interest expense and dividends, net of interest
income, capitalized interest and other......... (17,848)
Unrealized commodity derivative expense.......... (25,477)
----------
Income before income taxes........................... $ 62,214
==========
Total long-lived assets.............................. $1,370,707 $ 35,186 $1,405,893
========== ========== ==========
Additions to long-lived assets....................... $ 221,991 $ 6,998 $ 228,989
========== ========== ==========
- --------------
(1) General and administrative expense includes stock compensation charges
of $2,115 and $2,066 for the nine months ended September 30, 2003 and
2002, respectively.
(2) Includes domestic additions of $115.1 million for capitalized asset
retirement obligations.
15
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
We utilize swap, floor, collar and three-way collar 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 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. 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. A three-way collar contract consists of a standard collar contract
plus an additional put sold by us at a price below the floor price of the
collar. The additional put requires us to make a payment to the counterparty if
the settlement price for any settlement period is below the put price. Combining
the collar contract with the additional put results in us being entitled to a
net payment equal to the difference between the floor price of the standard
collar and the additional put price if the settlement price is equal to or less
than the additional put price. If the settlement price is greater than the
additional put price, the result is the same as it would have been with a
standard collar contract only. This strategy enables us to increase the floor
and the ceiling price of the collar beyond the range of a traditional cashless
collar while defraying the associated cost with the sale of the additional put.
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 "Accumulated 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
"Accumulated 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 September 30, 2003, we had a net $0.8 million in after-tax income recorded
under the caption "Accumulated other comprehensive income (loss)--Commodity
derivatives" associated with commodity derivatives. We expect hedged production
associated with commodity derivatives that account for a net gain of
approximately $2.1 million to be sold within the next 12 months and hedged
production associated with the remaining net loss of approximately $1.3 million
to be sold subsequent to that period. The actual gain or loss on these commodity
derivatives could vary significantly as a result of changes in market conditions
and other factors.
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)--Commodity
derivatives" on our consolidated balance sheet. As a result, amounts recorded in
the third quarter and first nine months 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.
16
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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 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.
Although our three-way collar contracts are effective as economic
hedges of our commodity price exposure, they do not qualify for hedge accounting
under SFAS No. 133. These contracts are carried at their fair value on our
consolidated balance sheet under the captions "Derivative assets" and
"Derivative liabilities." We recognize all changes in the fair value of our
three-way collar contracts on our consolidated statement of income for the
period in which the change occurs under the caption "Unrealized commodity
derivative income (expense)."
NATURAL GAS
As of September 30, 2003, we had entered into derivative contracts that
qualify as cash flow hedges with respect to our future natural gas production as
follows:
NYMEX CONTRACT PRICE PER MMBTU
-------------------------------------------------------------------
COLLARS
-------------------------------------------------------
FLOORS CEILINGS
SWAPS -------------------------- -------------------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED
PERIOD AND TYPE OF CONTRACT MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE
- --------------------------------- ---------- -------- ------------- --------- -------------- --------
October 2003 - December 2003
Price swap contracts.......... 15,617 $4.43 -- -- -- --
Collar contracts ............. 20,597 -- $3.50 - $5.50 $4.80 $3.90 - $15.00 $7.38
Floor contracts............... 3,000 -- -- -- -- --
January 2004 - March 2004
Price swap contracts.......... 9,835 5.39 -- -- -- --
Collar contracts ............. 20,755 -- 3.00 - 5.50 4.94 4.16 - 15.00 8.52
April 2004 - June 2004
Price swap contracts.......... 10,365 4.77 -- -- -- --
Collar contracts ............. 4,845 -- 3.00 - 4.50 4.27 4.16 - 5.75 5.31
July 2004 - September 2004
Price swap contracts.......... 10,075 4.75 -- -- -- --
Collar contracts.............. 4,845 -- 3.00 - 4.50 4.27 4.16 - 5.75 5.31
October 2004 - December 2004
Price swap contracts.......... 5,245 4.79 -- -- -- --
Collar contracts.............. 1,945 -- 3.00 - 4.50 4.11 4.16 - 5.75 5.20
January 2005 - December 2005
Price swap contracts.......... 5,440 4.43 -- -- -- --
Collar contracts ............. 1,380 -- 3.50 3.50 4.16 4.16
NYMEX CONTRACT PRICE PER MMBTU
-------------------------------
FLOOR CONTRACTS ESTIMATED
----------------------------- FAIR VALUE
WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT RANGE AVERAGE (IN MILLIONS)
- --------------------------------- ------------- -------- -----------------
October 2003 - December 2003
Price swap contracts.......... -- -- $ (6.0)
Collar contracts ............. -- -- 4.3
Floor contracts............... $4.70 - $4.98 $4.78 2.0
January 2004 - March 2004
Price swap contracts.......... -- -- 1.9
Collar contracts.............. -- -- 6.4
April 2004 - June 2004
Price swap contracts.......... -- -- 0.3
Collar contracts.............. -- -- (0.2)
July 2004 - September 2004
Price swap contracts.......... -- -- 0.3
Collar contracts.............. -- -- (0.3)
October 2004 - December 2004
Price swap contracts.......... -- -- --
Collar contracts ............. -- -- (0.5)
January 2005 - December 2005
Price swap contracts.......... -- -- (1.6)
Collar contracts ............. -- -- (1.1)
------
$ 5.5
======
17
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
As of September 30, 2003, we also had entered into three-way collar
contracts with respect to our future natural gas production as set forth in the
table below. These contracts do not qualify for hedge accounting.
NYMEX CONTRACT PRICE PER MMBTU
------------------------------------------------------------------
COLLARS
---------------------------------------
ADDITIONAL PUT FLOORS CEILINGS ESTIMATED
------------------------ ---------------------- -------------- FAIR VALUE
VOLUME IN WEIGHTED WEIGHTED WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT MMMBTUS RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE (IN MILLIONS)
- ----------------------------- -------- -------------- -------- ------------- ------- ----- -------- -----------------
April 2004 - June 2004
3-Way collar contracts ... 4,500 $3.61 - $3.76 $3.67 $4.61 - $4.76 $4.67 $5.20 $5.20 $ --
July 2004 - September 2004
3-Way collar contracts ... 4,500 3.61 - 3.76 3.67 4.61 - 4.76 4.67 5.20 5.20 (0.2)
October 2004 - December 2004
3-Way collar contracts ... 1,500 3.61 - 3.76 3.67 4.61 - 4.76 4.67 5.20 5.20 (0.2)
------
$ (0.4)
======
OIL
As of September 30, 2003, we had entered into derivative contracts that
qualify as cash flow hedges with respect to our future oil production as
follows:
NYMEX CONTRACT PRICE PER BBL
--------------------------------------------------------------------
COLLARS
-------------------------------------------------------
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)
- ------------------------------- ---------- -------- --------------- --------- -------------- -------- -----------------
October 2003 - December 2003
Price swap contracts........ 300,000 $27.55 -- -- -- -- $ (0.4)
Collar contracts............ 627,000 -- $22.00 - $24.00 $22.47 $26.35 - $29.70 $27.83 (1.0)
January 2004 - March 2004
Price swap contracts........ 69,000 26.86 -- -- -- -- --
Collar contracts............ 405,000 -- 22.00 - 24.00 22.70 26.04 - 29.70 27.28 (0.6)
April 2004 - June 2004
Price swap contracts........ 24,000 23.23 -- -- -- -- (0.1)
Collar contracts............ 300,000 -- 22.00 - 24.00 22.80 26.04 - 28.85 27.16 (0.3)
July 2004 - September 2004
Price swap contracts........ 24,000 23.23 -- -- -- -- (0.1)
Collar contracts............ 60,000 -- 22.00 22.00 26.35 26.35 (0.1)
October 2004 - December 2004
Price swap contracts........ 24,000 23.23 -- -- -- -- (0.1)
January 2005 - December 2005
Price swap contracts........ 204,000 22.63 -- -- -- -- (0.5)
------
$ (3.2)
======
As of September 30, 2003, we also had entered into three-way collar
contracts with respect to our future oil production as set forth in the table
below. These contracts do not qualify for hedge accounting.
NYMEX CONTRACT PRICE PER BBL
-------------------------------------------------------------------
COLLARS
------------------------------------------------------
FLOORS CEILINGS ESTIMATED
------------------------ -------------------------- FAIR VALUE
VOLUME IN ADDITIONAL WEIGHTED WEIGHTED ASSET (LIABILITY)
PERIOD AND TYPE OF CONTRACT BBLS PUT RANGE AVERAGE RANGE AVERAGE (IN MILLIONS)
- ------------------------------- ---------- ---------- ------------- -------- --------------- -------- -----------------
January 2004 - March 2004
3-Way collar contracts...... 286,000 $21.00 $26.00 $26.00 $29.80 - $30.05 $29.98 $ 0.1
April 2004 - June 2004
3-Way collar contracts...... 377,000 21.00 25.00 - 26.00 25.76 29.70 - 30.05 29.91 0.2
July 2004 - September 2004
3-Way collar contracts...... 379,000 21.00 25.00 - 26.00 25.76 29.70 - 30.05 29.91 0.1
October 2004 - December 2004
3-Way collar contracts...... 379,000 21.00 25.00 - 26.00 25.76 29.70 - 30.05 29.91 0.1
January 2005 - December 2005
3-Way collar contracts...... 90,000 21.00 25.00 25.00 29.70 29.70 --
-------
$ 0.5
=======
18
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 and the Anadarko and Arkoma Basins. 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.
On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. As a result
of the sale, the historical results of operations of Newfield Exploration
Australia Ltd. are reflected in our financial statements as "discontinued
operations." Please see Note 2, "Discontinued Operations," to our consolidated
financial statements appearing earlier in this report. Except where noted,
discussions in this report relate to our continuing activities.
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.
19
RESULTS OF CONTINUING 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 nine months ended September 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 third quarter and the
first nine months of 2003 were about 75% higher than the comparable periods of
2002 because of higher commodity prices and higher production.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE
---------------------- INCREASE ---------------------- INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
-------- -------- ---------- -------- -------- ----------
PRODUCTION:
Natural gas (Bcf)................... 47.4 34.8 36% 138.1 106.5 30%
Oil and condensate (MMBbls)......... 1.5 1.2 25% 4.6 3.9 18%
Total (Bcfe)........................ 56.1 41.9 34% 165.5 129.7 28%
AVERAGE REALIZED PRICES(1):
Natural gas (per Mcf)............... $ 4.40 $ 3.19 38% $ 4.64 $ 3.22 44%
Oil and condensate (per Bbl)........ 26.52 24.84 7% 27.71 23.52 18%
- -----------------
(1) 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 average realized price of natural gas by
$0.03 and $0.04 for the three months ended September 30, 2003 and 2002,
respectively, and by $0.02 and $0.03 for the nine months ended
September 30, 2003 and 2002, respectively. The average realized price
of oil and condensate was reduced by $0.32 and $0.46 for the three
months ended September 30, 2003 and 2002, respectively, and by $0.36
for both the nine month periods ended September 30, 2003 and 2002.
Average realized prices include the effects of hedging.
PRODUCTION. Our total oil and gas production (stated on a natural gas
equivalent basis) increased in the third quarter and the first nine 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.
NATURAL GAS. Our third quarter and first nine 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. Our oil production for the third quarter and
the first nine months of 2003, as compared to the same periods of the prior
year, increased primarily because of our acquisition of EEX and other small
acquisitions.
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 September 30, 2003............. $ 4.40 $ 4.78 92%
Three months ended September 30, 2002............. 3.19 3.02 106%
Nine months ended September 30, 2003.............. 4.64 5.42 86%
Nine months ended September 30, 2002.............. 3.22 2.86 113%
Crude Oil and Condensate:
Three months ended September 30, 2003............. $ 26.52 $ 28.68 92%
Three months ended September 30, 2002............. 24.84 26.10 95%
Nine months ended September 30, 2003.............. 27.71 29.81 93%
Nine months ended September 30, 2002.............. 23.52 23.49 100%
- -------------------
(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.
20
OPERATING EXPENSES. We are a growth oriented company. As such, our
proved reserves and production have grown steadily since our founding.
Naturally, our operating expenses have increased with our growth. As a result,
we believe the most informative way to analyze changes in our operating expenses
from one period to another is on a unit-of-production, or Mcfe, basis. The
following table presents information about our operating expenses for the third
quarter of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT
(PER MCFE) (IN THOUSANDS)
------------------------------------ ------------------------------------
THREE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE
-------------------- INCREASE ---------- ------------ INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
------ ------ ---------- -------- -------- ---------
Lease operating......................... $ 0.55 $ 0.48 15% $ 31,083 $ 20,309 53%
Production and other taxes.............. 0.13 0.09 44% 7,488 3,738 100%
Transportation.......................... 0.03 0.04 (25%) 1,624 1,730 (6%)
Depreciation, depletion and
amortization.......................... 1.80 1.67 8% 100,897 69,910 44%
General and administrative (exclusive
of stock compensation) (1)............ 0.23 0.30 (23%) 13,186 12,656 4%
Total............................. 2.74 2.58 6% 154,278 108,343 42%
- --------------------------
(1) Stock compensation charges were $629, or $0.01 per Mcfe, and $731, or
$0.02 per Mcfe, for the three months ended September 30, 2003 and 2002,
respectively.
Our total operating expense (excluding stock compensation) for the
third quarter of 2003, stated on a unit-of-production basis, increased 6% over
the same period in 2002. The increase was primarily related to the following
items:
- Lease operating expense (LOE) on a unit-of-production basis
for the third quarter of 2003 increased over the same period
of last year in large part due to a higher level of workover
activity in 2003 and the addition of higher cost properties
through the EEX acquisition.
- Production taxes on a unit-of-production basis increased in
the third 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 third 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 third quarter of 2002.
- General and administrative expense (G&A) before incentive
compensation expense and capitalized direct internal costs on
a unit-of-production basis decreased by $0.04 per Mcfe for the
third quarter of 2003, as compared to the same period of 2002,
because production growth was greater than the growth in our
workforce. This decrease was offset by a significant increase
in incentive compensation expense during the third quarter of
2003, as compared to the same period of 2002, because of the
significant increase in our earnings. During the third quarter
of 2003, we capitalized $6.2 million of direct internal costs
compared to $2.3 million in the same period of 2002.
The following table presents information about our operating expenses for
the first nine months of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT
(PER MCFE) (IN THOUSANDS)
------------------------------------ ------------------------------------
NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE
-------------------- INCREASE ---------- ------------ INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
------ ------ ---------- -------- -------- ---------
Lease operating......................... $ 0.52 $ 0.49 6% $ 85,807 $ 63,298 36%
Production and other taxes.............. 0.15 0.08 88% 25,159 11,009 129%
Transportation.......................... 0.03 0.03 -- 5,046 4,377 15%
Depreciation, depletion and
amortization.......................... 1.77 1.66 7% 293,407 215,937 36%
General and administrative (exclusive
of stock compensation) (1)............ 0.27 0.28 (4%) 43,893 35,700 23%
Total............................. 2.74 2.54 8% 453,312 330,321 37%
- ------------------
(1) Stock compensation charges were $2,115, or $0.01 per Mcfe, and $2,066,
or $0.02 per Mcfe, for the nine months ended September 30, 2003 and
2002, respectively. Total operating expense, inclusive of these charges
but excluding the gas sales obligation settlement and redemption of our
trust preferred securities, was $455,427, or $2.76 per Mcfe, and
$332,387, or $2.56 per Mcfe, for the nine months ended September 30,
2003 and 2002, respectively.
21
Our total operating expense (excluding stock compensation, the gas
sales obligation settlement and redemption of our trust preferred securities)
for the first nine months of 2003, stated on a unit-of-production basis,
increased 8% over the same period in 2002. The increase was primarily related to
the following items:
- Lease operating expense (LOE) on a unit-of-production basis
for the first nine months of 2003 increased over the same
period of last year in large part due to a higher level of
workover activity in 2003 and the addition of higher cost
properties through the EEX acquisition.
- Production taxes on a unit-of-production basis increased in
the first nine 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 nine months of 2003 was $1.72 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 third
quarter of 2002.
- G&A before capitalized direct internal costs on a unit-of-
production basis for the first nine months of 2003 increased
by $0.06 per Mcfe as a result of a significant increase in
incentive compensation expense during the 2003 period as
compared to the 2002 period. This increase is the result of
the significant increase in our earnings. During the first
nine months of 2003, we capitalized $20.4 million of direct
internal costs, compared to $6.4 million in the same period of
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
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
- an agreed upon value for BWT's membership interest in an 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 are 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.
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.
22
INTEREST EXPENSE. Interest expense for the third quarter and the first
nine 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ---------------------
2003 2002 2003 2002
------- ------ ------- -------
(IN MILLIONS)
Gross interest expense ................................ $ 13.4 $ 7.0 $ 45.0 $ 21.4
Capitalized interest .................................. (4.0) (2.3) (11.7) (6.6)
------- ------ ------- -------
Net interest expense .................................. 9.4 4.7 33.3 14.8
Distributions on preferred securities ................. -- 2.3 4.6 7.0
------- ------ ------- -------
Total interest expense and distributions ....... $ 9.4 $ 7.0 $ 37.9 $ 21.8
======= ====== ======= =======
UNREALIZED COMMODITY DERIVATIVE INCOME (EXPENSE). The $3.6 million and
$0.7 million of income for the third quarter and the first nine months of 2003,
respectively, primarily represents the hedge ineffectiveness associated with our
hedging program and the fair value adjustment for our three-way collar contracts
that do not qualify for hedge accounting. The unrealized expense of $14.0
million during the third quarter of 2002 and $25.5 million during the first nine
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 11, "Commodity Derivative Instruments and Hedging Activities,"
to our consolidated financial statements appearing earlier in this report.
TAXES. The effective tax rate for the three and nine month periods
ended September 30, 2003 and 2002 was 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, 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 as a component of DD&A expense 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 estimated 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 are included in DD&A 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;
- cumulative accretion of the ARO from the period incurred up to
the January 1, 2003 adoption date; and
- cumulative depreciation on the additional capitalized costs
included in oil and gas properties up to the January 1, 2003
adoption date.
As a result of our adoption of SFAS No. 143, we recorded a $134.8
million increase in the net capitalized costs of our oil and gas properties and
an initial ARO of $128.5 million. Additionally, we 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, including in each case
discontinued operations) for the cumulative effect of change in accounting
principle.
23
RESULTS OF DISCONTINUED OPERATIONS
On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. As a result
of the sale, the historical financial position, results of operations and cash
flow of Newfield Exploration Australia Ltd. are reflected in our financial
statements as "discontinued operations." Please see Note 2, "Discontinued
Operations," to our consolidated financial statements appearing earlier in this
report.
The results of operations of Newfield Exploration Australia Ltd., which
have been reclassified as discontinued operations for the three and nine months
ended September 30, 2003 and 2002, are summarized as follows (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- -------------------------
2003 2002 2003 2002
-------- -------- -------- --------
Loss on sale of discontinued operations ............... $ (9,895) $ -- $ (9,895) $ --
Income (loss) from discontinued operations
before income taxes ............................... 1,318 2,415 (9,881) 2,913
Income tax benefit (provision) ........................ (395) (684) 2,784 (895)
-------- -------- -------- --------
Income (loss) from discontinued operations ............ $ (8,972) $ 1,731 $(16,992) $ 2,018
======== ======== ======== ========
The decrease in earnings from discontinued operations before income
taxes for the three months ended September 30, 2003 compared to the same period
in 2002 was primarily due to the timing of oil liftings from our FPSOs in 2002
as compared to 2003.
The decrease in earnings from discontinued operations before income
taxes for the nine months ended September 30, 2003 compared to the same period
in 2002 was primarily due to a ceiling test writedown of $7.3 million ($5.1
million after-tax) recorded in the second quarter of 2003 and the timing of oil
liftings from our FPSOs in 2002 as compared to 2003.
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.
Our cash flow from operations during the first nine months of 2003
significantly exceeded our capital expenditures (including the acquisition of
Primary Natural Resources) during that period. We used the excess cash flow to
pay down debt (see Note 7, "Debt," to our consolidated financial statements
appearing earlier in this report and "--Credit Arrangements" and "--Cash Flow
used in Continuing Financing Activities" below). We anticipate that our fourth
quarter 2003 capital expenditures will be substantially funded by cash flow from
operations. To the extent that cash receipts during the quarter are less than
capital needs, we will make up the shortfall with borrowings under our credit
arrangements.
CREDIT ARRANGEMENTS. 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 October 31, 2003), 30% of the
principal amount of any outstanding senior subordinated notes (a reduction of
$75 million at October 31, 2003) and the outstanding principal amount of the
secured notes ($3 million at October 31, 2003). The borrowing base will be
redetermined at least semi-annually and, prior to reduction for the foregoing
items, was $805 million at November 1, 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
October 31, 2003, we had outstanding borrowings under our credit facility of
$129 million and no outstanding borrowings under our money market lines.
Consequently, at October 31, 2003, we had approximately $336 million of
available capacity under our credit arrangements.
24
At September 30, 2003, the interest rate for our outstanding
LIBOR-based loans was 2.5% and for our outstanding money market lines of credit
was 3.0%. 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.
During September 2003, we entered into interest rate swap agreements
that effectively convert the fixed interest rate on a portion of our outstanding
senior notes into a variable interest rate (see Note 7, "Debt--Interest Rate
Swaps," to our consolidated financial statements appearing earlier in this
report and "Item 3. Quantitative and Qualitative Disclosures about Market Risk"
appearing later 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 deficit of $13.3 million as of September
30, 2003. This compares to a working capital deficit of $57.0 million as of
December 31, 2002.
CASH FLOW FROM CONTINUING OPERATIONS. Our net cash from operations for
the first nine months of 2003 increased 66% compared to the first nine months of
2002. This increase was primarily due to higher operating income.
CAPITAL EXPENDITURES. Our capital spending, including discontinued
operations, during the first nine months of 2003 was $482 million, a 95%
increase over the same period of last year. During the first nine months of
2003, we invested approximately $150 million in proved property acquisitions,
$163 million in U.S. development, $147 million in U.S. exploration, $12 million
in other U.S. operations and $10 million internationally.
Since the beginning of the year, we have increased our capital budget
for 2003 from $450 million to $640 million, including discontinued operations.
The budget includes $250 million for U.S. development, $230 million for U.S.
exploration, $150 million for proved property acquisitions and $10 million for
international projects. These budget amounts broken down by area are
approximately 56% U.S. onshore, 42% Gulf of Mexico (including deepwater) and the
balance international. Acquisitions are opportunistic and are not budgeted under
our capital program unless specifically identified at the time the budget is
prepared. We continue to pursue attractive acquisition opportunities; however,
the timing, size and purchase price of acquisitions are unpredictable.
Historically, we have completed several acquisitions of varying sizes each year,
as we have done this 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 USED IN CONTINUING 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 Continuing Operations--Redemption of
Trust Preferred Securities."
During the first nine months of 2003, we either repurchased or repaid
$74.3 million principal amount of our secured notes.
On March 31, 2003, all of our obligations under the gas forward sales
contract with Bob West Treasure L.L.C. and all other agreements related to the
gas sales contract were terminated in exchange for a payment by us of
approximately $73 million. For a further discussion of this settlement, please
see "--Results of Continuing Operations--Gas Sales Obligation Settlement."
OIL AND GAS 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 83% (on an
Mcfe basis) of our production target for the three 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.
25
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.
Please see the discussion and tables in Note 11, "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 contracts as of September 30, 2003
and the fair value of those contracts as of that date. Between September 30,
2003 and November 3, 2003, we entered into the following transactions.
NYMEX CONTRACT PRICE PER MMBTU
-------------------------------------------------------------------------
COLLARS
----------------------------------
ADDITIONAL PUT FLOORS CEILINGS
SWAPS ------------------- ----------------- ---------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED
PERIOD AND TYPE OF CONTRACT MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE
- --------------------------- --------- --------- -------- --------- ----- -------- ----- --------
October 2003 - December 2003
Ceiling contracts............... 1,500 -- -- -- -- -- $6.55 $6.55
January 2004 - December 2004
Price swap contracts............ 15,900 $4.93 -- -- -- -- -- --
Collar contracts................ 2,250 -- -- -- $5.00 $ 5.00 7.50 7.50
3-Way collar contracts.......... 1,350 -- $4.25 $4.25 5.00 5.00 7.00 7.00
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 Continuing
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.
ASSETS HELD FOR SALE
As a result of our acquisition of EEX Corporation in November 2002, we
own a 60% interest in a floating production system (FPS), some offshore
pipelines and a processing facility located at the end of the pipelines in
shallow water. The FPS is a combination deepwater drilling rig and processing
facility capable of simultaneous drilling and production operations. These
infrastructure assets are not currently in service and we do not have a specific
use for them in our offshore operations. At the time of acquisition, we
estimated their fair market value to be $35 million and classified them as
"assets held for sale" under the provisions of SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement provides that an
asset can only be classified as "held for sale" for one year. Therefore, should
a sale not occur during the fourth quarter of 2003, these assets must be
re-categorized as held in use assets and periodically evaluated for impairment.
RECENT DEVELOPMENTS
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other 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 be
accounted for using the purchase method and that certain intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142 established
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. To our knowledge substantially
all publicly traded oil and gas companies have continued to include oil and gas
rights and interests held under leases, governmental licenses or other
contractual arrangements (leasehold interests) as part of oil and gas properties
after SFAS No. 141 and SFAS No. 142 became effective. It is our understanding
that the staffs of the FASB and the Securities and Exchange Commission may have
questioned the oil and gas industry's application of SFAS Nos. 141 and 142 to
leasehold interests.
26
Based on our understanding of the SEC's and the FASB's potential
interpretation of SFAS Nos. 141 and 142, 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 142 were applied as described above, at September
30, 2003 we had undeveloped leasehold interests of approximately $106 million
(without reduction for depreciation, depletion and amortization) that would be
classified on our consolidated balance sheet as "intangible undeveloped
leaseholds" and we had developed leasehold interests of approximately $620
million (without reduction for depreciation, depletion and amortization) 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. We will continue to classify our leasehold interests as tangible oil
and gas properties until further guidance is provided.
27
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 [email protected] or visit our web
page and sign up.
Our Annual Report on Form 10-K, quarterly reports on Form 10-Q and
current reports on Form 8-K, as well as any amendments and exhibits to those
reports, are available free of charge through our website as soon as reasonably
practicable after we file or furnish them to the SEC.
FORWARD-LOOKING INFORMATION
This report contains information that is forward-looking or relates to
anticipated future events or results such as planned capital expenditures, the
availability of capital resources to fund capital expenditures and anticipated
cash flow. Although we believe that the expectations reflected in this
information are reasonable, this information is based upon assumptions and
anticipated results that are subject to numerous uncertainties. Actual results
may vary significantly from those anticipated due to many factors, including
drilling results, oil and gas prices, industry conditions, the prices of goods
and services, the availability of drilling rigs and other support services and
the availability of capital resources.
COMMONLY USED OIL AND GAS TERMS
Below are explanations of some commonly used terms in the oil and gas
business.
Basis risk. The risk associated with the sales point price for oil or
gas production varying from the reference (or settlement) price
for a particular hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or condensate.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil or condensate.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees to
59.5 degrees Fahrenheit.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil or condensate.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMMBtu. One billion Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil or condensate.
NYMEX. The New York Mercantile Exchange.
28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk from changes in oil and gas prices and
interest rates as discussed below:
OIL AND GAS PRICES
Please see the discussion and tables in Note 11, "Commodity Derivative
Instruments and Hedging Activities," to our consolidated financial statements
appearing earlier in this report and the discussion under the caption "Oil and
Gas Hedging," in Item 2 of this report for a description of our hedging program
and a listing of open hedging contracts as of September 30, 2003 and the fair
value of those contracts as of that date.
INTEREST RATES
During September 2003, we entered into interest rate swap agreements
with respect to a portion of our outstanding senior notes to take advantage of
low interest rates and to obtain what we view as a more desirable proportion of
variable and fixed rate debt. Under the terms of the interest rate swap
contracts with respect to our 7.45% Senior Notes due 2007, we receive a fixed
semi-annual rate of 7.45% on $50 million principal amount and pay the
counterparties a variable rate equal to the three-month LIBOR, reset quarterly,
plus 425 basis points. Under the terms of the interest rate swap contract with
respect to our 7 5/8% Senior Notes due 2011, we receive a fixed semi-annual rate
of 7.625% on $50 million principal amount and pay the counterparty a variable
rate equal to the three-month LIBOR, reset quarterly, plus 349 basis points. We
continue to consider our interest rate exposure to be minimal because the
majority, about 65%, of our long-term debt obligations were at fixed rates at
September 30, 2003.
FOREIGN CURRENCY EXCHANGE 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 September 30, 2003.
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by 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 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit Number Description
- -------------- -----------
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 September 30, 2003, we filed a current report on Form 8-K
announcing the issuance of our @NFX publication, which included a
summary of our natural gas and crude oil hedge positions as of
September 25, 2003.
On September 15, 2003, we filed a current report on Form 8-K
providing the information required by Regulation BTR with respect to
our 401(k) plan.
On September 9, 2003, we filed a current report on Form 8-K
disclosing information regarding our recent acquisition and divestiture
activity, as well as recent drilling results.
On July 24, 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.
30
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NEWFIELD EXPLORATION COMPANY
Date: November 12, 2003 By: /s/ TERRY W. RATHERT
---------------------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal Financial
Officer)
31
EXHIBIT INDEX
Exhibit Number Description
- -------------- -----------
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