1
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------------------------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001
Commission file number 1-12534
---------------------------------------------
NEWFIELD EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 72-1133047
(State or other jurisdiction (I.R.S. employer
of incorporation or organization) identification number)
363 N. Sam Houston Parkway E.
Suite 2020
Houston, Texas 77060
(Address and Zip Code of principal executive offices)
Registrant's telephone number, including area code: (281) 847-6000
---------------------------------------------
Indicate by check mark whether the Registrant (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file
such reports, and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
As of August 1, 2001, there were 44,208,412 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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2
TABLE OF CONTENTS
PART I
<Table>
<Caption>
Page
-----
Item 1. Financial Statements:
Consolidated Balance Sheet as of June 30, 2001
and December 31, 2000 ..................................... 1
Consolidated Statement of Income for the three and six months
ended June 30, 2001 and 2000 .............................. 2
Consolidated Statement of Cash Flows for the
six months ended June 30, 2001 and 2000 ................... 3
Consolidated Statement of Stockholders' Equity
for the six months ended June 30, 2001 .................... 4
Notes to Consolidated Financial Statements ................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations .......................... 15
PART II
Item 4. Submission of Matters to a Vote of Security Holders ............ 24
Item 6. Exhibits and Reports on Form 8-K ............................... 25
</Table>
-ii-
3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2001 2000
--------------- ---------------
ASSETS
Current assets:
Cash and cash equivalents ...................... $ 51,789 $ 18,451
Accounts receivable-oil and gas ................ 113,910 147,643
Inventories .................................... 9,677 7,572
Commodity derivatives .......................... 55,744 --
Other current assets ........................... 8,772 5,891
--------------- ---------------
Total current assets ......................... 239,892 179,557
--------------- ---------------
Oil and gas properties (full cost method, of which
$151,231 at June 30, 2001 and $106,783 at
December 31, 2000 were excluded from
amortization) .................................. 2,269,684 1,589,150
Less-accumulated depreciation, depletion and
amortization ................................... (887,886) (756,243)
--------------- ---------------
1,381,798 832,907
--------------- ---------------
Furniture, fixtures and equipment, net ........... 6,350 4,028
Commodity derivatives ............................ 8,973 --
Other assets ..................................... 10,549 6,758
--------------- ---------------
Total assets ................................. $ 1,647,562 $ 1,023,250
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ............................... $ 19,435 $ 10,209
Other accrued liabilities ...................... 165,572 128,190
Advances from joint owners ..................... 3,055 2,661
Commodity derivatives .......................... 9,307 --
--------------- ---------------
Total current liabilities .................... 197,369 141,060
--------------- ---------------
Other liabilities ................................ 9,761 6,030
Commodity derivatives ............................ 4,862 --
Long-term debt ................................... 351,609 133,711
Deferred taxes ................................... 225,038 79,244
--------------- ---------------
Total long-term liabilities .................. 591,270 218,985
--------------- ---------------
Company-obligated, mandatorily redeemable,
convertible preferred securities of Newfield
Financial Trust I ............................... 143,750 143,750
--------------- ---------------
Commitments and contingencies .................... -- --
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000
shares authorized, no shares issued) ......... -- --
Common stock ($0.01 par value, 100,000,000
shares authorized; 44,748,629 and
42,625,764 shares issued at June 30, 2001
and December 31, 2000, respectively) ......... 447 426
Additional paid-in capital ....................... 361,001 286,811
Treasury stock (at cost, 547,997 and 18,463
shares at June 30,2001 and December 31, 2000,
respectively) .................................. (17,435) (399)
Unearned compensation ............................ (9,287) (6,201)
Accumulated other comprehensive income (loss) -
Foreign currency translation adjustment ........ (6,901) (4,644)
Commodity derivatives .......................... 28,798 --
Retained earnings ................................ 358,550 243,462
--------------- ---------------
Total stockholders' equity ................... 715,173 519,455
--------------- ---------------
Total liabilities and stockholders' equity ... $ 1,647,562 $ 1,023,250
=============== ===============
</Table>
The accompanying notes to consolidated financial statements are an integral part
of this financial statement.
-1-
4
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In thousands, except per share data)
(Unaudited)
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- -----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Oil and gas revenues ............................... $ 200,747 $ 114,704 $ 410,073 $ 212,526
------------ ------------ ------------ ------------
Operating expenses:
Lease operating .................................. 22,750 14,249 43,574 29,740
Production and other taxes ....................... 5,463 334 12,581 1,999
Transportation ................................... 1,563 1,567 2,825 3,103
Depreciation, depletion and amortization ......... 71,577 46,182 132,723 87,393
General and administrative (includes non-cash
stock compensation of $703 and $906 for the
three months ended June 30, 2001 and 2000,
respectively, and $1,298 and $1,495 for the
six months ended June 30, 2001 and 2000,
respectively) .................................. 11,939 7,163 23,224 14,098
------------ ------------ ------------ ------------
Total operating expenses ....................... 113,292 69,495 214,927 136,333
------------ ------------ ------------ ------------
Income from operations ............................. 87,455 45,209 195,146 76,193
Other income (expenses):
Interest income .................................. 529 407 1,142 922
Interest expense, net ............................ (3,817) (2,913) (9,469) (5,173)
Dividends on convertible preferred
securities of Newfield Financial Trust I ....... (2,336) (2,336) (4,672) (4,672)
Unrealized commodity derivative income ........... 5,719 -- 4,161 --
------------ ------------ ------------ ------------
95 (4,842) (8,838) (8,923)
------------ ------------ ------------ ------------
Income before income taxes ......................... 87,550 40,367 186,308 67,270
Income tax provision:
Current .......................................... 9,399 10,730 30,488 14,447
Deferred ......................................... 21,414 2,581 35,938 8,224
------------ ------------ ------------ ------------
30,813 13,311 66,426 22,671
------------ ------------ ------------ ------------
Income before cumulative effect of change in
accounting principles ............................ 56,737 27,056 119,882 44,599
Cumulative effect of change in accounting
principles, net of tax
Adoption of SAB 101 ............................ -- -- -- (2,360)
Adoption of SFAS 133 ........................... -- -- (4,794) --
------------ ------------ ------------ ------------
Net income ......................................... $ 56,737 $ 27,056 $ 115,088 $ 42,239
============ ============ ============ ============
Earnings per share
Basic -
Income before cumulative effect of
change in accounting principles .............. $ 1.27 $ 0.64 $ 2.70 $ 1.06
Cumulative effect of change in
accounting principles ........................ -- -- (0.11) (0.06)
------------ ------------ ------------ ------------
Net income ..................................... $ 1.27 $ 0.64 $ 2.59 $ 1.00
============ ============ ============ ============
Diluted -
Income before cumulative effect of
change in accounting principles .............. $ 1.18 $ 0.60 $ 2.50 $ 1.01
Cumulative effect of change in
accounting principles ........................ -- -- (0.09) (0.05)
------------ ------------ ------------ ------------
Net income ..................................... $ 1.18 $ 0.60 $ 2.41 $ 0.96
============ ============ ============ ============
Weighted average number of shares outstanding
for basic earnings per share .................... 44,651 42,402 44,387 42,140
============ ============ ============ ============
Weighted average number of shares outstanding
for diluted earnings per share .................. 49,314 47,322 49,098 47,049
============ ============ ============ ============
</Table>
The accompanying notes to consolidated financial statements are an integral part
of this financial statement.
-2-
5
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
<Table>
<Caption>
Six Months Ended
June 30,
-------------------------------
2001 2000
------------ ------------
Cash flows from operating activities:
Net income ............................................................ $ 115,088 $ 42,239
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion
and amortization .................................................. 132,723 87,393
Deferred taxes ...................................................... 35,938 8,224
Stock compensation .................................................. 1,298 1,495
Unrealized commodity derivative income .............................. (4,161) --
Cumulative effect of change in
accounting principles ............................................. 4,794 2,360
------------ ------------
285,680 141,711
Changes in assets and liabilities, net of
business acquired:
(Increase) decrease in accounts receivable-
oil and gas ....................................................... 62,412 (22,515)
Increase in inventories ............................................. (2,714) (1,791)
(Increase) decrease in other
current assets ................................................... (6,295) 532
(Increase) decrease in other assets ................................. (3,706) 291
Increase (decrease) in accounts payable
and accrued liabilities ........................................... 12,969 (4,408)
Increase in advances from joint owners .............................. 394 1,712
Increase (decrease) in other liabilities ............................ 3,802 (2,533)
------------ ------------
Net cash provided by
operating activities ............................................ 352,542 112,999
------------ ------------
Cash flows from investing activities:
Acquisition of Lariat Petroleum,
net of cash acquired .............................................. (264,089) --
Additions to oil and gas properties ................................. (255,838) (223,982)
Additions to furniture, fixtures and
equipment ......................................................... (2,036) (840)
------------ ------------
Net cash used in investing activities ............................. (521,963) (224,822)
------------ ------------
Cash flows from financing activities:
Proceeds from borrowings ............................................ 852,000 153,000
Repayments of borrowings ............................................ (809,000) (68,000)
Proceeds from issuance of senior notes .............................. 174,879 --
Proceeds from issuance of common
stock, net ......................................................... 1,353 4,938
Purchases of treasury stock ......................................... (17,036) --
------------ ------------
Net cash provided by financing
activities ...................................................... 202,196 89,938
------------ ------------
Effect of exchange rate changes on cash and
cash equivalents .................................................... 563 (451)
------------ ------------
Increase (decrease) in cash and cash
equivalents ............................................................. 33,338 (22,336)
Cash and cash equivalents, beginning of period ............................ 18,451 41,841
------------ ------------
Cash and cash equivalents, end of period .................................. $ 51,789 $ 19,505
============ ============
</Table>
The accompanying notes to consolidated financial statements are an integral part
of this financial statement.
-3-
6
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In thousands, except share data)
(Unaudited)
<Table>
<Caption>
Common Stock Additional Treasury Stock
-------------------------- Paid-in -------------------------- Unearned
Shares Amount Capital Shares Amount Compensation
----------- ----------- ----------- ----------- ----------- ------------
Balance, December 31,
2000 ....................... 42,625,764 $ 426 $ 286,811 (18,463) $ (399) $ (6,201)
Issuance of common
stock .................... 2,019,865 20 69,186
Purchase of treasury
stock
Issuance of
restricted stock,
less amortization
of $319 .................. 103,000 1 4,383 (4,065)
Treasury Stock ............... (529,534) (17,036)
Cancellation of
restricted stock
Amortization of stock
compensation ............. 979
Tax benefit from
exercise of
stock options ............ 621
Comprehensive Income:
Net income .................
Foreign currency
translation
adjustment ...............
Cumulative effect of
accounting change,
net of tax of $39,964 ....
Reclassification
adjustments for
settled contracts,
net of tax of
$36,316 ..................
Changes in fair value
of outstanding
hedging positions,
net of tax of
$19,154 ..................
Total
Comprehensive
Income ...........
----------- ----------- ----------- ----------- ----------- -----------
Balance, June 30,
2001 ........................ 44,748,629 $ 447 $ 361,001 (547,997) $ (17,435) $ (9,287)
=========== =========== =========== =========== =========== ===========
<Caption>
Accumulated
Other Total
Retained Comprehensive Stockholders'
Earnings Loss Equity
----------- ------------- ------------
Balance, December 31,
2000 ....................... $ 243,462 $ (4,644) $ 519,455
Issuance of common
stock .................... 69,206
Purchase of treasury
stock
Issuance of
restricted stock,
less amortization
of $319 .................. 319
Treasury Stock ............... (17,036)
Cancellation of
restricted stock
Amortization of stock
compensation ............. 979
Tax benefit from
exercise of
stock options ............ 621
Comprehensive Income:
Net income ................. 115,088 115,088
Foreign currency
translation
adjustment ............... (2,257) (2,257)
Cumulative effect of
accounting change,
net of tax of $39,964 .... (74,218) (74,218)
Reclassification
adjustments for
settled contracts,
net of tax of
$36,316 .................. 67,445 67,445
Changes in fair value
of outstanding
hedging positions,
net of tax of
$19,154 .................. 35,571 35,571
-----------
Total
Comprehensive
Income ........... 141,629
----------- ----------- -----------
Balance, June 30,
2001 ........................ $ 358,550 $ 21,897 $ 715,173
=========== =========== ===========
</Table>
The accompanying notes to consolidated financial statements are an integral
part of this financial statement.
-4-
7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Accounting Policies
Basis of Presentation
Unless the context otherwise requires, references to the "Company"
include Newfield Exploration Company and its subsidiaries. All significant
intercompany balances and transactions have been eliminated. The unaudited
consolidated financial statements of the Company reflect, in the opinion of
management, all adjustments, consisting only of normal and recurring
adjustments, necessary to present fairly the Company's consolidated financial
statements for the periods presented. The consolidated financial statements have
been prepared in accordance with the instructions to Form 10-Q and therefore do
not include all disclosures required for financial statements prepared in
conformity with generally accepted accounting principles. Interim period results
are not necessarily indicative of results of operations or cash flows for a full
year. Certain reclassifications have been made to prior year's reported amounts
in order to conform to the current year presentation.
These consolidated financial statements and the notes thereto should be
read in conjunction with the Company's Annual Report on Form 10-K for the year
ended December 31, 2000, including the financial statements and notes thereto.
Accounting Changes
On January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and
Hedging Activities" as amended by SFAS Nos. 137 and 138. See Note 5, "Commodity
Derivative Instruments and Hedging Activities."
On June 29, 2001, the Financial Accounting Standards Board ("FASB")
approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets."
Under SFAS No. 141, all business combinations should be accounted for
using the purchase method of accounting; use of the pooling-of-interests method
is prohibited. The provisions of the statement will apply to all business
combinations initiated after June 30, 2001.
SFAS No. 142 will apply to all acquired intangible assets whether
acquired singly, as part of a group or in a business combination. The statement
will supersede Accounting Principles Board ("APB") Opinion No. 17, "Intangible
Assets," but continues provisions in APB Opinion No. 17 related to internally
developed intangible assets. Adoption of SFAS No. 142 will result in ceasing
amortization of goodwill. All of the provisions of the statement should be
applied in fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial
position at that date, regardless of when those assets were initially
recognized. The Company does not expect the adoption of these standards to have
a material effect on its consolidated financial statements.
The FASB recently approved for issuance SFAS No. 143, "Accounting for
Asset Retirement Obligations." This statement changes the method of accruing for
costs associated with the retirement of fixed assets (e.g. oil & gas production
facilities, etc.) that an entity is legally obligated to incur. Implementation
of this standard is required no later than January 1, 2003, with earlier
application encouraged. The Company will further evaluate the impact and timing
of implementing SFAS No. 143 when the final standard is issued.
-5-
8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Unaudited)
Earnings per Share
Basic earnings per common share (EPS) is computed by dividing net
income by the weighted average number of common shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
securities were exercised for or converted into common stock.
The following is a calculation of basic and diluted weighted average
shares outstanding for each of the three and six month periods ended June 30,
2001 and 2000.
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
(In thousands, except per share data):
Income (numerator):
Income - basic ........................ $ 56,737 $ 27,056 $115,088 $ 42,239
After tax dividends on convertible
trust preferred securities ......... 1,518 1,518 3,037 3,037
-------- -------- -------- --------
Income - diluted ...................... $ 58,255 $ 28,574 $118,125 $ 45,276
======== ======== ======== ========
Shares (denominator):
Shares - basic ........................ 44,651 42,402 44,387 42,140
Dilution effect of stock options
outstanding at end of period ........ 740 997 788 986
Dilution effect of convertible
trust preferred securities .......... 3,923 3,923 3,923 3,923
-------- -------- -------- --------
Shared - diluted ...................... 49,314 47,322 49,098 47,049
======== ======== ======== ========
Earnings per share:
Basic ................................ $ 1.27 $ 0.64 $ 2.59 $ 1.00
Diluted .............................. $ 1.18 $ 0.60 $ 2.41 $ 0.96
</Table>
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 869,050 and 43,500
shares for the three months ended June 30, 2001 and 2000, respectively, and
657,800 and 63,000 for the six months ended June 30, 2001 and 2000,
respectively, because to do so would have been antidilutive.
-6-
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
Hedging
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires
enterprises to recognize all derivatives as either assets or liabilities on
their balance sheet and measure those instruments at fair value. See Note 5 -
"Derivative Instruments and Hedging Activities."
For all periods prior to January 1, 2001, the Company accounted for
commodity price hedging contracts in accordance with SFAS No. 80. Pursuant to
SFAS No. 80, gains and losses on these contracts were recognized in revenue in
the period in which the underlying production was delivered. Hedging contracts
were measured for correlation at both the inception of the contract and on an
ongoing basis. If a contract ceased to meet the criteria for deferral
accounting, any subsequent gains or losses were recognized in revenue. If a
hedging contract was terminated prior to maturity, resulting gains and losses
were deferred until the hedged item was recognized in revenue. Neither the
hedging contracts nor the unrealized gains or losses on these contracts were
recognized in the financial statements.
(2) Acquisitions
On January 23, 2001, the Company acquired all of the outstanding
capital stock of Lariat Petroleum, Inc. ("Lariat") by merging Lariat with and
into Newfield Exploration Mid-Continent Inc., a wholly owned subsidiary of the
Company. The total consideration for the acquisition was approximately $333
million, consisting of $68 million in Newfield stock and $265 million in cash,
inclusive of the assumption of debt and certain other obligations of Lariat.
In February 2000, the Company acquired interests in three producing gas
fields in South Texas for approximately $137 million in cash.
The acquisitions have been accounted for as purchases and, accordingly,
income and expenses for Lariat and from the South Texas properties have been
included in the Company's statement of income from the date of purchase.
The unaudited pro forma results of operations assuming that such
acquisitions occurred on January 1 of the respective periods are as follow (in
thousands, except per share amounts):
<Table>
<Caption>
Six Months Ended
June 30,
-------------------------
2001 2000
---------- ----------
Pro forma Pro forma
(Unaudited)
Revenue ..................................... $ 415,715 $ 245,592
Income from operations ...................... 196,287 79,984
Income before cumulative effect of change
in accounting principles .................. 119,664 41,030
Cumulative effect of change in accounting
principles ................................ (4,794) (2,360)
Net income .................................. 114,870 38,670
Basic earnings per common share ............. $ 2.59 $ 0.92
Diluted earnings per common share ........... $ 2.40 $ 0.89
</Table>
-7-
10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
The pro forma financial information does not purport to be indicative
of the results of operations that would have occurred had the acquisitions taken
place at the beginning of the periods presented or future results of operations.
(3) Contingencies
The Company has been named as a defendant in certain lawsuits arising
in the ordinary course of business. While the outcome of these lawsuits cannot
be predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows or results of
operations of the Company.
-8-
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(4) Geographic Information
<Table>
<Caption>
Other
United States Australia International Total
------------- ----------- ------------- -----------
(In thousands)
Three months ended June 30, 2001
-----------------------------------
Oil and gas revenues $ 191,167 $ 9,580 $ -- $ 200,747
Operating expenses:
Lease operating 18,508 4,242 -- 22,750
Production and other taxes 4,415 1,048 -- 5,463
Transportation 1,563 -- -- 1,563
Depreciation, depletion and
amortization 69,783 1,794 -- 71,577
Allocated income taxes 33,914 749 --
----------- ----------- -----------
Net income from oil and
gas operations $ 62,984 $ 1,747 $ --
=========== =========== ===========
General and administrative
(inclusive of stock
compensation) 11,939
-----------
Total operating expenses 113,292
-----------
Income from operations 87,455
Interest expense and
dividends, net (5,624)
Unrealized commodity derivative
income 5,719
-----------
Income before income taxes $ 87,550
===========
Total long-lived assets $ 1,351,270 $ 9,177 $ 21,351 $ 1,381,798
=========== =========== =========== ===========
Additions to long-lived assets $ 136,748 $ 1,364 $ 4,650 $ 142,762
=========== =========== =========== ===========
Three months ended June 30, 2000
---------------------------------
Oil and gas revenues $ 108,880 $ 5,824 $ -- $ 114,704
Operating expenses:
Lease operating 12,052 2,197 -- 14,249
Production and other taxes 1,297 (963) -- 334
Transportation 1,567 -- -- 1,567
Depreciation, depletion and
amortization 45,231 951 -- 46,182
Allocated income taxes 17,056 1,092 --
----------- ----------- -----------
Net income from oil and
gas operations $ 31,677 $ 2,547 $ --
=========== =========== ===========
General and administrative
(inclusive of stock
compensation) 7,163
-----------
Total operating expenses 69,495
-----------
Income from operations 45,209
Interest expense and
dividends, net (4,842)
-----------
Income before income taxes $ 40,367
===========
Total long-lived assets $ 766,581 $ 14,335 $ 11,944 $ 792,860
=========== =========== =========== ===========
Additions to long-lived assets $ 45,086 $ 5,840 $ 1,386 $ 52,312
=========== =========== =========== ===========
</Table>
-9-
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
<Table>
<Caption>
Other
United States Australia International Total
------------- ----------- ------------- -----------
(In thousands)
Six months ended June 30, 2001
---------------------------------
Oil and gas revenues $ 394,198 $ 15,875 $ -- $ 410,073
Operating expenses:
Lease operating 36,793 6,781 -- 43,574
Production and other taxes 8,860 3,721 -- 12,581
Transportation 2,825 -- -- 2,825
Depreciation, depletion and
amortization 129,776 2,947 -- 132,723
Allocated income taxes 75,580 728 --
----------- ----------- -----------
Net income from oil and
gas operations $ 140,364 $ 1,698 $ --
=========== =========== ===========
General and administrative
(inclusive of stock
compensation) 23,224
-----------
Total operating expenses 214,927
-----------
Income from operations 195,146
Interest expense and
dividends, net (12,999)
Unrealized commodity derivative
income 4,161
-----------
Income before income taxes $ 186,308
===========
Total long-lived assets $ 1,351,270 $ 9,177 $ 21,351 $ 1,381,798
=========== =========== =========== ===========
Additions to long-lived assets $ 674,078 $ 1,348 $ 5,108 $ 680,534
=========== =========== =========== ===========
Six months ended June 30, 2000
---------------------------------
Oil and gas revenues $ 192,953 $ 19,573 $ -- $ 212,526
Operating expenses:
Lease operating 23,526 6,214 -- 29,740
Production and other taxes 1,989 10 -- 1,999
Transportation 3,103 -- -- 3,103
Depreciation, depletion and
amortization 84,317 3,076 -- 87,393
Allocated income taxes 28,006 3,082 --
----------- ----------- -----------
Net income from oil and
gas operations $ 52,012 $ 7,191 $ --
=========== =========== ===========
General and administrative
(inclusive of stock
compensation) 14,098
-----------
Total operating expenses 136,333
-----------
Income from operations 76,193
Interest expense and
dividends, net (8,923)
-----------
Income before income taxes $ 67,270
===========
Total long-lived assets $ 766,581 $ 14,335 $ 11,944 $ 792,860
=========== =========== =========== ===========
Additions to long-lived assets $ 220,135 $ 13,859 $ 1,514 $ 235,508
=========== =========== =========== ===========
</Table>
-10-
13
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
(5) Commodity Derivative Instruments and Hedging Activities
The Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133, an amendment of FASB Statement No. 133," and SFAS No.
138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of FASB Statement No. 133," on January 1, 2001. In
accordance with the transition provisions of SFAS No. 133, on January 1, 2001,
the Company recorded as cumulative effect adjustments a loss of $74.2 million
(net of tax of $40.0 million) in accumulated other comprehensive loss and a loss
of $4.8 million (net of tax of $2.6 million) in 2001 earnings. In addition, the
adoption resulted in the recognition of $17.7 million of derivative assets and
$139.3 million of derivative liabilities on the balance sheet on January 1,
2001.
The Company maintains a commodity-price risk management strategy that
utilizes derivative instruments in order to hedge against the variability in
cash flows associated with the forecasted sale of its oil and gas production.
While the use of these derivative instruments limits the downside risk of
adverse price movements, they may also limit future revenues from favorable
price movements. The use of derivatives also involves the risk that the counter
parties to such instruments will be unable to meet the financial terms of such
contracts.
All derivatives are recognized on the balance sheet at their fair
value. On the date that the Company enters into a derivative contract, it
designates the derivative as a hedge of the variability in cash flows associated
with the forecasted sale of its oil and gas production. Changes in the fair
value of a derivative that is highly effective as and that is designated and
qualifies as a cash flow hedge, to the extent that the hedge is effective, are
recorded in other comprehensive income (loss), until earnings are affected by
the variability of cash flows of the hedged transaction (e.g., until the sale of
the Company's oil and gas production is recorded in earnings). Such gains or
losses are reported in oil and gas revenues on the consolidated statement of
income. For the six months ended June 30, 2001, the Company had the following
activity in the "Commodity derivatives" component of accumulated other
comprehensive income (in thousands):
<Table>
Cumulative effect of accounting change, net of tax............ $(74,218)
Reclassification adjustments for settled contracts,
net of tax.................................................. 67,445
Change in fair value of outstanding hedging positions,
net of tax.................................................. 35,571
--------
$ 28,798
========
</Table>
The Company expects that within the next twelve months it will
reclassify to earnings $30.2 million in after tax gains out of the net $28.8
million in after tax gains recorded in accumulated other comprehensive income
at June 30, 2001.
-11-
14
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
Any hedge ineffectiveness (which represents the amount by which the
changes in the fair value of the derivative exceed the variability in the cash
flows of the forecasted transaction) is recorded in current-period earnings. For
the three and six month periods ended June 30, 2001, the Company recorded an
unrealized gain of $5.7 million and $4.2 million, respectively, under the income
statement caption "Unrealized commodity derivative income" representing the net
of the ineffective portion of the Company's commodity derivative positions
during the three and six month periods ended June 30, 2001 as well as the change
in the time value component of the option contracts used in the Company's
hedging strategy.
The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk-management objective and
strategy for undertaking various hedge transactions. This process includes
linking all derivatives that are designated as cash flow hedges to the specific
forecasted sale of oil or gas at its physical location. The Company also
formally assesses (both at the hedge's inception and on an ongoing basis)
whether the derivatives that are used in hedging transactions have been highly
effective in offsetting changes in the cash flows of hedged items and whether
those derivatives may be expected to remain highly effective in future periods.
If it is determined that a derivative is not (or has ceased to be) highly
effective as a hedge, the Company will discontinue hedge accounting
prospectively. The gain or loss on the derivative will remain in accumulated
other comprehensive income or loss and will be reclassified into earnings when
the forecasted transaction affects earnings. If hedge accounting is discontinued
and the derivative remains outstanding, the Company will carry the derivative at
its fair value on the balance sheet, recognizing all subsequent changes in the
fair value in current-period earnings. Hedge accounting was not discontinued
during the period for any hedging instruments.
SFAS 133 is complex and subject to a potentially wide range of
interpretation in its application. There are currently several issues before the
FASB and the potential exists for additional issues to be brought under its
review. If subsequent FASB interpretations of SFAS 133 are different than the
Company's current interpretation, it is possible that the application of SFAS
133 on the Company's financial statements will be modified.
NATURAL GAS. As of June 30, 2001, the Company had entered into the
commodity derivative instruments set forth in the table below as a cash flow
hedge of the forecasted sale of its U.S. Gulf Coast natural gas production for
2001 and 2002.
<Table>
<Caption>
NYMEX CONTRACT PRICE PER MMBTU
------------------------------------------------------------------------
COLLARS
--------------------------------------------
FLOORS CEILINGS FLOOR CONTRACTS
SWAPS ---------------------- --------------------- ----------------
VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED FAIR MARKET
PERIOD MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE VALUE(1)
- -------------------------------- -------- --------- ----------- -------- ----------- -------- ------ -------- -------------
July 2001 -- September 2001
Price Swap Contracts ......... 4,880 $ 5.14 -- -- -- -- -- -- $ 9.4 million
Collar Contracts ............. 12,100 -- $3.25-$5.00 $ 4.24 $3.85-$6.30 $ 4.80 -- -- $12.8 million
Floor Contracts .............. 3,000 -- -- -- -- -- $ 5.35 $ 5.35 $ 6.4 million
October 2001 -- December 2001
Price Swap Contracts ......... 4,720 $ 4.63 -- -- -- -- -- -- $ 5.1 million
Collar Contracts ............. 5,140 -- $3.50-$4.75 $ 3.92 $4.50-$6.00 $ 5.16 -- -- $ 3.5 million
January 2002 -- March 2002
Price Swap Contracts ......... 1,500 $ 4.01 -- -- -- -- -- -- $ 0.4 million
Collar Contracts ............. 8,790 -- $3.50-$4.25 $ 3.79 $4.90-$9.95 $ 5.81 -- -- $ 3.6 million
April 2002 -- June 2002
Collar Contracts ............. 4,200 -- $3.75-$4.00 $ 3.98 $4.80-$6.00 $ 5.33 -- -- $ 3.3 million
July 2002 - September 2002
Collar Contracts ............. 4,200 -- $3.75-$4.00 $ 3.98 $4.80-$6.00 $ 5.32 -- -- $ 3.0 million
October 2002 - December 2002
Price Swap Contracts ......... 310 $ 2.73 -- -- -- -- -- --
Collar Contracts ............. 3,300 -- $ 4.00 $ 4.00 $4.80-$6.10 $ 5.27 -- -- $ 2.0 million
</Table>
- ----------
(1) Except for July 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at
June 30, 2001. Because July 2001 NYMEX futures contracts expired on
June 27, 2001, the fair market value of July 2001 hedging contracts
represents the actual settlement value of such contracts.
-12-
15
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
In connection with the acquisition of Lariat in January 2001, the
Company assumed certain commodity derivative instruments and designated them as
cash flow hedges of the forecasted natural gas sales of the Company's production
in Oklahoma. The table below presents the outstanding derivative instruments as
of June 30, 2001.
<Table>
<Caption>
CONTRACT PRICE PER MMBTU
------------------------------------
SWAPS COLLARS
VOLUME IN (WEIGHTED ------------------------ FAIR MARKET
PERIOD MMMBTUS AVERAGE) FLOORS CEILINGS VALUE(1)
-------------------------------------------- --------- --------- ----------- ---------- ---------------
July 2001 -- September 2001
Price Swap Contracts...................... 2,420 $4.11 -- -- $ 2.4 million
October 2001 -- December 2001
Price Swap Contracts...................... 2,420 $4.11 -- -- $ 1.5 million
January 2002 -- December 2002
Price Swap Contracts...................... 3,650 $2.62 -- -- $ (2.9 million)
January 2003 -- March 2003
Price Swap Contracts...................... 900 $2.61 -- -- $ (0.8 million)
</Table>
- ----------
(1) Except for July 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at
June 30, 2001. Because July 2001 NYMEX futures contracts expired on
June 27, 2001, the fair market value of July 2001 hedging contracts
represents the actual settlement value of such contracts.
OIL AND CONDENSATE. As of June 30, 2001, the Company had entered into
commodity derivative instruments set forth in the table below as a cash flow
hedge of the forecasted sale of its U.S. Gulf Coast oil production for 2001 and
2002.
<Table>
<Caption>
NYMEX CONTRACT PRICE PER BBL
------------------------------------------------------------------------------
COLLARS
---------------------------------------------
FLOORS CEILINGS FLOOR CONTRACTS
VOLUME SWAPS ---------------------- ---------------------- ----------------------
IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED FAIR MARKET
PERIOD BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE VALUE(1)
- ----------------------------- -------- --------- ------------- -------- ------------- -------- ------------- -------- -------------
July 2001 -- September 2001
Price Swap Contracts....... 391,000 $23.88 -- -- -- -- -- -- $(0.8 million)
Collar Contracts........... 414,000 -- $24.00-$26.00 $25.19 $27.30-$30.75 $29.97 -- -- $ 0.2 million
Floor Contracts............ 207,000 -- -- -- -- $22.17-$27.04 $25.61 $ 0.2 million
October 2001 -- December 2001
Price Swap Contracts....... 386,400 $23.24 -- -- -- -- -- -- $(1.0 million)
Collar Contracts........... 345,000 -- $24.00-$25.25 $24.77 $27.30-$30.75 $29.26 -- -- $ 0.2 million
Floor Contracts............ 262,200 -- -- -- -- -- $22.17-$26.00 $25.28 $ 0.4 million
January 2002 -- March 2002
Collar Contracts........... 697,500 -- $22.00-$25.00 $23.98 $25.75-$30.75 $28.12 -- -- $ 0.1 million
April 2002 -- June 2002
Collar Contracts........... 637,000 -- $22.00-$25.00 $23.80 $25.75-$30.75 $27.86 -- -- $ 0.2 million
July 2002 -- September 2002
Collar Contracts........... 529,000 -- $23.00-$25.00 $24.37 $26.75-$30.75 $28.59 -- -- $ 0.6 million
October 2002 -- December 2002
Collar Contracts........... 368,000 -- $24.00-$25.00 $24.75 $27.50-$30.75 $28.98 -- -- $ 0.7 million
</Table>
- ----------
(1) Except for July 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at
June 30, 2001. Because July 2001 NYMEX futures contracts expired on
June 20, 2001, the fair market value of July 2001 hedging contracts
represents the actual settlement value of such contracts.
-13-
16
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)
With respect to any particular swap transaction, the counter party is
required to make a payment to the Company in the event that the settlement price
for any settlement period is less than the swap price for such transaction, and
the Company is required to make payment to the counter party in the event that
the settlement price for any settlement period is greater than the swap price
for such transaction. For any particular collar transaction, the counter party
is required to make a payment to the Company if the settlement price for any
settlement period is below the floor price for such transaction, and the Company
is required to make payment to the counter party if the settlement price for any
settlement period is above the ceiling price of such transaction. For any
particular floor transaction, the counter party is required to make a payment to
the Company if the settlement price for any settlement period is below the floor
price for such transaction. The Company is not required to make any payment in
connection with the settlement of a floor transaction.
(6) Treasury Stock
On May 4, 2001, the Company announced that its Board of Directors
authorized the expenditure of up to $50 million to repurchase shares of the
Company's common stock. During the second quarter of 2001, the Company
repurchased 512,000 shares of its common stock for total consideration of $16.4
million, an average of $31.97 per share. Additional repurchases may be effected
from time to time in accordance with applicable securities laws, through
solicited or unsolicited transactions in the market or in privately negotiated
transactions. No limit was placed on the duration of the repurchase program.
Subject to applicable securities laws, such purchases will be at times and in
amounts as the Company deems appropriate. As of August 1, 2001, no shares had
been purchased during the third quarter of 2001.
-14-
17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
As an independent oil and gas producer, our revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas, oil and condensate, which are dependent upon numerous factors
beyond our control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have historically
been very volatile, and there can be no assurance that oil and gas prices will
not be subject to wide fluctuations in the future. A substantial or extended
decline in oil and gas prices could have a material adverse effect on our
financial position, results of operations, cash flows and access to capital and
on the quantities of oil and gas reserves that may be economically produced.
Our results of operations and cash flows may vary significantly from
quarter to quarter as a result of development operations, commodity prices, the
curtailment of production in association with work over and recompletion
activities and the incurrence of expenses related thereto and the timing of
crude oil offloadings from inventory in Australia. Consequently, quarterly
results of operations and cash flows may not be indicative of results for the
full year.
We use the full cost method of accounting. Under this method, all costs
incurred in the acquisition, exploration and development of oil and gas
properties are capitalized into cost centers that are established on a
country-by-country basis. For each cost center, at the end of each quarter, the
net capitalized costs of oil and gas properties are limited to the lower of
unamortized cost or the cost center ceiling, defined as the sum of the present
value (10% discount rate) of estimated future net revenues from proved reserves,
based on period-end oil and gas prices; plus the cost of properties not being
amortized, if any; plus the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any; less related income
tax effects. If net capitalized costs of oil and gas properties exceed the
ceiling limit, we are subject to a ceiling test writedown to the extent of such
excess. A ceiling test writedown is a non-cash charge to earnings. If required,
it would reduce earnings and impact stockholders' equity in the period of
occurrence.
We adopted Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities" on January 1,
2001. Please see the discussion in Note 5, "Derivative Instruments and Hedging
Activities," to our consolidated financial statements appearing earlier in this
report.
In the fourth quarter of 2000 we adopted SEC Staff Accounting Bulletin
(SAB) No. 101, "Revenue Recognition in Financial Statements." SAB No. 101
requires us to report crude oil inventory associated with our Australian
offshore operations at lower of cost or market, which is a change from our
historical policy of recording such inventory at market value on the balance
sheet date, net of estimated costs to sell. The cumulative effect of the change
from the acquisition date of our Australian operations in July 1999 through
December 31, 1999 is a reduction in net income of $2.36 million, or $0.05 per
diluted share, and is shown as the cumulative effect of change in accounting
principle on our consolidated statement of income for the six month period ended
June 30, 2000. The adoption of SAB No. 101 does not affect any period prior to
our acquisition in Australia.
As a result of the adoption of Emerging Issues Task Force (EITF) No.
00-10, "Accounting for Shipping and Handling Fees and Costs," we have
reclassified to operating expenses, for all periods presented, third party costs
incurred to transport production to our sales point. Such costs previously were
recorded as a reduction of the related revenues. This reclassification had no
effect on previously reported net income. Approximately $1.6 million and $3.1
million were reclassified pursuant to EITF No. 00-10 for the three and six month
periods ended June 30, 2000, respectively.
On June 29, 2001, the Financial Accounting Standards Board ("FASB")
approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets."
Under SFAS No. 141, all business combinations should be accounted for
using the purchase method of accounting; use of the pooling-of-interests method
is prohibited. The provisions of the statement will apply to all business
combinations initiated after June 30, 2001.
SFAS No. 142 will apply to all acquired intangible assets whether
acquired singly, as part of a group or in a business combination. The statement
will supersede Accounting Principles Board ("APB") Opinion No. 17, "Intangible
Assets," but continues provisions in APB Opinion No. 17 related to internally
developed intangible assets. Adoption of SFAS No. 142 will result in ceasing
amortization of goodwill. All of the provisions of the statement should be
applied in fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial
position at that date, regardless of when those assets were initially
recognized. We do not expect the adoption of these standards to have a material
effect on our consolidated financial statements.
-15-
18
The FASB recently approved for issuance SFAS No. 143, "Accounting for
Asset Retirement Obligations." This statement changes the method of accruing for
costs associated with the retirement of fixed assets (e.g. oil & gas production
facilities, etc.) that an entity is legally obligated to incur. Implementation
of this standard is required no later than January 1, 2003, with earlier
application encouraged. We will further evaluate the impact and timing of
implementing SFAS No. 143 when the final standard is issued.
Explanation of some commonly used oil and gas terms can be found under
the caption "Commonly Used Oil and Gas Terms" at the end of Management's
Discussion and Analysis.
RESULTS OF OPERATIONS
The following table presents information about our oil and gas
production and realized prices.
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
PRODUCTION:
UNITED STATES
Natural gas (Bcf) ................. 35.5 26.8 66.3 49.5
Oil and condensate (MBbls) ........ 1,374 961 2,615 1,875
Total (Bcfe) ...................... 43.7 32.6 81.9 60.8
AUSTRALIA(2)
Oil and condensate (MBbls) ........ 342 203 581 711
Total (Bcfe) ...................... 2.1 1.2 3.5 4.2
TOTAL
Natural gas (Bcf) ................. 35.5 26.8 66.3 49.5
Oil and condensate (MBbls) ........ 1,716 1,164 3,196 2,586
Total (Bcfe) ...................... 45.8 33.8 85.4 65.0
AVERAGE REALIZED PRICES:(1)
UNITED STATES
Natural gas (per Mcf) ............. $ 4.39 $ 3.21 $ 4.94 $ 2.97
Oil and condensate (per Bbl) ...... 24.45 22.01 24.57 22.88
AUSTRALIA(2)
Oil and condensate (per Bbl) ...... $ 28.02 $ 28.70 $ 27.30 $ 27.52
TOTAL
Natural gas (per Mcf) ............. $ 4.39 $ 3.21 $ 4.94 $ 2.97
Oil and condensate (per Bbl) ...... 25.16 23.17 25.06 24.15
</Table>
----------
(1) As discussed above, as the result of the adoption of EITF No. 00-10, we
have reclassified third party transportation costs as operating
expenses. Previously, such costs were recorded as a reduction of the
related revenue. However, for purposes of this table, average realized
prices for natural gas and oil and condensate are presented net of all
applicable transportation expenses, which reduces the realized price of
natural gas by $0.03 and $0.04 for the three months ended June 30, 2001
and 2000, respectively, and by $0.03 and $0.05 for the six months ended
June 30, 2001 and 2000, respectively. The realized price of oil and
condensate is reduced by $0.30 and $0.38 for the three months ended
June 30, 2001 and 2000, respectively, and by $0.27 and $0.32 for the
six months ended June 30, 2001 and 2000, respectively. Average realized
prices include the effect of hedges.
(2) Represents oil and condensate sold during the period rather than
production.
PRODUCTION
NATURAL GAS. The increase in gas production was primarily related to the
acquisition of producing properties in South Texas in February 2000, the
acquisition of Lariat Petroleum in January 2001, development projects in the
Gulf of Mexico and the success of our drilling program. Gains in production were
partially offset by natural declines from other producing properties.
CRUDE OIL AND CONDENSATE. The increase in oil and condensate production is
mainly due to the acquisition of Lariat Petroleum in January 2001 and
development projects at Vermilion 215 and Eugene Island 198/199/202. These
increases were offset during the six-month period ended June 30, 2001 by the
decrease in reported Australian crude oil production caused by the timing of
liftings of crude oil from our two FPSOs.
-16-
19
EFFECT OF HEDGING ON REALIZED PRICES
<Table>
<Caption>
Average Realized Prices Ratio of
------------------------- Hedged to
With Without Non-Hedged
Hedge Hedge Price(1)
---------- ---------- ----------
Natural Gas
Three months ended June 30, 2000.......... $ 3.21 $ 3.49 92%
Three months ended June 30, 2001.......... $ 4.39 $ 4.64 95%
Six months ended June 30, 2000............ $ 2.97 $ 3.08 96%
Six months ended June 30, 2001............ $ 4.94 $ 5.75 86%
Crude Oil and Condensate
Three months ended June 30, 2000.......... $23.17 $27.53 84%
Three months ended June 30, 2001.......... $25.16 $26.10 96%
Six months ended June 30, 2000............ $24.15 $28.06 86%
Six months ended June 30, 2001............ $25.06 $26.62 94%
</Table>
- ----------
(1) This ratio is determined by dividing the realized price (which includes
the effects of hedging) by the price that otherwise would have been realized
without hedging activities.
OPERATING EXPENSES
The following table presents information about our operating expenses
for the three months ended June 30, 2001 and 2000.
<Table>
<Caption>
UNIT OF PRODUCTION (PER MCFE) AMOUNT (IN MILLIONS)
------------------------------ -------------------------------
Three Months Ended Three Months Ended
June 30, Percentage June 30, Percentage
------------------ Increase ------------------- Increase
2001 2000 (Decrease) 2001 2000 (Decrease)
------ ------- ---------- ------- ------- ----------
UNITED STATES
Lease operating........................... $0.42 $0.37 14% $18,508 $12,052 54%
Production and other taxes................ 0.10 0.04 150% 4,415 1,297 240%
Transportation............................ 0.04 0.05 (20%) 1,563 1,567 0%
Depreciation, depletion and amortization.. 1.59 1.39 14% 69,783 45,231 54%
General and administrative (exclusive of
stock compensation). ................... 0.25 0.19 32% 11,051 6,239 77%
AUSTRALIA
Lease operating........................... $2.07 $1.80 15% $ 4,242 $ 2,197 93%
Production and other taxes................ 0.51 (0.79) 165% 1,048 (963) (209%)
Transportation............................ -- -- -- -- -- --
Depreciation, depletion and amortization.. 0.87 0.79 10% 1,794 951 87%
General and administrative (exclusive of
stock compensation)..................... 0.09 0.01 800% 185 18 928%
TOTAL
Lease operating........................... $0.50 $0.42 19% $22,750 $14,249 60%
Production and other taxes................ 0.12 0.01 1,100% 5,463 334 1,536%
Transportation............................ 0.03 0.05 (40%) 1,563 1,567 0%
Depreciation, depletion and amortization.. 1.56 1.37 14% 71,577 46,182 55%
General and administrative (exclusive of
stock compensation)..................... 0.25 0.19 32% 11,236 6,257 80%
</Table>
Operating expenses during the three-month period ended June 30, 2001
were impacted by the following:
- The per unit of production increase in domestic lease
operating expense reflects higher oilfield service and related
costs in the Gulf of Mexico. The 15% increase in our
Australian lease operating expense per Mcfe is due mainly to
downtime while performing several non-routine maintenance
operations on our FPSOs during the second quarter of 2001,
which resulted in increased expenses and lower production.
- The significant increase in production and other taxes in the
second quarter of 2001 is primarily due to our acquisition of
three producing gas fields in South Texas in February 2000,
the acquisition of Lariat Petroleum in January 2001 and a
higher natural gas price environment during the second quarter
of 2001. The increase in production and other taxes in
Australia is due to revised estimates of such taxes during the
second quarter of 2000 as a result of changes in the timing of
anticipated future capital expenditures in Australia.
- The increase in our domestic depreciation, depletion and
amortization rate is primarily the result of increases in the
cost of drilling goods and services, platform and facilities
construction, industry transportation cost and the completion
of several higher cost wells.
-17-
20
- The increase in general and administrative expense for the
second quarter of 2001 is due primarily to an increase in
performance based pay and our growing workforce. Performance
based compensation excluding stock compensation expense, as a
component of general and administrative expense, increased
from $2.6 million, or $0.08 per Mcfe, for the three months
ended June 30, 2000, to $4.3 million or $0.09 per Mcfe, for
the three months ended June 30, 2001. The increase in
performance based compensation is a result of higher earnings
during the second quarter of 2001 as compared to the
comparable period of 2000. Performance based pay is limited by
profitability. The significant increase in general and
administrative expense on a unit of production basis in
Australia is due to the timing of liftings from our two FPSOs
during the second quarter of 2001 as compared to the same
period of 2000 and lower production as a result of downtime
while performing non-routine maintenance on the FPSOs.
The following table presents information about our operating expenses
for the six months ended June 30, 2001 and 2000.
<Table>
<Caption>
UNIT OF PRODUCTION (PER MCFE) AMOUNT (IN MILLIONS)
------------------------------ --------------------------------
Six Months Ended Six Months Ended
June 30, Percentage June 30, Percentage
---------------- Increase -------------------- Increase
2001 2000 (Decrease) 2001 2000 (Decrease)
------ ------ ---------- --------- -------- ----------
UNITED STATES
Lease operating........................... $0.45 $0.39 15% $ 36,793 $23,526 56%
Production and other taxes................ 0.11 0.03 267% 8,860 1,989 345%
Transportation............................ 0.03 0.05 (40%) 2,825 3,103 (9%)
Depreciation, depletion and amortization.. 1.58 1.39 14% 129,776 84,317 54%
General and administrative (exclusive of
stock compensation). ................... 0.26 0.21 24% 21,492 12,537 71%
AUSTRALIA
Lease operating........................... $1.94 $1.46 33% $ 6,781 $ 6,214 (9%)
Production and other taxes................ 1.07 0.00 100% 3,721 10 37,110%
Transportation............................ -- -- -- -- -- --
Depreciation, depletion and amortization.. 0.85 0.72 18% 2,947 3,076 (4%)
General and administrative (exclusive of
stock compensation)..................... 0.12 0.02 500% 434 66 558%
TOTAL
Lease operating........................... $0.51 $0.46 11% $ 43,574 $29,740 47%
Production and other taxes................ 0.15 0.03 400% 12,581 1,999 529%
Transportation............................ 0.03 0.05 (40%) 2,825 3,103 (9%)
Depreciation, depletion and amortization.. 1.55 1.34 16% 132,723 87,393 52%
General and administrative (exclusive of
stock compensation)..................... 0.26 0.19 37% 21,926 12,603 74%
</Table>
Operating expenses during the six-month period ended June 30, 2001 were
impacted by the following:
- The per unit of production increase in domestic lease
operating expense reflects higher oilfield service and related
costs in the Gulf of Mexico. The 33% increase in our
Australian lease operating expense per Mcfe is due mainly to
downtime while performing several non-routine maintenance
operations on our FPSOs during the first six months 2001,
which resulted in increased expenses and lower production.
- The significant increase in production and other taxes in the
six months ended June 30, 2001 is primarily due to our
acquisition of three producing gas fields in South Texas in
February 2000, the acquisition of Lariat Petroleum in January
2001 and a higher natural gas price environment during the
first six months of 2001. The increase in production and other
taxes in Australia is due to revised estimates of such taxes
during the second quarter of 2000 as a result of changes in
the timing of anticipated future capital expenditures in
Australia.
- The increase in our domestic depreciation, depletion and
amortization rate is primarily the result of increases in the
cost of drilling goods and services, platform and facilities
construction, industry transportation cost and the completion
of several higher cost wells.
- The increase in general and administrative expense for the six
months ended June 30, 2001 is due primarily to an increase in
performance based pay and our growing workforce. Performance
based compensation excluding stock compensation expense, as a
component of general and administrative expense, increased
from $4.4 million, or $0.07 per Mcfe, for the six months ended
June 30, 2000, to $9.5 million or $0.11 per Mcfe, for the six
months ended June 30, 2001. The increase in performance based
compensation is a result of higher earnings during the first
six months of 2001 as compared to the same period of 2000.
Performance based pay is limited by profitability. The
significant increase in general and administrative expense on
a unit of production basis in Australia is due to the timing
of liftings from our two FPSOs during the first six months of
2001 as compared to the same period of 2000 and lower
production as a result of downtime while performing
non-routine maintenance on the FPSOs.
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INTEREST EXPENSE AND DIVIDENDS
We incur interest expense on our $125 million principal amount 7.45%
Senior Notes due 2007, our $175 million principal amount 7 5/8% Senior Notes due
2011 and on borrowings under our reserve-based revolving credit facility and
money market credit lines. Outstanding borrowings under the credit facility and
money market lines of credit may vary significantly from period to period. We
pay dividends on the 6.5% convertible trust preferred securities we issued in
August 1999.
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
2001 2000 2001 2000
------ ------ ------ ------
(In millions)
Gross interest expense................................ $ 6.6 $ 4.3 $ 13.7 $ 7.7
Capitalized interest.................................. (2.8) (1.4) (4.2) (2.6)
------ ------ ------ ------
Net interest expense.................................. 3.8 2.9 9.5 5.1
Dividends on preferred securities..................... 2.3 2.3 4.7 4.7
------ ------ ------ ------
Total interest expense and dividends.................. $ 6.1 $ 5.2 $ 14.2 $ 9.8
====== ====== ====== ======
</Table>
Our higher total interest expense for the three and six month period
ended June 30, 2001 is the result of borrowings in January 2001 to partially
finance the acquisition of Lariat Petroleum. A higher percentage of our interest
costs were capitalized during the three month period ended June 30, 2001 as a
result of the acquisition of Lariat Petroleum. At June 30, 2001, borrowings
under our credit facility were $52 million.
UNREALIZED COMMODITY DERIVATIVE INCOME
As a result of our adoption of SFAS No. 133 effective January 1, 2001,
we are now required to record all derivative instruments on the balance sheet at
fair value. The $5.7 million and $4.1 million unrealized income for the three
and six months ended June 30, 2001, respectively, represent the net of the
ineffective portion of our commodity derivative hedge positions and the change
in the time value component of the option contracts used in our hedging
strategy.
TAXES
The effective tax rate for the three and six month periods ended June
30, 2001 was 35% and 36%, respectively, as compared to 33% and 34% for the
comparable periods in 2000. The effective tax rates were slightly greater than
the statutory tax rate in 2001 as a result of state income taxes associated with
the acquisition of Lariat Petroleum.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. We had a working capital surplus of $42.5 million at
June 30, 2001. This compares to a working capital surplus of $38.1 million at
December 31, 2000. Working capital balances may fluctuate from quarter to
quarter to the extent we increase or decrease borrowings under our revolving
credit facility.
CAPITAL RESOURCES. Historically, we have funded our oil and gas
activities through cash flow from operations, equity capital, public debt and
bank borrowings.
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22
DEBT. The banks participating in our facility have committed to lend
the Company up to $425 million. The amount available under the facility is
subject to a calculated borrowing base determined by banks holding 75% of the
aggregate commitments, which is reduced by the aggregate outstanding principal
amount of any senior notes issued by us (currently $300 million). The borrowing
base is currently $510 million and is redetermined at least semi-annually. No
assurances can be given that the banks will not elect to redetermine the
borrowing base in the future. The new facility contains restrictions on the
payment of dividends and the incurrence of debt as well as other customary
covenants and restrictions. The new facility matures in January 2004. We also
have money market lines of credit with various banks in an amount limited by the
credit facility to $40 million. At June 30, 2001, we had outstanding borrowings
under the credit facility of $42 million and $10 million outstanding borrowings
under the money market lines of credit. Consequently, at June 30, 2001, we had
approximately $200 million of available capacity under our credit arrangements.
CASH FLOW FROM OPERATIONS. Our net cash flow from operations for the
six months ended June 30, 2001 increased 102% over the comparable period of 2000
to $285.7 million. This increase in cash flow is primarily due to sharply higher
commodity prices for gas, higher production volumes and changes in working
capital.
CAPITAL EXPENDITURES. We made capital expenditures of $575.5 million in
the first six months of 2001. This includes $45.4 million for exploration,
$167.1 million for exploitation and development projects and $363.0 million for
property acquisitions, including the $333 million paid for Lariat Petroleum. We
have budgeted $224 million for capital spending for the remainder of 2001.
Approximately $60 million has been budgeted for domestic exploration projects
and $133 million for domestic exploitation and development drilling and the
construction of platforms, facilities and pipelines. International spending is
estimated at $19 million for the remainder of 2001. Acquisitions are
opportunistic and are generally not budgeted under our capital program. We
continue to pursue attractive acquisition opportunities, however, the timing,
size and purchase price of acquisitions are unpredictable. Actual levels of
capital expenditures may vary significantly due to many factors, including
drilling results, oil and gas prices, industry conditions, the prices and
availability of goods and services and the extent to which proved properties are
acquired.
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HEDGING
We enter into various commodity price hedging contracts with respect to
a portion of our anticipated future natural gas and crude oil production. During
2000, approximately 47% of our equivalent production was subject to hedge
positions. As of August 1, 2001, approximately 62% of our anticipated production
for 2001 was or is subject to hedge positions. While the use of these hedging
arrangements limits the downside risk of adverse price movements, they may also
limit future revenues from favorable price movements. The use of hedging
transactions also involves the risk that the counter parties will be unable to
meet the financial terms of such transactions. Such contracts are accounted for
as derivatives in accordance with SFAS No. 133. Please see the discussion in
Note 5, "Derivative Instruments and Hedging Activities," to our consolidated
financial statements appearing earlier in this report.
Historically, we have entered into hedging arrangements with respect to
a portion of our anticipated future production offshore and onshore near the
Gulf Coast. In connection with our acquisition of Lariat Petroleum in January
2001, we assumed natural gas hedges entered into by Lariat with respect to a
portion of its anticipated future production in Oklahoma.
Please see the tables in Note 5, "Commodity Derivative Instruments and
Hedging Activities," to our consolidated financial statements appearing earlier
in this report for a description of our hedging contracts as of June 30, 2001
and the fair value of those contracts as of that date.
In addition to the hedging contracts in Note 5, we have entered into
several contracts after June 30, 2001 for both our natural gas and crude and
condensate production. Specifically, we have added 8,400 MMMbtus of natural gas
swaps for the period of September 2001 through December 2001 at a weighted
average fixed price of $3.56 per MMbtu and 18,600 MMMbtus of natural gas swaps
for the calendar year 2002 at a weighted average fixed price of $3.67 per MMbtu.
Additionally, we added 1.1 million barrels of crude and condensate swaps for the
period from October 2001 through March 2003 at a weighted average price of
$24.92 per barrel and 0.8 million barrels in the form of floors with a weighted
average price of $21.15 per barrel for the same period. We continue to evaluate
additional hedging transactions for the remainder of 2001 and future years.
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STOCK REPURCHASE PROGRAM
On May 4, 2001, we announced that our Board of Directors authorized the
expenditure of up to $50 million to repurchase shares of our common stock. We
purchased 512,000 shares during the second quarter of 2001 for total
consideration of $16.4 million, an average of $31.97 per share. Additional
repurchases may be effected from time to time in accordance with applicable
securities laws, through solicited or unsolicited transactions in the market or
in privately negotiated transactions. No limit was placed on the duration of the
repurchase program. Subject to applicable securities laws, purchases will be at
times and in amounts as we deem appropriate. As of August 1, 2001, no shares had
been purchased during the third quarter of 2001.
ESTIMATED OPERATING AND FINANCIAL DATA; OPERATING ACTIVITIES
We continue to maintain our home page located at www.newfld.com. In
conjunction with our web page, we also maintain our electronic publication
entitled @NFX. @NFX will be periodically published to provide updates on our
current operating activities. @NFX also includes our latest publicly announced
estimates of expected production volumes, costs and expenses for the then
current quarter. All recent additions of @NFX are available on our web page. To
receive @NFX directly by e-mail, please forward your e-mail address to
pmcknight@newfld.com or visit our web page and sign up.
FORWARD LOOKING INFORMATION
Certain of the statements set forth in this report regarding planned
capital expenditures, drilling plans, other capital activities and the financing
of capital expenditures are forward looking and are based upon assumptions and
anticipated results that are subject to numerous uncertainties. Actual results
may vary significantly from those anticipated due to many factors, including
drilling results, oil and gas prices, industry conditions, the prices of goods
and services, the availability of drilling rigs and other support services, the
availability of capital resources and other factors described in our annual
report on Form 10-K for the year ended December 31, 2000. In addition, the
drilling of oil and gas wells and the production of hydrocarbons are subject to
governmental regulations and operating risks.
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COMMONLY USED OIL AND GAS TERMS
Below are explanations of some commonly used terms in the oil and gas
business.
Basis risk. The risk associated with the sales point price for oil or gas
production varying from the reference (or settlement) price
for a particular hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of
crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined by using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees to
59.5 degrees Fahrenheit.
MBbls. One thousand barrels of crude oil or other liquid
hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
MMBbls. One million barrels of crude oil or other liquid
hydrocarbons.
MMbtu. One million Btus.
MMMbtu. One billion Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
NYMEX. The New York Mercantile Exchange
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Part II
Item 4. Submission of Matters to a Vote of Security Holders
At the May 3, 2001 Annual Meeting of Stockholders, our stockholders
voted on two matters. As of the March 6, 2001 record date, 44,680,331
shares of common stock were outstanding and entitled to vote at the
meeting.
(1) Election of Eleven Directors:
Our stockholders elected the eleven nominees for director
until the next annual meeting by the following vote:
<Table>
<Caption>
Nominee Elected For Withheld
----------------- ----------- ------------
Joe B. Foster 29,970,253 7,807,342
David A. Trice 29,970,583 7,807,012
Charles W. Duncan, Jr. 37,563,682 213,913
Howard H. Newman 37,566,362 211,233
Thomas G. Ricks 37,566,962 210,633
C.E. (Chuck) Shultz 37,566,902 210,693
Terry Huffington 37,566,962 210,633
Dennis R. Hendrix 36,679,814 1,097,781
Philip J. Burguieres 37,097,954 679,641
Randy A. Foutch 29,970,013 7,807,582
Claire S. Farley 37,565,972 211,623
</Table>
(2) Appointment of Independent Public Accountants:
The stockholders ratified the appointment of Pricewaterhouse-
Coopers LLP as our independent auditors for 2001 by the
following vote:
<Table>
<Caption>
Abstentions and
For Against Broker Non-Votes
----------- ----------- ----------------
37,510,174 245,217 22,204
</Table>
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
10 Second Amendment Agreement, dated as of May 1, 2001,
amending our Credit Agreement (the Credit Agreement
was included as Exhibit 10.2.2 to our Current Report
on Form 8-K filed with the Securities and Exchange
Commission on February 7, 2001 (File No. 1-12534))
(b) Reports on Form 8-K:
On May 17, 2001, we filed a Current Report on Form 8-K
announcing the expenditure of up to $50 million to repurchase
shares of our common stock.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NEWFIELD EXPLORATION COMPANY
Date: August 3, 2001 By: /s/ TERRY W. RATHERT
------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)
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EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10 Second Amendment Agreement, dated as of May 1, 2001, amending
our Credit Agreement (the Credit Agreement was included as
Exhibit 10.2.2 to our Current Report on Form 8-K filed with
the Securities and Exchange Commission on February 7, 2001
(File No. 1-12534))
</Table>
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