- --------------------------------------------------------------------------------
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, 2002
COMMISSION FILE NUMBER 1-12534
-----------------------------------
NEWFIELD EXPLORATION COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 72-1133047
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER
OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)
363 N. SAM HOUSTON PARKWAY E.
SUITE 2020
HOUSTON, TEXAS 77060
(ADDRESS AND ZIP CODE OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 847-6000
-----------------------------------
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS, AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS.
YES [X] NO [ ]
AS OF AUGUST 14, 2002, THERE WERE 44,411,597 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 I. Unaudited Financial Statements:
Consolidated Balance Sheet as of June 30, 2002 and December 31, 2001........... 1
Consolidated Statement of Income for the three and six months
ended June 30, 2002 and 2001................................................... 2
Consolidated Statement of Cash Flows for the six months ended
June 30, 2002 and 2001......................................................... 3
Consolidated Statement of Stockholders' Equity for the six
months ended June 30, 2002..................................................... 4
Notes to Consolidated Financial Statements..................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................................... 14
PART II
Item 4. Submission of Matters to a Vote of Security Holders................................. 23
Item 6. Exhibits and Reports on Form 8-K.................................................... 24
-ii-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
June 30, December 31,
2002 2001
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents............................................. $ 7,657 $ 26,610
Accounts receivable-oil and gas....................................... 120,918 92,644
Inventories........................................................... 9,446 7,332
Commodity derivatives................................................. 9,318 79,012
Other current assets.................................................. 22,827 25,006
------------- -------------
Total current assets.............................................. 170,166 230,604
------------- -------------
Oil and gas properties (full cost method, of which $165,655 at June 30,
2002 and $149,742 at December 31, 2001 were excluded from
amortization)......................................................... 2,602,837 2,443,615
Less-accumulated depreciation, depletion and amortization.................. (1,183,091) (1,035,036)
------------- -------------
1,419,746 1,408,579
------------- -------------
Furniture, fixtures and equipment, net..................................... 6,868 6,807
Commodity derivatives...................................................... 743 7,409
Other assets............................................................... 9,396 9,972
------------- -------------
Total assets...................................................... $ 1,606,919 $ 1,663,371
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable...................................................... $ 9,235 $ 9,172
Accrued liabilities................................................... 133,869 122,214
Advances from joint owners............................................ 2,297 10
Commodity derivatives................................................. 8,133 4,217
Deferred taxes........................................................ 3,137 29,418
------------- -------------
Total current liabilities......................................... 156,671 165,031
------------- -------------
Other liabilities.......................................................... 8,959 6,288
Commodity derivatives...................................................... 3,119 1,813
Long-term debt............................................................. 375,653 428,631
Deferred taxes............................................................. 205,472 207,880
------------- -------------
Total long-term liabilities....................................... 593,203 644,612
------------- -------------
Company-obligated, mandatorily redeemable, convertible preferred
securities of Newfield Financial Trust I.............................. 143,750 143,750
------------- -------------
Commitments and contingencies
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000 shares authorized,
no shares issued)................................................ -- --
Common stock ($0.01 par value, 100,000,000 shares authorized;
45,278,462 and 44,962,277 shares issued at June 30, 2002 and
December 31, 2001, respectively)................................. 453 449
Additional paid-in capital................................................. 372,242 364,734
Treasury stock (at cost, 870,552 and 860,755 shares at June 30, 2002
and December 31, 2001, respectively).................................. (26,130) (25,794)
Unearned compensation...................................................... (7,659) (7,845)
Accumulated other comprehensive income (loss)
Foreign currency translation adjustment............................... (4,056) (8,918)
Commodity derivatives................................................. (16,567) 24,936
Retained earnings.......................................................... 395,012 362,416
------------- -------------
Total stockholders' equity........................................ 713,295 709,978
------------- -------------
Total liabilities and stockholders' equity........................ $ 1,606,919 $ 1,663,371
============= =============
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 Six Months Ended
June 30, June 30,
-------------------- --------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Oil and gas revenues.............................................. $ 161,611 $ 200,747 $ 309,650 $ 410,073
--------- --------- --------- ---------
Operating expenses:
Lease operating.............................................. 25,706 22,750 48,759 43,574
Production and other taxes................................... 3,861 5,463 7,271 12,581
Transportation............................................... 1,316 1,563 2,647 2,825
Depreciation, depletion and amortization..................... 78,027 71,577 149,234 132,723
General and administrative (includes non-cash stock
compensation of $757 and $703 for the three months ended
June 30, 2002 and 2001, respectively, and $1,335 and
$1,298 for the six months ended June 30, 2002 and 2001,
respectively).............................................. 12,963 11,939 25,308 23,224
--------- --------- --------- ---------
Total operating expenses................................... 121,873 113,292 233,219 214,927
--------- --------- --------- ---------
Income from operations............................................ 39,738 87,455 76,431 195,146
Other income (expenses):
Interest expense............................................. (7,134) (6,641) (14,348) (13,623)
Capitalized interest......................................... 2,130 2,824 4,273 4,154
Dividends on convertible preferred securities of Newfield
Financial Trust I.......................................... (2,336) (2,336) (4,672) (4,672)
Unrealized commodity derivative income (expense)............. (5,880) 5,719 (11,525) 4,161
Other........................................................ (1,247) 529 569 1,142
--------- --------- --------- ---------
(14,467) 95 (25,703) (8,838)
--------- --------- --------- ---------
Income before income taxes........................................ 25,271 87,550 50,728 186,308
Income tax provision (benefit):
Current...................................................... 10,195 9,399 16,422 30,488
Deferred..................................................... (1,194) 21,414 1,710 35,938
--------- --------- --------- ---------
9,001 30,813 18,132 66,426
--------- --------- --------- ---------
Income before cumulative effect of change in accounting
principle....................................................... 16,270 56,737 32,596 119,882
Cumulative effect of change in accounting principle, net of tax
Adoption of SFAS 133............................................ -- -- -- (4,794)
--------- --------- --------- ---------
Net income........................................................ $ 16,270 $ 56,737 $ 32,596 $ 115,088
========= ========= ========= =========
Earnings per share
Basic-
Income before cumulative effect of change in accounting
principle................................................ $ 0.37 $ 1.27 $ 0.74 $ 2.70
Cumulative effect of change in accounting principle........ -- -- -- (0.11)
--------- --------- --------- ---------
Net income................................................. $ 0.37 $ 1.27 $ 0.74 $ 2.59
========= ========= ========= =========
Diluted-
Income before cumulative effect of change in accounting
principle................................................ $ 0.36 $ 1.18 $ 0.73 $ 2.50
Cumulative effect of change in accounting principle........ -- -- -- (0.09)
--------- --------- --------- ---------
Net income................................................. $ 0.36 $ 1.18 $ 0.73 $ 2.41
========= ========= ========= =========
Weighted average number of shares outstanding for basic earnings
per share.................................................... 44,376 44,651 44,295 44,387
========= ========= ========= =========
Weighted average number of shares outstanding for diluted earnings
per share.................................................... 48,928 49,314 48,838 49,098
========= ========= ========= =========
The accompanying notes to consolidated financial statements are an integral
part of this financial statement.
2
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended
June 30,
------------------------
2002 2001
----------- ---------
Cash flows from operating activities:
Net income.............................................................. $ 32,596 $ 115,088
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization................................ 149,234 132,723
Deferred taxes.......................................................... 1,710 35,938
Stock compensation...................................................... 1,335 1,298
Unrealized commodity derivative......................................... 11,525 (4,161)
Cumulative effect of change in accounting principle..................... -- 4,794
----------- -----------
196,400 285,680
Changes in assets and liabilities:
Decrease (increase) in accounts receivable - oil and gas................ (27,919) 62,412
Decrease (increase) in inventories...................................... 1,239 (2,714)
Decrease (increase) in other current assets............................. 3,301 (6,295)
Decrease (increase) in other assets..................................... 577 (3,706)
Increase in accounts payable and accrued liabilities.................... 17,945 12,969
Increase in advances from joint owners.................................. 2,288 394
Increase in other liabilities........................................... 2,597 3,802
----------- -----------
Net cash provided by operating activities............................. 196,428 352,542
----------- -----------
Cash flows from investing activities:
Acquisition, net of cash acquired....................................... -- (264,089)
Additions to oil and gas properties..................................... (164,983) (255,838)
Additions to furniture, fixtures and equipment.......................... (1,557) (2,036)
----------- -----------
Net cash used in investing activities................................. (166,540) (521,963)
----------- -----------
Cash flows from financing activities:
Proceeds from borrowings................................................ 261,000 852,000
Repayments of borrowings................................................ (314,000) (809,000)
Proceeds from issuance of senior notes.................................. -- 174,879
Proceeds from issuance of common stock.................................. 4,829 1,353
Purchases of treasury stock............................................. (336) (17,036)
----------- -----------
Net cash provided by (used in) financing activities................... (48,507) 202,196
----------- -----------
Effect of exchange rate changes on cash and cash equivalents................. (334) 563
----------- -----------
Increase (decrease) in cash and cash equivalents............................. (18,953) 33,338
Cash and cash equivalents, beginning of period............................... 26,610 18,451
----------- -----------
Cash and cash equivalents, end of period..................................... $ 7,657 $ 51,789
=========== ===========
The accompanying notes to consolidated financial statements are an integral
part of this financial statement.
3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In thousands, except share data)
(Unaudited)
Accumulated
Common Stock Treasury Stock Additional Other Total
------------------- ------------------- Paid-in Unearned Retained Comprehensive Stockholders'
Shares Amount Shares Amount Capital Compensation Earnings Income (Loss) Equity
---------- -------- -------- --------- --------- ------------ --------- -------------- -------------
Balance, December 31, 2001.. 44,962,277 $ 449 (860,755) $ (25,794) $ 364,734 $ (7,845) $ 362,416 $ 16,018 $ 709,978
Issuance of common stock.. 281,389 4 4,825 4,829
Issuance of restricted
stock, less amortization
of $190................ 34,796 1,149 (959) 190
Treasury stock, at cost... (9,797) (336) (336)
Amortization of stock
compensation........... 1,145 1,145
Tax benefit from exercise
of stock options........ 1,534 1,534
Comprehensive Income:
Net income................ 32,596 32,596
Foreign currency translation
adjustment, net of tax
of $2,618.............. 4,862 4,862
Reclassification adjustments
for settled contracts,
net of tax of $8,032... (14,916) (14,916)
Changes in fair value of
outstanding hedging
positions, net of tax
of $14,316............. (26,587) (26,587)
---------
Total comprehensive
loss................ (4,045)
---------- ----- -------- --------- --------- -------- --------- --------- ---------
Balance, June 30, 2002...... 45,278,462 $ 453 (870,552) $ (26,130) $ 372,242 $ (7,659) $ 395,012 $ (20,623) $ 713,295
========== ===== ======== ========= ========= ======== ========= ========= =========
The accompanying notes to consolidated financial statements are an integral
part of this financial statement.
4
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
ORGANIZATION AND PRINCIPLES OF CONSOLIDATION
These financial statements include the accounts of Newfield Exploration
Company, a Delaware corporation, and its subsidiaries (collectively, the
"Company"). All significant intercompany balances and transactions have been
eliminated. The unaudited consolidated financial statements of the Company
reflect, in the opinion of management, all adjustments, consisting only of
normal and recurring adjustments, necessary to present fairly the Company's
consolidated financial position as of, and results of operations for, the
periods presented. The consolidated financial statements have been prepared in
accordance with the instructions to Form 10-Q and therefore do not include all
disclosures required for financial statements prepared in conformity with
generally accepted accounting principles. Interim period results are not
necessarily indicative of results of operations or cash flows for a full year.
These consolidated financial statements and the notes thereto should be
read in conjunction with the Company's consolidated financial statements and the
notes thereto for the year ended December 31, 2001 included in the Company's
Annual Report on Form 10-K.
DEPENDANCE ON OIL AND GAS PRICES
As an independent oil and gas producer, the Company's revenue,
profitability and future rate of growth are substantially dependent upon
prevailing prices for natural gas, oil and condensate, which are dependent upon
numerous factors beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of energy. The energy
markets have historically been very volatile, and there can be no assurance that
oil and gas prices will not be subject to wide fluctuations in the future. A
substantial or extended decline in oil and gas prices could have a material
adverse effect on the Company's financial position, results of operations, cash
flows and access to capital and on the quantities of oil and gas reserves that
may be economically produced.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates. The
Company's most significant financial estimates are based on remaining proved oil
and gas reserves.
5
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(Unaudited)
NEW ACCOUNTING STANDARDS
The FASB recently issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement changes the method of accruing for costs associated
with the retirement of fixed assets (e.g., oil & gas production facilities,
etc.) that an entity is legally obligated to incur. This statement will require
that the fair value of the obligation be recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made, and that the
associated asset retirement costs be capitalized as part of the carrying amount
of the asset. The Company plans to implement this standard on January 1, 2003.
The Company is currently assessing the impact of this standard.
EARNINGS PER SHARE
Basic earnings per common share (EPS) is computed by dividing net
income by the weighted average number of common shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
outstanding stock options and convertible securities were exercised for or
converted into common stock.
The following is a calculation of basic and diluted weighted average
shares outstanding for the three and six month periods ended June 30, 2002 and
2001.
Three Month Six Month
Period Ended Period Ended
June 30, June 30,
------------------------ ------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(in thousands, except per share amounts)
Income (numerator):
Income before cumulative effect change
in accounting principle....................... $ 16,270 $ 56,737 $ 32,596 $ 119,882
Cumulative effect change in accounting
principle, net of tax........................ -- -- -- (4,794)
----------- ----------- ----------- -----------
Income - basic.................................... 16,270 56,737 32,596 115,088
After tax dividends on convertible trust
preferred securities......................... 1,518 1,518 3,037 3,037
----------- ----------- ----------- -----------
Income - diluted.................................. $ 17,788 $ 58,255 $ 35,633 $ 118,125
=========== =========== =========== ===========
Shares (denominator):
Shares - basic.................................... 44,376 44,651 44,295 44,387
Dilution effect of stock options outstanding
at end of period.............................. 629 740 620 788
Dilution effect of convertible trust
preferred securities.......................... 3,923 3,923 3,923 3,923
----------- ----------- ----------- -----------
Shares - diluted.................................. 48,928 49,314 48,838 49,098
=========== =========== =========== ===========
Earnings per share:
Basic before change in accounting principle....... $ 0.37 $ 1.27 $ 0.74 $ 2.70
Basic............................................. $ 0.37 $ 1.27 $ 0.74 $ 2.59
Diluted before change in accounting principle..... $ 0.36 $ 1.18 $ 0.73 $ 2.50
Diluted........................................... $ 0.36 $ 1.18 $ 0.73 $ 2.41
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 645,590 and 869,050
shares for the three months ended June 30, 2002 and 2001, respectively, and
707,640 and 657,800 shares for the six months ended June 30, 2002 and 2001,
respectively, because to do so would have been antidilutive.
6
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(Unaudited)
2. PROPERTY ACQUISITIONS:
On January 23, 2001, the Company acquired all of the outstanding
capital stock of Lariat Petroleum, Inc. ("Lariat") by merging Lariat with and
into Newfield Exploration Mid-Continent Inc., a wholly owned subsidiary of the
Company. The total consideration for the acquisition was approximately $333
million, inclusive of the assumption of debt and certain other obligations of
Lariat. The consideration included the issuance of approximately 1.9 million
shares of the Company's common stock valued at $68 million. For financial
accounting purposes, the Company allocated $438 million to oil and gas
properties, which included a $105 million step-up associated with deferred
income taxes.
This acquisition has been accounted for as a purchase and, accordingly,
income and expenses for Lariat have been included in the Company's statement of
income from the date of purchase.
The unaudited pro forma results of operations assuming that such
acquisition had occurred on January 1, 2001 are as follows (in thousands, except
per share amounts):
Six Months
Ended
June 30, 2001
-------------
(unaudited)
Proforma:
Revenue............................................................................. $ 415,715
Income from operations.............................................................. 196,287
Income before cumulative effect of change in accounting
principle........................................................................ 119,664
Cumulative effect of change in accounting principles................................ (4,794)
Net income.......................................................................... 114,870
Basic earnings per common share before cumulative effect
of change in accounting principle................................................ $ 2.70
Basic earnings per common share..................................................... $ 2.59
Diluted earnings per common share before cumulative effect
of change in accounting principle................................................ $ 2.50
Diluted earnings per common share................................................... $ 2.40
The pro forma financial information does not purport to be indicative
of the results of operations that would have occurred had the acquisition taken
place at January 1, 2001 or future results of operations.
7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
3. CONTINGENCIES:
The Company has been named as a defendant in certain lawsuits arising
in the ordinary course of business. While the outcome of these lawsuits cannot
be predicted with certainty, management does not expect that these matters will
have a material adverse effect on the financial position, cash flows or results
of operations of the Company.
8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
4. GEOGRAPHIC INFORMATION:
Other
United States Australia International Total
------------- --------- ------------- ----------
Three Months Ended June 30, 2002
- ----------------------------------------------------------
Oil and gas revenues...................................... $ 154,475 $ 7,136 $ -- $ 161,611
Operating expenses:
Lease operating...................................... 22,832 2,874 -- 25,706
Production and other taxes........................... 3,861 -- -- 3,861
Transportation....................................... 1,316 -- -- 1,316
Depreciation, depletion and amortization............. 76,395 1,632 -- 78,027
Allocated income taxes............................... 17,528 789 --
----------- --------- ---------
Net income from oil and gas operations........... $ 32,543 $ 1,841 $ --
=========== ========= =========
General and administrative........................... 12,963
----------
Total operating expenses......................... 121,873
----------
Income from operations.................................... 39,738
Interest expense and dividends, net of interest
income, capitalized interest and other........... (8,587)
Unrealized commodity derivative expense.............. (5,880)
----------
Income before income taxes................................ $ 25,271
==========
Total long-lived assets................................... $ 1,362,561 $ 22,848 $ 34,337 $1,419,746
=========== ========= ========= ==========
Additions to long-lived assets............................ $ 70,334 $ 8,358 $ 2,123 $ 80,815
=========== ========= ========= ==========
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........................... 11,939
----------
Total operating expenses......................... 113,292
----------
Income from operations.................................... 87,455
Interest expense and dividends, net of interest
income, capitalized interest and other........... (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 asset............................. $ 136,748 $ 1,364 $ 4,650 $ 142,762
=========== ========= ========= ==========
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
Other
United States Australia International Total
------------- --------- ------------- ----------
Six Months Ended June 30, 2002
- ----------------------------------------------------------
Oil and gas revenues...................................... $ 295,948 $ 13,702 $ -- $ 309,650
Operating expenses:
Lease operating...................................... 42,988 5,771 -- 48,759
Production and other taxes........................... 7,271 -- -- 7,271
Transportation....................................... 2,647 -- -- 2,647
Depreciation, depletion and amortization............. 146,028 3,206 -- 149,234
Allocated income taxes............................... 33,955 1,418 --
----------- --------- ---------
Net income from oil and gas operations........... $ 63,059 $ 3,307 $ --
=========== ========= =========
General and administrative........................... 25,308
----------
Total operating expenses......................... 233,319
----------
Income from operations.................................... 76,431
Interest expense and dividends, net of interest
income, capitalized interest and other........... (14,178)
Unrealized commodity derivative expense.............. (11,525)
----------
Income before income taxes................................ $ 50,728
==========
Total long-lived assets................................... $ 1,362,561 $ 22,848 $ 34,337 $1,419,746
=========== ========= ========= ==========
Additions to long-lived assets............................ $ 139,923 $ 15,319 $ 6,149 $ 161,391
=========== ========= ========= ==========
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............. 129,775 2,948 -- 132,723
Allocated income taxes............................... 75,581 728 --
----------- --------- ---------
Net income from oil and gas operations........... $ 140,364 $ 1,697 $ --
=========== ========= =========
General and administrative....................... 23,224
----------
Total operating expenses......................... 214,927
----------
Income from operations.................................... 195,146
Interest expense and dividends, net of interest
income, capitalized interest and other........... (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 asset............................. $ 672,435 $ 1,348 $ 5,107 $ 678,890
=========== ========= ========= ==========
</Table>
10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
5. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
The Company maintains a commodity-price risk management strategy that
utilizes derivative instruments, primarily swaps, collars and floor contracts,
in order to hedge against the variability in cash flows associated with the
forecasted sale of its oil and gas production. While the use of these derivative
instruments limits the downside risk of adverse price movements, they may also
limit future revenues from favorable price movements. The use of derivatives
also involves the risk that the counterparties to such instruments will be
unable to meet the financial terms of such contracts.
With respect to any particular swap transaction, the counterparty is
required to make a payment to the Company if the settlement price for any
settlement period is less than the swap price for such transaction, and the
Company is required to make payment to the counterparty if the settlement price
for any settlement period is greater than the swap price for such transaction.
For any particular collar transaction, the counterparty is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction, and the Company is required to make
payment to the counterparty if the settlement price for any settlement period is
above the ceiling price of such transaction. For any particular floor contract,
the counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price for such transaction.
The Company is not required to make any payment in connection with the
settlement of a floor contract.
As of January 1, 2001, all derivatives are recognized on the balance
sheet at their fair value. Substantially all of the Company's hedging
transactions are settled based upon reported prices on the NYMEX. The estimated
fair value of these transactions is based upon various factors that include
closing exchange prices on the NYMEX, over-the-counter quotations, volatility
and the time value of options. The calculation of the fair value of collars and
floors requires the use of the Black-Scholes option-pricing model. On the date
that the Company enters into a derivative contract, it designates the derivative
as a hedge of the variability in cash flows associated with the forecasted sale
of its oil and gas production. Changes in the fair value of a derivative that is
highly effective and is designated and qualifies as a cash flow hedge, to the
extent that the hedge is effective, are recorded in other comprehensive income
(loss) until earnings are affected by the variability of cash flows of the
hedged transaction (e.g., until the sale of the Company's oil and gas production
is recorded in earnings). Such gains or losses are reported in oil and gas
revenues on the consolidated statement of income.
The Company expects that within the next twelve months it will
reclassify to earnings approximately $15.0 million in after tax losses out of
the net $16.6 million in unrealized after tax losses recorded in accumulated
other comprehensive income (loss) at June 30, 2002.
Any hedge ineffectiveness (which represents the amount by which the
change in the fair value of the derivative differs from the change in the cash
flows of the forecasted sale of production) is recorded in current-period
earnings. On January 1, 2002, the Company began assessing hedge effectiveness
based on the total changes in cash flows on its collar and floor contracts as
described by the Derivative Implementation Group (DIG) Issue G20, "Cash Flow
Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in
a Cash Flow Hedge." Accordingly, prospectively the Company has elected to record
subsequent changes in the fair value, including changes associated with time
value, in accumulated other comprehensive income (loss). Gains or losses on
these collar and floor contracts will be reclassified out of other comprehensive
income (loss) and into earnings when the forecasted sale of production occurs.
For the three and six month periods ended June 30, 2002, the Company recorded
expense of $5.9 million and $11.5 million, respectively, under the income
statement caption "Unrealized commodity derivative expense." These losses are
associated with the settlement of option contracts during the three and six
month periods ended June 30, 2002 and primarily reflect the reversal of time
value gains that were previously recognized on these same open option contracts
during 2001, prior to the adoption of DIG Issue G20.
The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk-management objective and
strategy for undertaking various hedge transactions. This process includes
linking all derivatives that are designated as cash flow hedges to the specific
forecasted sale of oil or gas at its physical location. The Company also
formally assesses (both at the hedge's inception and on an ongoing basis)
whether the derivatives that are used in hedging transactions have been highly
effective in offsetting changes in the cash flows of hedged items and whether
those derivatives may be expected to remain highly effective in future periods.
If it is determined that a derivative is not (or has ceased to be) highly
effective as a hedge, then the Company will discontinue hedge accounting
prospectively. The gain or loss
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
on the derivative will remain in accumulated other comprehensive income (loss)
and will be reclassified into earnings when the forecasted sale of production
affects earnings. The Company records ineffectiveness as a "commodity derivative
expense" line item while the proceeds, net of premiums paid, on the settlement
of derivative financial instruments are recognized in "oil and gas revenues." If
hedge accounting is discontinued and the derivative remains outstanding, the
Company will carry the derivative at its fair value on the balance sheet,
recognizing all subsequent changes in the fair value in current-period earnings.
Hedge accounting was not discontinued during the period for any hedging
instruments.
NATURAL GAS
As of June 30, 2002, the Company had entered into the commodity
derivative instruments set forth in the table below as a cash flow hedge of the
forecasted sale of its U.S. Gulf Coast natural gas production for the remainder
of 2002 and for 2003.
NYMEX Contract Price Per MMBtu
----------------------------------------------------------------------
Collars
----------------------------------------------------------
Floors Ceilings
Swaps -------------------------- -------------------------
Volume in (Weighted Weighted Weighted Fair Value
Period and Type of Contract MMMBtus Average) Range Average Range Average (in millions)
- --------------------------- --------- --------- ------------- -------- -------------- -------- -------------
July 2002 - September 2002
Price Swap Contracts....... 4,250 $3.47 -- -- -- -- $0.7
Collar Contracts........... 20,850 -- $2.50 - $4.00 $3.10 $3.19 - $6.00 $4.07 2.8
October 2002 - December 2002
Price Swap Contracts....... 1,700 3.78 -- -- -- -- 0.5
Collar Contracts........... 3,800 -- 2.75 - 4.00 3.84 4.80 - 6.10 5.07 1.8
January 2003 - March 2003
Price Swap Contracts....... 5,100 3.78 -- -- -- -- (0.6)
Collar Contracts........... 450 -- 3.50 3.50 4.20 4.20 --
April 2003 - June 2003
Price Swap Contracts....... 5,105 3.78 -- -- -- -- 0.2
Collar Contracts........... 1,050 -- 3.50 3.50 3.90 - 4.20 4.03 --
July 2003 - September 2003
Price Swap Contracts....... 2,410 3.51 -- -- -- -- (0.7)
Collar Contracts........... 1,350 -- 3.50 3.50 3.90 - 4.20 4.00 (0.1)
October 2003 - December 2003
Price Swap Contracts....... 2,410 3.51 -- -- -- -- (1.2)
Collar Contracts........... 1,350 -- 3.50 3.50 3.90 - 4.20 4.00 (0.4)
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, 2002.
Weighted Average
Volume in Contract Price Fair Value
Period and Type of Contract MMMBtus Per MMBtu (in millions)
- --------------------------- --------- ---------------- -------------
July 2002 - December 2002
Price Swap Contracts.................... 1,840 $2.61 $(1.3)
January 2003 - March 2003
Price Swap Contracts.................... 900 2.61 (1.0)
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
OIL AND CONDENSATE
As of June 30, 2002, the Company had entered into the commodity
derivative instruments set forth in the table below as a cash flow hedge of the
forecasted sale of its U.S. Gulf Coast oil production for the remainder of 2002
and for 2003.
NYMEX Contract Price Per Bbl
-------------------------------------------------------------------------------
Collars
---------------------------------------------------
Floors Ceilings Floor Contracts
Swaps ---------------------- --------------------------- ---------------
Period and Type Volume in (Weighted Weighted Weighted Weighted Fair Value
of Contract Bbls Average) Range Average Range Average Range Average (in millions)
----------- --------- --------- ------------- -------- ---------------- -------- ------ -------- -------------
July 2002 - September 2002
Price Swap Contracts... 276,000 $24.01 -- -- -- -- -- -- $(0.7)
Collar Contracts....... 713,000 -- $21.00 - $25.00 $22.98 $26.75 - $30.75 $28.74 -- -- (0.2)
Floor Contracts........ 138,000 -- -- -- -- -- $21.15 $21.15 --
October 2002 -
December 2002
Price Swap Contracts... 276,000 24.01 -- -- -- -- -- -- (0.6)
Collar Contracts....... 552,000 -- 21.00 - 25.00 22.83 27.50 - 30.75 29.03 -- -- (0.1)
Floor Contracts........ 138,000 -- -- -- -- -- 21.15 21.15 --
January 2003 - March 2003
Price Swap Contracts... 180,000 24.92 -- -- -- -- -- -- (0.1)
Collar Contracts....... 90,000 -- 20.00 20.00 27.50 27.50 -- -- (0.1)
Floor Contracts........ 135,000 -- -- -- -- -- 21.15 21.15 --
April 2003 - June 2003
Collar Contracts....... 91,000 -- 20.00 20.00 27.50 27.50 -- -- (0.1)
6. EEX ACQUISITION AND RELATED FINANCING:
On May 29, 2002, we announced our agreement to acquire EEX Corporation,
an independent oil and as exploration and production company with activities
focused in Texas, Louisiana and the Gulf of Mexico. The transaction is valued at
approximately $650 million, including the assumption of approximately $400
million of debt. We will issue approximately 7.1 million shares of our common
stock in the transaction, or approximately 12.7% of our outstanding common stock
on a fully diluted basis following the closing of the transaction.
The acquisition is subject to the approval of EEX's common
shareholders and other conditions. All of EEX's preferred shareholders have
signed an irrevocable proxy to vote their share in favor of the transaction. We
expect the transaction to close in late September 2002.
On August 13, 2002, we completed the issuance of $250,000,000 principal
amount of our 8 3/8% Senior Subordinated Notes due 2012 pried with a yield to
maturity of 8.50%. The net proceeds from the offering of approximately $241.8
million will be used to repay EEX debt that will become due at the closing of
the EEX acquisition and to pay a portion of the transaction costs of the
acquisition. Pending their use to finance the acquisition of EEX, the net
proceeds of the notes (before expenses) will be placed in an escrow account to
fund the redemption of the notes if required. If the EEX acquisition does ot
close on or prior to December 31, 2002 or the merger agreement relating to the
acquisition of EEX is terminated or abandoned earlier, the funds in the escrow
account, together with additional funds we will provide, will be used to redeem
all of the notes at a redemption price equal to 101% of their principal amount,
plus accrued and unpaid interest to the date of redemption.
The notes are unsecured senior subordinated debt and rank junior in
right of payment to all of our present and future senior indebtedness. The
indenture governing the notes limits our ability to, among other things, incur
additional debt, make restricted payments, pay dividends on or redeem our
capital stock, make certain investments, create liens, make certain
dispositions of assets, engage in transactions with affiliates and engage in
merger, consolidations and certain sales of assets.
13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas. Prices for oil and gas fluctuate widely. Oil
and gas prices affect:
o the amount of cash flow available for capital expenditures;
o our ability to borrow and raise additional capital;
o the amount of oil and gas that we can economically produce; and
o the accounting for our oil and gas activities.
We use hedging transactions with respect to a portion of our oil and
gas production to achieve more predictable cash flows and to reduce our exposure
to price fluctuations.
Our future success depends on our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. As is generally the
case, our producing properties in the Gulf of Mexico and the onshore Gulf Coast
often have high initial production rates, followed by steep declines. As a
result, we must locate and develop or acquire new oil and gas reserves to
replace those being depleted by production. Substantial capital expenditures are
required to find, develop, acquire and produce oil and gas reserves.
CRITICAL ACCOUNTING POLICIES
Our 2001 annual report describes the accounting policies that we
believe are critical to the reporting of our financial position and operating
results and that require management's most difficult, subjective or complex
judgments. Our most significant estimates are:
o remaining proved oil and gas reserves;
o timing of our future drilling activities;
o future costs to develop and abandon our oil and gas properties; and
o the value of derivative positions.
This report should be read together with the discussion contained in
our 2001 annual report regarding these critical accounting policies.
OTHER FACTORS AFFECTING OUR BUSINESS AND FINANCIAL RESULTS
In addition to the matters discussed above, our business, financial
condition and results of operations are affected by a number of other factors.
This report should be read together with the discussion in our 2001 annual
report regarding these other factors.
14
RESULTS OF OPERATIONS
REVENUES. All of our revenues are derived from the sale of our oil and
gas production and the settlement of hedging contracts associated with our
production. Our revenues may vary significantly from quarter to quarter as a
result of changes in commodity prices. Revenues for the second quarter and six
months ended June 30, 2002 were 19% and 24%, respectively, lower than the
comparable periods of 2001 primarily because of lower natural gas prices.
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- -------------------
2002 2001 2002 2001
--------- --------- -------- --------
PRODUCTION (1):
United States
Natural gas (Bcf)................. 37.9 35.5 71.8 66.3
Oil and condensate (MBbls)........ 1,328.8 1,374.2 2,678.3 2,615.4
Total (Bcfe)...................... 45.8 43.8 87.8 82.0
Australia
Oil and condensate (MBbls)........ 277.5 341.9 575.8 581.4
Total (Bcfe)...................... 1.7 2.1 3.5 3.4
Total
Natural gas (Bcf)................. 37.9 35.5 71.8 66.3
Oil and condensate (MBbls)........ 1,606.2 1,716.1 3,254.0 3,196.8
Total (Bcfe)...................... 47.5 45.8 91.3 85.4
AVERAGE REALIZED PRICES (2):
United States
Natural gas (per Mcf)............. $ 3.21 $ 4.39 $ 3.23 $ 4.94
Oil and condensate (per Bbl)...... 23.84 24.45 22.93 24.56
Australia
Oil and condensate (per Bbl)...... $ 25.72 $ 28.02 $ 23.80 $ 27.30
Total
Natural gas (per Mcf)............. $ 3.21 $ 4.39 $ 3.23 $ 4.94
Oil and condensate (per Bbl)...... 24.17 25.16 23.08 25.06
- ---------------
(1) Represents volumes sold regardless of when produced.
(2) For purposes of this table, average realized prices for natural gas
and oil and condensate are presented net of all applicable
transportation expenses, which reduced the realized price of natural
gas by $0.02 and $0.03 for the three months ended June 30, 2002 and
2001, respectively, and by $0.03 and $0.03 for the six months ended
June 30, 2002 and 2001, respectively. The realized price of oil and
condensate is reduced by $0.29 and $0.30 for the three months ended
June 30, 2002 and 2001, respectively, and by $0.26 and $0.27 for the
six months ended June 30, 2002 and 2001, respectively. Average realized
prices include the effects of hedging. See "Effect of Hedging on
Realized Prices" below.
PRODUCTION. During the first quarter of 2002, we voluntarily curtailed
approximately one Bcfe of production in response to low commodity prices. During
the second quarter of 2002, we resolved several open accounting matters relating
to prior periods, including the calculation of royalties due to the Minerals
Management Service and accounting for production from a recent acquisition. As a
result of the resolution of these matters, we recorded an additional 1.9 Bcf of
gas production and related revenue, depreciation, depletion and amortization
expense and income tax expense in the second quarter. The table above reflects
volumes sold regardless of when the volumes were produced. Primarily because of
the timing of liftings of oil and condensate from our FPSOs and also because of
natural production decline, we experienced a 19% reduction in the volumes sold
in Australia during the second quarter of 2002 as compared to the same quarter
of 2001.
15
EFFECTS OF HEDGING ON REALIZED PRICES. The following table presents
information about the effect of our hedging program on realized prices.
Average
Realized Prices Ratio of
---------------- Hedged to
With Without Non-Hedged
Hedge Hedge Price (1)
------- ------- ------------
Natural Gas
Three months ended June 30, 2002............... $3.21 $3.22 99.7%
Three months ended June 30, 2001............... $4.39 $4.59 95.6%
Six months ended June 30, 2002................. $3.23 $2.78 116.2%
Six months ended June 30, 2001................. $4.94 $5.72 86.3%
Crude Oil and Condensate
Three months ended June 30, 2002............... $24.17 $24.60 98.3%
Three months ended June 30, 2001............... $25.16 $26.10 96.3%
Six months ended June 30, 2002................. $23.08 $22.60 102.1%
Six months ended June 30, 2001................. $25.06 $22.62 110.8%
- -------------
(1) The ratio is determined by dividing the realized price (which includes the
effects of hedging) by the price that otherwise would have been realized without
hedging activities.
OPERATING EXPENSES. The following table presents information about our
operating expenses for the three months ended June 30, 2002 and 2001.
Unit of Production (Per Mcfe) Amount (in thousands)
--------------------------------- ---------------------------------
Three Months Ended Three Months Ended
June 30, Percentage June 30, Percentage
------------------ Increase ------------------ Increase
2002 2001 (Decrease) 2002 2001 (Decrease)
------ ------ ----------- -------- -------- ----------
United States:
Lease operating .............................. $ 0.50 $ 0.42 19% $ 22,832 $ 18,508 23%
Production and other taxes ................... 0.08 0.10 (20)% 3,861 4,415 (13)%
Transportation ............................... 0.03 0.04 (25)% 1,316 1,563 (16)%
Depreciation, depletion and amortization ..... 1.67 1.59 5% 76,395 69,783 9%
General and administrative (exclusive of
stock compensation) ...................... 0.26 0.25 4% 11,808 11,051 7%
Total operating .......................... 2.54 2.41 5% 116,212 105,320 10%
Australia:
Lease operating .............................. $ 1.73 $ 2.07 (16)% $ 2,874 $ 4,242 (32)%
Production and other taxes ................... -- 0.51 (100)% -- 1,048 (100)%
Transportation ............................... -- -- -- -- -- --
Depreciation, depletion and amortization ..... 0.98 0.87 13% 1,632 1,794 (9)%
General and administrative (exclusive
of stock compensation) ................... 0.24 0.09 167% 398 185 115%
Total operating .......................... 2.95 3.54 (17)% 4,904 7,269 (33)%
Total:
Lease operating .............................. $ 0.54 $ 0.50 8% $ 25,706 $ 22,750 13%
Production and other taxes ................... 0.08 0.12 (33)% 3,861 5,463 (29)%
Transportation ............................... 0.03 0.03 -- 1,316 1,563 (16)%
Depreciation, depletion and amortization ..... 1.64 1.56 5% 78,027 71,577 9%
General and administrative (exclusive
of stock compensation) ................... 0.26 0.25 4% 12,206 11,236 9%
Total operating .......................... 2.55 2.46 4% 121,116 112,589 8%
16
The following table presents information about our operating expenses
for the six months ended June 30, 2002 and 2001.
Unit of Production Amount
(Per Mcfe) (in thousands)
------------------------------- ------------------------------------
Six Months Ended Six Months Ended
June 30, Percentage June 30, Percentage
------------------ Increase --------------------- Increase
2002 2001 (Decrease) 2002 2001 (Decrease)
------- ------- ---------- -------- --------- ----------
United States:
Lease operating .............. $ 0.49 $ 0.45 8% $ 42,988 $ 36,793 17%
Production and other taxes ... 0.08 0.11 (27)% 7,271 8,860 (18)%
Transportation ............... 0.03 0.03 -- 2,647 2,825 (6)%
Depreciation, depletion
and amortization ......... 1.66 1.58 5% 146,028 129,775 13%
General and administrative
(exclusive of stock
compensation) ............ 0.26 0.26 -- 23,044 21,492 7%
Total operating .......... 2.53 2.44 4% 221,978 199,745 11%
Australia:
Lease operating .............. $ 1.67 $ 1.94 (14)% $ 5,771 $ 6,781 (15)%
Production and other taxes ... -- 1.07 (100)% -- 3,721 (100)%
Transportation ............... -- -- -- -- -- --
Depreciation, depletion
and amortization ......... 0.93 0.85 9% 3,206 2,948 9%
General and administrative
(exclusive of stock
compensation) ............ 0.27 0.12 125% 929 434 114%
Total operating .......... 2.87 3.98 (28)% 9,906 13,884 (29)%
Total:
Lease operating .............. $ 0.53 $ 0.51 4% $ 48,759 $ 43,574 12%
Production and other taxes ... 0.08 0.15 (47)% 7,271 12,581 (42)%
Transportation ............... 0.03 0.03 -- 2,647 2,825 (6)%
Depreciation, depletion
and amortization ......... 1.63 1.55 5% 149,234 132,723 12%
General and administrative
(exclusive of stock
compensation) ............ 0.26 0.26 -- 23,973 21,926 9%
Total operating ......... 2.54 2.50 2% 231,884 213,629 9%
o Domestic lease operating expense increased in the second quarter
and the first half of 2002 as a result of several non-routine
repairs to gathering lines and other offshore facilities related
to our Gulf of Mexico operations, and a slight increase in well
service costs in the Mid-Continent.
o Non-routine maintenance on our FPSOs in 2001 resulted in higher
Australian lease operating expense during the second quarter and
the first half of 2001.
o The decrease in domestic production and other taxes resulted from
lower natural gas prices in the second quarter and the first half
of 2002.
o Australian capital expenditures offset production taxes otherwise
payable. As a result of capital expenditures during the twelve
months ended June 30, 2002, no Australian production taxes were
recorded in the first half of 2002.
o The increase in the domestic DD&A during the second quarter and the
first half of 2002 is primarily related to the increased cost of
reserve additions arising from both the quantity of proved reserves
added and increases in the cost of drilling goods and services and
platform and facilities construction. The increase is partially
offset by our fourth quarter 2001 non-cash ceiling test writedown.
o The increase in the Australian DD&A rate during the second quarter
and the first half of 2002 is primarily a result of our unsuccessful
exploratory drilling efforts in 2002 and 2001.
o The significant increase in per unit Australian general and
administrative expense relates to costs incurred in connection with
the relocation of the previous manager of our Australian operations
to our Tulsa, Oklahoma office and the relocation of the current
manager of our Australian operations from Houston to Perth,
Australia and decreased production volumes.
17
INTEREST EXPENSE. We incurred interest expense on our $125 million
principal amount 7.45% Senior Notes due 2007, our $175 million principal amount
7 5/8% Senior Notes due 2011 and on borrowings under our reserve-based revolving
credit facility and money market credit lines. Outstanding borrowings under our
credit arrangements may vary significantly from period to period. Distributions
are paid on our 6.5% convertible trust preferred securities issued in August
1999. We capitalize a portion of our interest expense each quarter based upon
our unproved property balance. This amount may vary significantly from period to
period based upon the timing and size of acquisitions and the evaluation of
unproved properties.
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2002 2001 2002 2001
------ ------ ------ ------
(in millions) (in millions)
Gross interest expense ................... $ 7.1 $ 6.7 $14.3 $13.6
Capitalized interest ..................... (2.1) (2.8) (4.3) (4.2)
----- ----- ----- -----
Net interest expense ..................... 5.0 3.9 10.0 9.4
Distributions on preferred securities .... 2.3 2.3 4.7 4.7
----- ----- ----- -----
Total interest expense and distributions . $ 7.3 $ 6.2 $14.7 $14.1
===== ===== ===== =====
UNREALIZED COMMODITY DERIVATIVE EXPENSE. We recorded $5.9 million of
expense and $5.7 million of income for the three months ended June 30, 2002 and
2001, respectively, and $11.5 million of expense and $4.2 million of income for
the six months ended June 30, 2002 and 2001, respectively. The gains in 2001
primarily reflect the change in the time value of open hedging contracts. The
losses in 2002 are associated with the settlement of those same hedging
contracts and primarily reflect the reversal of the time value gains that were
previously recognized during 2001.
OTHER. During the second quarter of 2002, we recognized $2.6 million of
currency losses associated with transactions by our Australian operations in
U.S. dollars that more than offset all other interest income during the period.
During the first six months of 2002, we reversed accruals of certain
contingencies of $2.2 million related to our 1999 acquisition of Gulf Australia
that were resolved favorably in 2002. This gain was substantially offset by
currency losses associated with transactions by our Australian operations in
U.S. dollars.
TAXES. The effective tax rate for both the three and six month periods
ended June 30, 2002 was 36%, as compared to 35% and 36%, respectively, for the
comparable periods of 2001. Estimates of future taxable income can be
significantly affected by changes in oil and natural gas prices, estimates of
the timing and amount of future production and estimates of future operating and
capital costs.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. Our working capital balance is not a good indicator of
our liquidity because it fluctuates as a result of the timing and amount of
borrowings or repayments under our credit arrangements. We had working capital
of $13.5 million as of June 30, 2002. This compares to $65.6 million as of
December 31, 2001. Historically, we have funded our oil and gas activities
through cash flow from operations, equity capital, public debt and bank
borrowings.
CASH FLOW FROM OPERATIONS. Our net cash flow from operations for the
six months ended June 30, 2002 decreased 44%, from $352.5 million for the
comparable period of 2001 to $196.4 million. Net cash flow from operations
before changes in operating assets and liabilities for the six months ended June
30, 2002 was $196.4 million compared to $285.6 million for the same period of
2001. These decreases are primarily attributable to lower natural gas prices and
a higher portion of current cash taxes paid.
CASH FLOW FROM FINANCING ACTIVITIES. Pursuant to our equity shelf
program, in March 2002, we sold 20,800 shares of our common stock for net
proceeds (before expenses other than commissions to our sales agent) of
approximately $750,000. An additional $4.1 million of proceeds were received
from the exercise of stock options during 2002. The net proceeds were used for
general corporate purposes. We may sell additional shares under this program
from time to time in the future.
DEBT. At June 30, 2002, we had $69 million outstanding under our credit
facility and an additional $7 million outstanding under our money market lines
of credit with various banks. At June 30, 2002, our long-term debt was $376
million, which includes the above amounts and $125 million of our 7.45% Senior
Notes due 2007 and $175 million of our 7 5/8% Senior Notes due 2011.
18
The amount available under our credit facility is subject to a
calculated borrowing base determined by banks holding 75% of the aggregate
commitments. The borrowing base is reduced by the aggregate outstanding
principal amount of our senior notes ($300 million). The borrowing base is
currently $525 million and is redetermined at least semi-annually. No assurances
can be given that the banks will not elect to reduce the borrowing base in the
future. The facility contains restrictions on the payment of dividends and the
incurrence of debt as well as other customary covenants and restrictions. The
facility matures on January 23, 2004. As of August 14, 2002 we had $179 million
available under our credit facility and had outstanding borrowings of $46
million.
We also have money market lines of credit with various banks in an
amount limited by the credit facility to $40 million. As of August 14, 2002, we
had $15 million of outstanding borrowings under these lines of credit.
Our credit arrangements are not subject to any debt rating or similar
triggers or conditions. However, applicable commitment fees and interest rates
under our credit facility vary based on our senior unsecured credit rating.
CAPITAL EXPENDITURES. In the first six months of 2002, our capital
spending totaled $161 million. We invested $7 million for proved property
acquisitions, $64 million in development, $69 million in domestic exploration
and $21 million internationally.
We budgeted $360 million for capital spending in 2002. Approximately
$30 million has been budgeted for proved property acquisitions, $170 million for
development, $135 million for domestic exploration and $25 million for
international projects. The 2002 exploratory budget is the largest in our
history. Acquisitions are opportunistic and are not budgeted under our capital
program unless specifically identified at the time the budget is prepared. We
continue to pursue attractive acquisition opportunities; however, the timing,
size and purchase price of acquisitions are unpredictable. We anticipate that
our capital expenditure program for 2002 (exclusive of acquisitions not included
in the initial budget) will be funded principally from cash flow from operations
and working capital.
Our annual capital budget is established at the beginning
of each year. Because of the nature of the properties we own, only a small
portion of our capital budget is nondiscretionary. The size of our budget is
driven by expected cash flow from operations. Actual levels of capital
expenditures may vary significantly due to many factors, including drilling
results, oil and gas prices, industry conditions, the prices and availability of
goods and services and the extent to which proved properties are acquired.
EEX ACQUISITION AND RELATED FINANCING
On May 29, 2002, we announced our agreement to acquire EEX Corporation,
an independent oil and gas exploration and production company with activities
focused in Texas, Louisiana and the Gulf of Mexico. The transaction is valued at
approximately $650 million, including the assumption of approximately $400
million of debt. We will issue approximately 7.1 million shares of our common
stock in the transaction, or approximately 12.7% of our outstanding common stock
on a fully diluted basis following the closing of the transaction.
The assets and operations of EEX are complementary to ours. EEX's
onshore properties are located in our core South Texas focus area, and the
acquisition will make us one of the largest independent producers in this area.
The acquisition also will provide us with increased balance between our onshore
and offshore assets. In addition, EEX's acreage position and interests in
undeveloped discoveries in the Gulf of Mexico will further our efforts to
establish operations in the deepwater. We expect to reduce EEX's current general
and administrative expense by as much as 50%.
The acquisition is subject to the approval of EEX's common shareholders
and other conditions. All of EEX's preferred shareholders have signed an
irrevocable proxy to vote their shares in favor of the transaction. We expect
the transaction to close in late September 2002.
On August 13, 2002, we completed the issuance of $250,000,000 principal
amount of our 8 3/8% Senior Subordinated Notes due 2012 priced with a yield to
maturity of 8.50%. The net proceeds from the offering of approximately $241.8
million will be used to repay EEX debt that will become due at the closing of
the EEX acquisition and to pay a portion of the transaction costs of the
acquisition. Pending their use to finance the acquisition of EEX, the net
proceeds of the notes (before expenses) will be placed in an escrow account to
fund the redemption of the notes if required. If the EEX acquisition does not
close on or prior to December 31, 2002 or the merger agreement relating to the
acquisition of EEX is terminated or abandoned earlier, the funds in the escrow
account, together with additional funds we will provide, will be used to redeem
all of the notes at a redemption price equal to 101% of their principal amount,
plus accrued and unpaid interest to the date of redemption.
19
The notes are unsecured senior subordinated debt and rank junior in
right of payment to all of our present and future senior indebtedness. The
indenture governing the notes limits our ability to, among other things, incur
additional debt, make restricted payments, pay dividends on or redeem our
capital stock, make certain investments, create liens, make certain dispositions
of assets, engage in transactions with affiliates and engage in merger,
consolidations and certain sales of assets.
EEX currently has outstanding $100.8 of notes that are secured by EEX's
interest in certain pipelines and a combination deepwater drilling
rig/processing facility located in the Gulf of Mexico. We intend to sell these
assets after the closing of the transaction. Pending their sale, the secured
notes will remain outstanding. We will finance other EEX obligations and
remaining transaction costs with borrowings under our existing revolving credit
facility. The lenders under our credit facility have agreed that our borrowing
base will increase to $735 million upon consummation of the acquisition. The
borrowing base will be reduced by 100% of the principal amount of our senior
notes ($300 million) and EEX's secured notes and a portion of the principal
amount of our senior subordinated notes (the banks under our credit facility
have agreed to a reduction equal to 30% of the principal amount). Immediately
following the acquisition of EEX, we will have approximately $185 million of
borrowings under our credit facility and money market lines of credit and
remaining borrowing capacity of approximately $115 million. Upon the sale of the
assets securing EEX's notes, the borrowing base will be reduced by $30 million
and the notes must be repaid. To the extent that we receive less than $30
million of proceeds for these assets, our available borrowing capacity will be
reduced.
HEDGING
We enter into various commodity price hedging contracts with respect to
a portion of our anticipated future natural gas and crude oil production. While
the use of these hedging arrangements limits the downside risk of adverse price
movements, they may also limit future revenues from favorable price movements.
The use of hedging transactions also involves the risk that the counterparties
will be unable to meet the financial terms of such transactions. Such contracts
are accounted for as derivatives in accordance with SFAS No. 133.
Please see the discussion and tables in Note 5, "Commodity Derivative
Instruments and Hedging Activities," to our consolidated financial statements
appearing earlier in this report for a description of our hedging contracts as
of June 30, 2002 and the fair value of those contracts as of that date.
Since June 30, 2002, we have entered into the additional natural gas
price hedging contracts with respect to our Gulf Coast natural gas production
set forth in the table below. We continue to evaluate additional hedging
transactions for the remainder of 2002 and future years.
NYMEX Contract Price Per MMBtu
------------------------------------------------------------------------------
Collars
-------------------------------------------------------
Floors Ceilings Floor Contracts
--------------------------- -------------------------- ----------------------
Period and Type Volume in Weighted Weighted Weighted
of Contract MMMBtus Range Average Range Average Range Average
- ---------------- ---------- --------------- ------------ ------------ ---------- ----------- ---------
July 2002 - September 2002
Floor Contracts ........... 4,500 -- -- -- -- $3.15 - $3.18 $3.16
October 2002 - December 2002
Collar Contracts .......... 1,800 $2.65 - $3.25 $2.97 $3.73 - $4.25 $3.96 -- --
Floor Contracts ........... 600 -- -- -- -- 2.88 2.88
20
Since June 30, 2002, we have also entered into the additional oil and
condensate price hedging contracts with respect to our Gulf Coast oil
production set forth in the table below. We continue to evaluate additional
hedging transactions for the remainder of 2002 and future years.
NYMEX Contract Price Per Bbl
-------------------------------------------------------------------
Collars
------------------------------------------------------
Floors Ceilings
Swaps ----------------------- ---------------------------
Volume in (Weighted Weighted Weighted
Period and Type of Contract Bbls Average) Range Average Range Average
- --------------------------- --------- --------- --------- -------- -------------- --------
January 2003 - March 2003
Swaps....................... 60,000 $ 25.25 -- -- -- --
Collars..................... 60,000 -- $ 22.00 $ 22.00 $28.25 $ 28.25
April 2003 - June 2003
Swaps....................... 60,000 25.25 -- -- -- --
Collars..................... 240,000 -- 22.00 22.00 27.25 - 28.25 27.72
July 2003 - September 2003
Swaps....................... 40,000 25.25 -- -- -- --
Collars..................... 160,000 -- 22.00 22.00 27.25 - 28.25 27.72
Substantially all of our hedging transactions are settled based upon
reported settlement prices on the NYMEX. We believe there is no material basis
risk with respect to our natural gas price hedging contracts because
substantially all our Gulf Coast natural gas production is sold under spot
contracts that have historically correlated to the settlement price, and because
all of the hedging contracts assumed from Lariat are settled against the same
pipelines into which our production in Oklahoma is sold. In addition, because
substantially all of our U.S. Gulf Coast oil production is sold under spot
contracts that have historically correlated to the NYMEX West Texas Intermediate
price, we believe that we have no material basis risk with respect to our oil
price hedging contracts.
NEW ACCOUNTING STANDARDS
The FASB recently issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement changes the method of accruing for costs associated
with the retirement of fixed assets (e.g., oil & gas production facilities,
etc.) that an entity is legally obligated to incur. It will require that the
fair value of the obligation be recognized in the period in which it is incurred
if a reasonable estimate of fair value can be made, and that the associated
asset retirement costs be capitalized as part of the carrying amount of the
asset. We plan to implement this standard on January 1, 2003. We are
currently assessing the impact of this standard.
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 email, please forward your email address to
pmcknight@newfld.com or visit our web page and sign up.
FORWARD-LOOKING INFORMATION
This report contains information that is forward-looking or relates to
anticipated future events or results such as planned capital expenditures, the
availability of capital resources to fund capital expenditures, our financial
position and expected reductions in EEX's general and administrative expense.
Although we believe that the expectations reflected in this information are
reasonable, this information is based upon assumptions and anticipated results
that are subject to numerous uncertainties. Actual results may vary
significantly from those anticipated due to many factors, including drilling
results, oil and gas prices, industry conditions, the prices of goods and
services, the availability of drilling rigs and other support services and the
availability of capital resources.
21
COMMONLY USED OIL AND GAS TERMS
Below are explanations of some commonly used terms in the oil and gas
business.
Basis risk. The risk associated with the sales point price for oil or gas
production varying from the reference (or settlement) price for
a particular hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of
crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined by using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees to
59.5 degrees Fahrenheit.
FPSO. A floating production, storage and off-loading vessel, commonly
used overseas to produce oil locations where pipeline
infrastructure may not exist.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMMBtu. One billion Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
NYMEX. The New York Mercantile Exchange.
22
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the May 2, 2002 Annual Meeting of Stockholders, our stockholders
voted on three matters. As of the March 5, 2002 record date, 44,275,828 shares
of common stock were outstanding and entitled to vote at the meeting.
(1) Election of Eleven Directors:
Our stockholders elected the eleven nominees for director until
the next annual meeting by the following vote:
NOMINEE ELECTED FOR WITHHELD
--------------- --- --------
Joe B. Foster 29,309,303 6,272,705
David A. Trice 29,551,708 6,030,300
David F. Schaible 29,549,700 6,032,308
Charles W. Duncan, Jr. 35,017,683 564,325
Howard H. Newman 34,700,994 881,014
Thomas G. Ricks 34,806,983 775,025
C.E. (Chuck) Shultz 34,808,948 773,060
Terry Huffington 34,701,119 880,889
Dennis R. Hendrix 34,808,453 773,555
Philip J. Burguieres 34,807,903 774,105
Claire S. Farley 34,807,154 774,854
(2) Approval of Amendment and Restatement of the Newfield
Exploration Company 2000 Omnibus Stock Plan:
The stockholders approved the amendment and restatement of the
Newfield Exploration Company 2000 Omnibus Stock Plan by the following
vote:
ABSTENTIONS AND
FOR AGAINST BROKER NON-VOTES
--- --------- ----------------
27,062,043 5,634,241 66,365
(3) Appointment of Independent Public Accountants:
The stockholders ratified the appointment of
PricewaterhouseCoopers LLP as our independent auditors for 2002 by the
following vote:
ABSTENTIONS AND
FOR AGAINST BROKER NON-VOTES
--- ---------- ----------------
34,549,219 1,218,231 30,327
23
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
None
(b) Reports on Form 8-K:
On April 25, 2002, we filed a Current Report on Form 8-K announcing
our financial and operating results for the first quarter of 2002.
On May 30, 2002, we filed a Current Report on Form 8-K announcing our
agreement and plan of merger with EEX Corporation.
24
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 14, 2002 By: /s/ TERRY W. RATHERT
------------------------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)
25