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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 APRIL 30, 2002, THERE WERE 44,350,201 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 March 31, 2002 and December 31, 2001............ 1
Consolidated Statement of Income for the three months
ended March 31, 2002 and 2001.................................................... 2
Consolidated Statement of Cash Flows for the three months ended
March 31, 2002 and 2001.......................................................... 3
Consolidated Statement of Stockholders' Equity for the three
months ended March 31, 2002...................................................... 4
Notes to Consolidated Financial Statements....................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................................ 13
PART II
Item 6. Exhibits and Reports on Form 8-K.................................................... 20
-ii-
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
March 31, December 31,
2002 2001
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents..................................................... $ 25,128 $ 26,610
Accounts receivable-oil and gas............................................... 87,580 92,644
Inventories................................................................... 8,125 7,332
Commodity derivatives......................................................... 24,678 79,012
Other current assets.......................................................... 26,392 25,006
------------- -------------
Total current assets...................................................... 171,903 230,604
------------- -------------
Oil and gas properties (full cost method, of which $174,194 at March 31, 2002
and $149,742 at December 31, 2001 were excluded from amortization)............ 2,524,191 2,443,615
Less-accumulated depreciation, depletion and amortization.......................... (1,106,436) (1,035,036)
-------------- --------------
1,417,755 1,408,579
------------- -------------
Furniture, fixtures and equipment, net............................................. 6,896 6,807
Commodity derivatives.............................................................. 1,784 7,409
Other assets....................................................................... 9,684 9,972
------------- -------------
Total assets.............................................................. $ 1,608,022 $ 1,663,371
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.............................................................. $ 6,156 $ 9,172
Accrued liabilities........................................................... 118,106 122,214
Advances from joint owners.................................................... 10 10
Commodity derivatives......................................................... 21,692 4,217
Deferred taxes................................................................ 3,763 29,418
------------- -------------
Total current liabilities................................................. 149,727 165,031
------------- -------------
Other liabilities.................................................................. 5,918 6,288
Commodity derivatives.............................................................. 2,360 1,813
Long-term debt..................................................................... 410,642 428,631
Deferred taxes..................................................................... 207,349 207,880
------------- -------------
Total long-term liabilities............................................... 626,269 644,612
------------- -------------
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; 45,215,537
and 44,962,277 shares issued at March 31, 2002 and December 31,
2001, respectively)....................................................... 451 449
Additional paid-in capital......................................................... 370,544 364,734
Treasury stock (at cost, 867,936 and 860,755 shares at March 31, 2002
and December 31, 2001, respectively).......................................... (26,012) (25,794)
Unearned compensation.............................................................. (8,176) (7,845)
Accumulated other comprehensive income (loss) -
Foreign currency translation adjustment....................................... (7,160) (8,918)
Commodity derivatives......................................................... (20,113) 24,936
Retained earnings.................................................................. 378,742 362,416
------------- -------------
Total stockholders' equity................................................ 688,276 709,978
------------- -------------
Total liabilities and stockholders' equity................................ $ 1,608,022 $ 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
March 31,
-------------------
2002 2001
--------- --------
Oil and gas revenues...................................................... $ 148,039 $209,326
--------- --------
Operating expenses:
Lease operating...................................................... 23,053 20,824
Production and other taxes........................................... 3,410 7,118
Transportation....................................................... 1,331 1,262
Depreciation, depletion and amortization............................. 71,207 61,146
General and administrative (includes non-cash stock compensation
of $578 and $595 for the three months ended March 31, 2002
and 2001, respectively............................................. 12,345 11,285
--------- --------
Total operating expenses........................................... 111,346 101,635
--------- --------
Income from operations.................................................... 36,693 107,691
Other income (expenses):
Interest and other income, net....................................... 1,816 613
Interest expense..................................................... (7,201) (6,982)
Capitalized interest................................................. 2,130 1,330
Dividends on convertible preferred securities of Newfield Financial
Trust I............................................................ (2,336) (2,336)
Unrealized commodity derivative expense.............................. (5,645) (1,558)
---------- ---------
(11,236) (8,933)
Income before income taxes................................................ 25,457 98,758
Income tax provision:
Current.............................................................. 6,227 21,089
Deferred............................................................. 2,904 14,524
--------- --------
9,131 35,613
--------- ---------
Income before cumulative effect of change in accounting principle. 16,326 63,145
Cumulative effect of change in accounting principle, net of tax
Adoption of SFAS 133................................................. -- (4,794)
--------- ---------
Net income................................................................ $ 16,326 $ 58,351
========= ========
Earnings per share
Basic-
Income before cumulative effect of change in accounting
Principles....................................................... $ 0.37 $ 1.43
Cumulative effect of change in accounting principle................ -- (0.11)
Net income......................................................... $ 0.37 $ 1.32
========= ========
Diluted-
Income before cumulative effect of change in accounting
Principles....................................................... $ 0.37 $ 1.32
Cumulative effect of change in accounting principle................ -- (0.10)
Net income......................................................... $ 0.37 $ 1.22
========= ========
Weighted average number of shares outstanding for basic earnings
per share............................................................ 44,212 44,125
========= ========
Weighted average number of shares outstanding for diluted earnings
per share............................................................ 48,745 48,882
========= ========
The accompanying notes to consolidated financial statements are an integral part
of this financial statement.
2
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended
March 31,
------------------------
2002 2001
----------- -----------
Cash flows from operating activities:
Net income.............................................................. $ 16,326 $ 58,351
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization................................ 71,207 61,146
Deferred taxes.......................................................... 2,904 14,524
Stock compensation...................................................... 578 595
Unrealized commodity derivative expense................................. 5,645 1,558
Cumulative effect of change in accounting principle..................... -- 4,794
----------- -----------
96,660 140,968
Changes in assets and liabilities:
Decrease in accounts receivable - oil and gas........................... 5,263 53,716
(Increase) decrease in inventories...................................... 451 (2,872)
(Increase) decrease in other current assets............................. (1,086) (710)
(Increase) decrease in other assets..................................... 288 (3,902)
Increase (decrease) in accounts payable and accrued liabilities......... (2,531) 5,000
Increase (decrease) in advances from joint owners....................... -- 2,181
Increase (decrease) in other liabilities................................ (396) 7,150
----------- -----------
Net cash provided by operating activities............................. 98,649 201,531
----------- -----------
Cash flows from investing activities:
Acquisition of Lariat Petroleum, net of cash acquired................... -- (264,089)
Additions to oil and gas properties..................................... (84,489) (107,846)
Additions to furniture, fixtures and equipment.......................... (826) (1,112)
----------- -----------
Net cash used in investing activities................................. (85,315) (373,047)
----------- -----------
Cash flows from financing activities:
Proceeds from borrowings................................................ 128,000 663,000
Repayments of borrowings................................................ (146,000) (622,000)
Proceeds from issuance of senior notes.................................. -- 174,879
Proceeds from issuance of common stock, net............................. 3,396 530
Purchases of treasury stock............................................. (218) (575)
----------- -----------
Net cash provided by (used in) financing activities................... (14,822) 215,834
----------- -----------
Effect of exchange rate changes on cash and cash equivalents................. 6 837
----------- -----------
Increase (decrease) in cash and cash equivalents............................. (1,482) 45,155
Cash and cash equivalents, beginning of period............................... 26,610 18,451
----------- -----------
Cash and cash equivalents, end of period..................................... $ 25,128 $ 63,606
=========== ===========
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..... 224,760 2 3,394 3,396
Issuance of restricted stock,
less amortization
of $60.................... 28,500 909 (849) 60
Treasury stock, at cost...... (7,181) (218) (218)
Amortization of stock
compensation.............. 518 518
Tax benefit from exercise of
stock options............. 1,507 1,507
Comprehensive Income:
Net income................... 16,326 16,326
Foreign currency translation
adjustment, net of tax
of $947................... 1,758 1,758
Reclassification adjustments
for settled contracts, net
of tax of $12,063......... (19,908) (19,908)
Changes in fair value of
outstanding hedging
positions, net of tax
of $15,234................ (25,141) (25,141)
---------
Total comprehensive
income.................... (26,965)
---------- ----- -------- -------- --------- -------- -------- --------- ---------
Balance, March 31, 2002 45,215,537 $ 451 (867,936) $(26,012) $ 370,544 $ (8,176) $378,742 $ (27,273) $ 688,276
========== ===== ======== ======== ========= ======== ======== ========= =========
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 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. Implementation of this standard is required no later than January
1, 2003, with earlier application encouraged. 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 month period ended March 31, 2002 and 2001.
Three Month
Period Ended
March 31,
------------------------
2002 2001
----------- -----------
(in thousands,
except per share amounts)
Income (numerator):
Income before cumulative effect change
in accounting principle....................... $ 16,326 $ 63,145
Cumulative effect change in accounting
principle, net of tax........................ --- (4,794)
----------- -----------
Income - basic.................................... 16,326 58,351
After tax dividends on convertible trust
preferred securities......................... 1,518 1,518
--------- -----------
Income - diluted.................................. $ 17,844 $ 59,869
=========== ===========
Shares (denominator):
Shares - basic.................................... 44,212 44,125
Dilution effect of stock options outstanding
at end of period.............................. 610 834
Dilution effect of convertible trust
preferred securities.......................... 3,923 3,923
----------- -----------
Shares - diluted.................................. 48,745 48,882
=========== ===========
Earnings per share:
Basic before change in accounting principle....... $ 0.37 $ 1.43
Basic............................................. $ 0.37 $ 1.32
Diluted before change in accounting principle..... $ 0.37 $ 1.32
Diluted........................................... $ 0.37 $ 1.22
The calculation of shares outstanding for diluted EPS above does not
include the effect of outstanding stock options to purchase 800,500 and 594,100
shares for the three months ended March 31, 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):
Quarter
Ended
March 31,
---------
2001
---------
(unaudited)
Proforma:
Revenue............................................................................ $214,968
Income from operations............................................................. 108,832
Income before cumulative effect of change in accounting
principle....................................................................... 62,927
Cumulative effect of change in accounting principles............................... (4,794)
Net income......................................................................... 58,133
Basic earnings per common share before cumulative effect
of change in accounting principle............................................... $ 1.43
Basic earnings per common share.................................................... $ 1.32
Diluted earnings per common share before cumulative effect
of change in accounting principle............................................... $ 1.32
Diluted earnings per common share.................................................. $ 1.22
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
United States Australia International Total
------------- ----------- ------------- -----------
Three Months Ended March 31, 2002
- ----------------------------------------------------------
Oil and gas revenues...................................... $ 141,473 $ 6,566 $ --- $ 148,039
Operating expenses:
Lease operating...................................... 20,156 2,897 --- 23,053
Transportation....................................... 1,331 --- --- 1,331
Production and other taxes........................... 3,410 --- --- 3,410
Depreciation, depletion and amortization............. 69,633 1,574 --- 71,207
Allocated income taxes............................... 16,427 629 ---
----------- ----------- -----------
Net income from oil and gas operations........... $ 30,516 $ 1,466 $ ---
=========== =========== ===========
General and administrative........................... 11,767
Stock compensations.................................. 578
-----------
Total operating expenses......................... 111,346
-----------
Income from operations.................................... 36,693
Interest expense and dividends, net of interest and
other income..................................... (5,591)
Unrealized commodity derivative expense.............. (5,645)
-----------
Income before income taxes................................ $ 25,457
===========
Total long-lived assets................................... $ 1,367,832 $ 17,709 $ 32,214 $ 1,417,755
=========== =========== =========== ===========
Additions to long-lived assets............................ $ 69,589 $ 6,961 $ 4,026 $ 80,576
=========== =========== =========== ===========
Three Months Ended March 31, 2001
- ----------------------------------------------------------
Oil and gas revenues...................................... $ 203,031 $ 6,295 $ --- $ 209,326
Operating expenses:
Lease operating...................................... 18,285 2,539 --- 20,824
Transportation....................................... 1,262 --- --- 1,262
Production and other taxes........................... 4,445 2,673 --- 7,118
Depreciation, depletion and amortization............. 59,992 1,154 --- 61,146
Allocated income taxes............................... 41,666 (21) ---
----------- ----------- -----------
Net income (loss) from oil and gas operations.... $ 77,381 $ (50) $ ---
=========== =========== ===========
General and administrative........................... 10,690
Stock compensation................................... 595
-----------
Total operating expenses......................... 101,635
-----------
Income from operations.................................... 107,691
Interest expense and dividends, net of interest and
other income..................................... (7,375)
Unrealized commodity derivative expense.............. (1,558)
-----------
Income before income taxes................................ $ 98,758
===========
Total long-lived assets................................... $ 1,283,766 $ 9,497 $ 16,702 $ 1,309,965
=========== =========== =========== ===========
Additions to long-lived asset............................. $ 537,330 $ (16) $ 458 $ 537,772
=========== =========== =========== ===========
9
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 $17.7 million in after tax losses out of the net $20.1
million in after tax losses recorded in accumulated other comprehensive income
(loss) at March 31, 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 collars 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
in accumulated other comprehensive income (loss) all of the subsequent changes
in the fair value, including the changes in the option's time value. Gains or
losses on these collar and floor contracts used to hedge commodity price risk
associated with the forecasted sale of oil and gas production will be
reclassified out of other comprehensive income (loss) into earnings when the
forecasted sale of production occurs. For the period ended March 31, 2002, the
Company recorded an unrealized loss of $5.6 million under the income statement
caption "Unrealized commodity derivative expense."
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 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
10
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 March 31, 2002, the Company had entered into the commodity derivative
instruments set forth in the table below as a cash flow hedges of the forecasted
sale of its U.S. Gulf Coast natural gas production for 2002 through 2003.
NYMEX Contract Price Per MMBtu
----------------------------------------------------------------------------
Collars
------------------------------------------------
Floors Ceilings Floor Contracts
----------------------- ----------------------- ----------------
Swaps
Volume in (Weighted Weighted Weighted Weighted Fair Value
Period and Type of Contract MMMBtus Average Range Average Range Average Range Average (in millions)
- --------------------------- ------- -------- ------------- -------- ------------- -------- ------- ------- ------------
April 2002 - June 2002
Price Swap Contracts........ 13,350 $ 3.24 -- -- -- -- -- -- $ (1.4)
Collar Contracts............ 13,800 -- $2.20 - $4.00 $ 2.99 $2.94 - $6.00 $ 3.93 -- -- 0.2
Floor Contracts............. 1,000 -- -- -- -- -- $ 2.85 $ 2.85 --
July 2002 - September 2002
Price Swap Contracts........ 4,250 3.47 -- -- -- -- -- -- 0.4
Collar Contracts............ 20,850 -- 2.50 - 4.00 3.10 3.19 - 6.00 4.07 -- -- 1.7
October 2002 - December 2002
Price Swap Contracts........ 1,700 3.78 -- -- -- -- -- -- 0.3
Collar Contracts............ 3,800 -- 4.00 3.84 4.80 - 6.10 5.07 -- -- 2.1
January 2003 - March 2003
Price Swap Contracts........ 2,400 3.51 -- -- -- -- -- -- (0.8)
Collar Contracts............ 450 -- 3.50 3.50 4.20 4.20 -- -- --
April 2003 - June 2003
Price Swap Contracts........ 2,405 3.51 -- -- -- -- -- -- --
Collar Contracts............ 1,050 -- 3.50 3.50 3.90 - 4.20 4.03 -- -- 0.2
July 2003 - September 2003
Price Swap Contracts........ 2,410 3.51 -- -- -- -- -- -- (0.1)
Collar Contracts............ 1,350 -- 3.50 3.90 - 4.20 4.00 -- -- 0.1
October 2003 - December 2003
Price Swap Contracts........ 2,410 3.51 -- -- -- -- -- -- (0.6)
Collar Contracts............ 1,350 -- 3.50 3.50 3.90 - 4.20 4.00 -- -- --
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 March 31, 2002.
Weighted Average
Volume in Contract Price Fair Value
Period and Type of Contract MMMBTUs PER MMBtu (in millions)
- ----------------------------- ---------------- ---------------- -------------
April 2002 -- December 2002
Price Swap Contracts............... 2,750 $2.61 $(1.9)
January 2003 -- March 2003
Price Swap Contracts............... 900 2.61 (1.0)
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(CONTINUED)
(Unaudited)
Oil and Condensate.
As of March 31, 2002, the Company had entered into the commodity derivative
instruments set forth in the table below as a cash flow hedges of the forecasted
sale of its U.S. Gulf Coast oil production for 2002 through 2003.
NYMEX Contract Price Per Bbl
---------------------------------------------------------------------------------
Collars
---------------------------------------------------
Floors Ceilings Floor Contracts
------------------------- ------------------------ -----------------
Swaps
Volume in (Weighted Weighted Weighted Weighted Fair Value
Period and Type of Contract Bbls Average) Range Average Range Average Range Average (in millions)
- --------------------------- --------- ---------- --------------- -------- --------------- -------- ------- -------- -----------
April 2002 - June 2002
Price Swap Contracts....... 273,000 $ 24.01 -- -- -- -- -- -- $ (0.10)
Collar Contracts........... 728,000 -- $21.00 - $25.00 $ 22.95 $25.75 - $30.75 $ 28.09 -- -- 3.90
Floor Contracts............ 136,500 -- -- -- -- -- $ 21.15 $ 21.15 1.00
July 2002 - September 2002
Price Swap Contracts....... 276,000 24.01 -- -- -- -- -- -- (0.60)
Collar Contracts........... 713,000 -- 21.00 - 25.00 22.98 26.75 - 30.75 28.74 -- -- (0.50)
Floor Contracts............ 138,000 -- -- -- -- -- 21.15 21.15 0.10
October 2002 - December 2002
Price Swap Contracts....... 276,000 24.01 -- -- -- -- -- -- (0.40)
Collar Contracts........... 552,000 -- 21.00 - 25.00 22.83 27.50 - 30.75 29.03 -- -- (0.20)
Floor Contracts............ 138,000 -- -- -- -- -- 21.15 21.15 0.10
January 2003 - March 2003
Price Swap Contracts....... 180,000 24.92 -- -- -- -- -- -- --
Collar Contracts........... 90,000 -- 20.00 20.00 27.50 27.50 -- -- (0.20)
Floor Contracts............ 135,000 -- -- -- -- -- 21.15 21.10 0.20
April 2003 - June 2003
Collar Contracts........... 91,000 -- 20.00 20.00 27.50 27.50 -- -- (0.10)
12
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:
- the amount of cash flow available for capital expenditures;
- our ability to borrow and raise additional capital;
- the amount of oil and gas that we can economically produce; and
- the accounting for our oil and gas activities.
We use hedging transactions with respect to a portion of our oil and
gas production to achieve more predictable cash flow 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. We believe
that our working capital and cash flow from operations will be sufficient to
fund planned capital expenditures for the remainder of 2002.
13
Results of Operations
Three Months Ended
March 31,
--------------------
2002 2001
---------- ---------
Production:
United States
Natural gas (Bcf).................................... 33.9 30.8
Oil and condensate (MBbls)........................... 1,349.5 1,241.2
Total (Bcfe)......................................... 42.0 38.2
Australia (1)
Oil and condensate (MBbls)........................... 298.3 239.6
Total (Bcfe)......................................... 1.8 1.4
Total
Natural gas (Bcf).................................... 33.9 30.8
Oil and condensate (MBbls)........................... 1,647.3 1,480.6
Total (Bcfe)......................................... 43.8 39.6
Average Realized Prices: (2)
United States
Natural gas (per Mcf)................................ $ 3.26 $ 5.56
Oil and condensate (per Bbl)......................... 22.03 24.69
Australia (2)
Oil and condensate (per Bbl)......................... $ 22.01 $ 26.28
Total
Natural gas (per Mcf)................................ $ 3.26 $ 5.56
Oil and condensate (per Bbl)......................... 22.03 24.95
- -----------------
(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 $0.03 and $0.03 for the three
months ended March 31, 2002 and 2001, respectively. The realized price of oil
and condensate is reduced by $0.23 and $0.24 for the three months ended March
31, 2002 and 2001, respectively. Average realized prices include the effect of
hedges.
Production. Our total oil and gas production (stated on a natural gas
equivalent basis) increased 10% in the first quarter of 2002 versus the same
quarter of the prior year. Gas production was impacted by our decision to
voluntarily curtail approximately one Bcfe in the first quarter of 2002 in
response to low commodity prices. Without the curtailment, our production would
have increased about 13%. The increase was the result of development prospects
in the Gulf of Mexico, drilling success and the timing of crude oil liftings in
Australia.
14
Effect of Hedging on Realized Prices. The following table presents
information about the effect of our hedging program on realized prices.
Ratio of
Average Realized Prices Ratio of
------------------------ Hedged to
With Without Non-Hedged
Hedge Hedge Price (1)
----------- ----------- -------------
Natural Gas
Three months ended March 31, 2001.................... $5.56 $7.04 79%
Three months ended March 31, 2002.................... $3.26 $2.30 142%
Crude Oil and Condensate
Three months ended March 31, 2001.................... $24.95 $27.23 92%
Three months ended March 31, 2002.................... $22.03 $20.64 107%
- ------------------
(1) The ratio is determined by dividing the realized price (which includes the
effects of hedging) by the price that otherwise would have been realized without
hedging activities.
Net Income and Revenues. For the three months ended March 31, 2002, we
had net income of $16.3 million, or $0.37 per diluted share. This compares to
first quarter 2001 net income of $58.4 million, or $1.22 per diluted share
(which includes a charge for the cumulative effect of a change in accounting
principle of $4.8 million, or $0.10 per diluted share). Revenues for the first
quarter of 2002 were $148.0 million, 29% below the first quarter of 2001
revenues of $209.3 million. The decrease in revenues in 2002 was primarily due
to decreased natural gas prices.
Operating Expenses. The following table presents information about our
operating expenses for the three months ended March 31, 2002 and 2001.
Unit of Production (Per Mcfe) Amount (in thousands)
-------------------------------- -----------------------------------
Three Months Ended Three Months Ended
March 31, Percentage March 31, Percentage
------------------ Increase ---------------------- Increase
2002 2001 (Decrease) 2002 2001 (Decrease)
-------- -------- ---------- -------- --------- ----------
United States
Lease operating............................. $ 0.48 $ 0.48 -- $ 20,156 $18,285 10%
Production and other taxes.................. 0.08 0.12 (33)% 3,410 4,445 (23)%
Transportation.............................. 0.03 0.03 -- 1,331 1,262 5%
Depreciation, depletion and amortization.... 1.66 1.57 6% 69,633 59,992 16%
General and administrative (exclusive of
stock compensation)..................... 0.27 0.27 -- 11,236 10,441 8%
Total operating......................... 2.52 2.47 2% 105,766 94,425 12%
Australia
Lease operating............................. $ 1.62 $ 1.77 (8)% $2,897 $2,539 14%
Production and other taxes.................. -- 1.86 N/C -- 2,673 N/C
Transportation.............................. -- -- -- -- -- --
Depreciation, depletion and amortization.... 0.88 0.80 10% 1,574 1,154 36%
General and administrative (exclusive of stock
compensation)........................... 0.30 0.17 77% 531 249 113%
Total operating......................... 2.80 4.60 (39)% 5,002 6,615 (24)%
Total
Lease operating............................. $ 0.53 $ 0.53 -- $23,053 $20,824 11%
Production and other taxes.................. 0.08 0.18 (56)% 3,410 7,118 (52)%
Transportation.............................. 0.03 0.03 -- 1,331 1,262 5%
Depreciation, depletion and amortization.... 1.63 1.54 6% 71,207 61,146 16%
General and administrative (exclusive of
stock compensation)..................... 0.27 0.27 -- 11,767 10,690 10%
Total operating........................ 2.54 2.55 -- 110,768 101,040 10%
o The decrease in domestic production and other taxes resulted from
lower natural gas prices in the first quarter of 2002.
o The increase in domestic DD&A is primarily related to increased costs
of reserve additions arising from both the quantity of proved reserves
added and increases in the costs 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 Non-routine maintenance operations on our FPSOs during the first
quarter of 2001 resulted in higher Australian lease operating expense
for that period.
o Australian capital expenditures offset production taxes otherwise
payable. As a result of anticipated future capital expenditures, no
Australian production taxes were recorded in the first quarter of
2002.
15
o The increase in the Australian DD&A rate is primarily a result of
unsuccessful exploratory drilling efforts in 2001.
o The significant increase in per unit Australian general and
administrative expense relates to the recognition of compensation
based on 2001 performance.
Interest and Other Income, Net. During the first quarter of 2002, we
reversed accruals of certain contingencies related to our acquisition of Gulf
Australia in 1999. The net effect of these items was that we recorded a $2.2
million gain. The gain was partially offset by losses from foreign currency
transactions in Australia.
Interest Expense. 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 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
March 31,
--------------------
2002 2001
--------- ---------
(in millions)
Gross interest expense.......................................... $ 7.2 $ 7.0
Capitalized interest............................................ (2.1) (1.3)
--------- --------
Net interest expense............................................ 5.1 5.7
Distributions on preferred securities........................... 2.3 2.3
--------- --------
Total interest expense and dividends............................ $ 7.4 $ 8.0
========= ========
Unrealized Commodity Derivative Expense. 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 $5.6 and $1.6
million of unrealized expense for the three months ended March 31, 2002 and
2001, respectively, primarily represents the ineffective portion of our hedges.
Taxes. The effective tax rate for the first quarter of 2001 and the
first quarter of 2002 was the same. Estimates of future taxable income can be
significantly affected by changes in oil and natural gas prices, estimates of
the timing and amount of future production and estimates of future operating and
capital costs.
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 $22.2 million as of March 31, 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.
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. 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 March 31, 2002, we had $97 million outstanding under our
credit facility and an additional $14 million outstanding under our money market
lines of credit with various banks. At March 31, 2002, our long-term debt was
$410.6 million, which includes $125 million of our 7.45% Senior Notes due 2007
and $175 million of our 7 5/8% Senior Notes due 2011.
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 $510 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
16
facility matures on January 23, 2004. As of April 26, 2002 we had $114 million
available under our credit facility and had outstanding borrowings of $96
million. Effective May 1, 2002, the borrowing base will increase to $525
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 April 26, 2002, we
had outstanding borrowings of $5 million 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 credit rating.
Cash Flow from Operations. Our net cash flow from operations for the
three months ended March 31, 2002 decreased 51% from the comparable period of
2001 to $98.6 million. This compares to cash flow from operations in 2001 of
$201.5 million. Net cash flow from operations before changes in operating assets
and liabilities for the first quarter of 2002 was $96.7 million compared to
$140.9 million for the same period of 2001. The decrease is primarily
attributable to lower commodity prices.
Capital Expenditures. In the first three months of 2002, our capital
spending totaled $81 million. We invested $4 million for acquisitions, $37
million in development, $30 million in domestic exploration and $10 million
internationally.
We have budgeted $360 million for capital spending in 2002.
Approximately $200 million has been budgeted 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. We continue to pursue attractive
acquisition opportunities; however, the timing, size and purchase price of
acquisitions are unpredictable. We anticipate that our capital expenditure
budget for 2002 will be funded principally from cash flow from operations and
working capital. 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.
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 March 31, 2002 and the fair value of those contracts as of that date.
Since March 31, 2002, we have not entered into any additional natural
gas or oil and gas condensate price hedging contracts. We continue to evaluate
additional hedging transactions for the remainder of 2002 and future years.
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 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.). 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.
17
Implementation of this standard is required no later than January 1, 2003, with
earlier application encouraged. 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 and our
financial position. 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.
18
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
19
Part II
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
None
(b) Reports on Form 8-K:
On February 8, 2002, we filed a Current Report on Form 8-K
announcing earnings guidance for our 2001 financial operating
results, as well as spending and growth plans for 2002.
On March 14, 2002, we filed a Current Report on Form 8-K
announcing recent Gulf of Mexico discoveries, including significant
discoveries in the deep shelf play.
On March 26, 2002, we filed a Current Report on Form 8-K
announcing that we had entered a Sales Agency Agreement with UBS
Warburg LLC as successor to PaineWebber Incorporated.
20
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: April 30, 2002 By: /s/ TERRY W. RATHERT
------------------------
Terry W. Rathert
Vice President and Chief Financial Officer
(Authorized Officer and Principal Financial Officer)
21
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
None
22