<PAGE> 1
===============================================================================
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 SEPTEMBER 30, 1999
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 of principal executive offices) (Zip code)
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 October 29, 1999, there were 41,606,144 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
PART I
<S> <C>
Item 1. Financial Statements:
Consolidated Balance Sheet as of September 30,
1999 and December 31, 1998............................. 1
Consolidated Statement of Income for the three months ended
September 30, 1999 and 1998 and for the nine months
ended September 30, 1999 and 1998...................... 2
Consolidated Statement of Cash Flows for the
nine months ended September 30, 1999
and 1998............................................... 3
Consolidated Statement of Stockholders' Equity for the nine
months ended September 30, 1999........................ 4
Notes to Financial Statements................................. 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 10
PART II
Item 6. Exhibits and Reports on Form 8-K................................ 21
</TABLE>
ii
<PAGE> 3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS OF DOLLARS, EXCEPT SHARE DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
----------- -----------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents ............................... $ 30,425 $ 92
Accounts receivable, oil and gas ........................ 42,777 43,095
Inventories.............................................. 9,234 --
Other ................................................... 3,090 2,082
----------- -----------
Total current assets ................................. 85,526 45,269
----------- -----------
Oil and gas properties (full cost method, of which $64,629
at September 30, 1999 and $34,234 at December 31,
1998 were excluded from amortization) ................... 1,149,224 992,629
Less-accumulated depreciation, depletion and amortization ... (525,914) (414,206)
----------- -----------
623,310 578,423
----------- -----------
Furniture, fixtures and equipment, net ...................... 2,606 2,208
Other assets ................................................ 7,588 3,411
----------- -----------
Total assets ......................................... $ 719,030 $ 629,311
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities ................ $ 55,283 $ 52,123
Advances from joint owners .............................. 386 1,952
----------- -----------
Total current liabilities ........................ 55,669 54,075
----------- -----------
Other liabilities ........................................... 12,282 11,467
Long-term debt .............................................. 124,672 208,650
Deferred taxes .............................................. 26,829 31,171
----------- -----------
Total long-term liabilities .......................... 163,783 251,288
----------- -----------
Company-obligated, mandatorily redeemable, convertible
preferred securities of Newfield Financial Trust I......... 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; 41,604,144 and 40,429,729
shares issued and outstanding at September 30,
1999 and December 31, 1998, respectively) ............ 416 404
Additional paid-in capital .................................. 265,232 250,642
Unearned compensation ....................................... (3,981) (5,007)
Accumulated other comprehensive loss - foreign currency
translation adjustment..................................... (358) --
Retained earnings ........................................... 94,519 77,909
----------- -----------
Total stockholders' equity ........................... 355,828 323,948
----------- -----------
Total liabilities and stockholders' equity ........... $ 719,030 $ 629,311
=========== ===========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
1
<PAGE> 4
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oil and gas revenues ....................... $ 78,648 $ 45,296 $ 191,725 $ 145,180
--------- --------- --------- ---------
Operating expenses:
Lease operating ............................ 12,016 8,779 30,783 24,831
Production and other taxes.................. 963 -- 1,054 --
Depreciation, depletion and amortization ... 38,382 29,279 112,232 87,028
General and administrative, net ............ 4,094 2,274 10,350 7,768
Stock compensation ......................... 494 587 1,485 1,695
--------- --------- --------- ---------
Total operating expenses .............. 55,949 40,919 155,904 121,322
--------- --------- --------- ---------
Income from operations ......................... 22,699 4,377 35,821 23,858
Other income (expense):
Other income ............................... 427 190 715 802
Interest expense, net ...................... (2,675) (3,188) (9,324) (7,065)
Dividends on preferred securities of
Newfield Financial Trust I ............... (1,168) -- (1,168) --
--------- --------- --------- ---------
(3,416) (2,998) (9,777) (6,263)
--------- --------- --------- ---------
Income before income taxes ..................... 19,283 1,379 26,044 17,595
Income tax provision:
Current .................................... -- -- -- --
Deferred ................................... 6,878 529 9,434 6,261
--------- --------- --------- ---------
6,878 529 9,434 6,261
--------- --------- --------- ---------
Net income ..................................... $ 12,405 $ 850 $ 16,610 $ 11,334
========= ========= ========= =========
Basic earnings per common share ................ $ 0.30 $ 0.02 $ 0.40 $ 0.31
========= ========= ========= =========
Diluted earnings per common share .............. $ 0.29 $ 0.02 $ 0.39 $ 0.29
========= ========= ========= =========
Weighted average number of shares
outstanding for basic earnings per share ....... 41,517 36,721 41,039 36,315
========= ========= ========= =========
Weighted average number of shares
outstanding for diluted earnings per share ..... 42,590 38,776 42,192 38,470
========= ========= ========= =========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
2
<PAGE> 5
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------
1999 1998
---------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income ..................................................... $ 16,610 $ 11,334
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization ..................... 112,232 87,028
Deferred taxes ............................................... 9,434 6,261
Stock compensation ........................................... 1,485 1,695
--------- ---------
139,761 106,318
Changes in operating assets and liabilities:
Decrease in accounts receivable, oil and gas ................. 1,585 18,212
Decrease in inventories ...................................... 1,503 --
Increase in other current assets ............................. (3,012) (1,352)
Increase in other assets ..................................... (4,177) (15)
Decrease in accounts payable and accrued liabilities ......... (204) (7,321)
Increase (decrease) in advances from joint owners ............ (1,566) 7,998
Increase (decrease) in other liabilities ..................... (559) 687
--------- ---------
Net cash provided by operating activities .................. 133,331 124,527
--------- ---------
Cash flows from investing activities:
Acquisition of Gulf Australia, net of cash acquired
of $12,064 ................................................. (10,681) --
Additions to oil and gas properties .......................... (157,764) (270,406)
Additions to furniture, fixtures and equipment ............... (922) (918)
--------- ---------
Net cash used in investing activities ...................... (169,367) (271,324)
--------- ---------
Cash flows from financing activities:
Proceeds from borrowings ..................................... 443,000 569,750
Repayments of borrowings ..................................... (527,000) (511,750)
Proceeds from issuance of convertible preferred securities ... 143,750 --
Proceeds from issuance of common stock, net .................. 6,707 83,974
--------- ---------
Net cash provided by financing activities .................. 66,457 141,974
--------- ---------
Effect of exchange rate changes on cash and cash equivalents ........ (88) --
--------- ---------
Increase (decrease) in cash and cash equivalents .................... 30,333 (4,823)
Cash and cash equivalents, beginning of period ...................... 92 8,217
--------- ---------
Cash and cash equivalents, end of period ............................ $ 30,425 $ 3,394
========= =========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
3
<PAGE> 6
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
Accumulated
Common Stock Additional Other Total
--------------- Paid-in Unearned Retained Comprehensive Stockholders'
Shares Amount Capital Compensation Earnings Loss Equity
------ ------ ------- ------------ -------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1998 ............. 40,429,729 $404 $250,642 $(5,007) $77,909 $ -- $323,948
Issuance of Common Stock ........... 1,161,980 12 6,695 -- -- -- 6,707
Issuance of restricted stock, less
amortization of $112 ............. 28,035 -- 829 702 -- -- 1,531
Cancellation of restricted stock ... (15,600) -- (370) (312) -- -- (682)
Amortization of stock compensation . -- -- -- 636 -- -- 636
Tax benefit from exercise of
stock options .................... -- -- 7,436 -- -- -- 7,436
Comprehensive Income:
Net income ......................... -- -- -- -- 16,610 -- 16,610
Other comprehensive loss, net of tax
Foreign currency translation
adjustment ..................... -- -- -- -- -- (358) (358)
---------- ---- -------- -------- ------- ------ ---------
Total Comprehensive Income........... -- -- -- -- -- -- 16,252
---------- ---- -------- -------- ------- ------ ---------
---------- ---- -------- -------- ------- ------ ---------
Balance, September 30, 1999 ............ 41,604,144 $416 $265,232 $(3,981) $94,519 $(358) $355,828
========== ==== ======== ======== ======= ====== =========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
4
<PAGE> 7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(1) ACCOUNTING POLICIES
Basis of Presentation
Unless the context otherwise requires, references to the "Company"
include Newfield Exploration Company and its subsidiaries. All significant
intercompany balances and transactions have been eliminated. The unaudited
consolidated financial statements of the Company reflect, in the opinion of
management, all adjustments, consisting only of normal and recurring
adjustments, necessary to present fairly the Company's consolidated financial
position at September 30, 1999 and the Company's consolidated results of
operations for the three and nine month periods ended September 30, 1999 and
1998 and consolidated cash flows for the nine month periods ended September 30,
1999 and 1998. 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 Annual Report on Form 10-K for the
year ended December 31, 1998, including those financial statements and notes
thereto incorporated by reference to the Company's 1998 Annual Report to
Stockholders.
Inventories
Inventories consist of materials and supplies, stated at the lower of
cost or market, and oil produced but not sold, stated at the market value on
the balance sheet date, net of costs to sell. Crude oil from the Company's
operations located in Australia is produced into a floating production, storage
and off loading ("FPSO") system and sold periodically as a barge quantity is
accumulated. The product inventory at September 30, 1999 consists of
approximately 304,800 barrels of crude oil, net to the Company's interest,
and is carried at the market value on the balance sheet date.
Foreign Currency
The functional currency for all foreign operations, except Australia,
is the U.S. dollar. Translation adjustments resulting from translating the
Australian subsidiary's Australian dollar financial statements into U.S.
dollars are included as other comprehensive income in the consolidated
statement of stockholders' equity for the period. Gains and losses incurred
on currency transactions in other than a country's functional currency are
included in the consolidated statement of income for the period.
Earnings per Share
Basic earnings per common share ("EPS") is computed by dividing net
income by the weighted average number of common shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
securities were exercised or converted to common stock.
5
<PAGE> 8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(UNAUDITED)
There are no adjustments to reported net income for purposes of
calculating earnings per share. The following is a calculation of basic and
diluted weighted average shares outstanding for the three and nine month
periods ended September 30, 1999 and 1998, respectively:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Shares outstanding for basic EPS ................ 41,516,635 36,720,935 41,039,237 36,315,491
Dilutive effect of stock options
outstanding at end of period .............. 1,073,316 2,055,005 1,152,417 2,154,063
---------- ---------- ---------- ----------
Shares outstanding for diluted EPS .............. 42,589,951 38,775,940 42,191,654 38,469,554
========== ========== ========== ==========
</TABLE>
The calculation of diluted EPS does not include the effect of the
6.50% convertible preferred securities outstanding during the three and nine
month periods ended September 30, 1999, because to do so would have been
antidilutive.
Hedging
From time to time, the Company has utilized and expects to continue to
utilize hedging transactions with respect to a portion of its oil and gas
production to achieve a more predictable cash flow, as well as to reduce its
exposure to price fluctuations. 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. Substantially all of the Company's hedging
transactions to date were carried out in the over-the-counter market with
investment grade institutions. The Company accounts for these transactions as
hedging activities and, accordingly, gains or losses are included in oil and
gas revenues when the hedged production is delivered. Neither the hedging
contracts nor the unrealized gains or losses on these contracts are recognized
in the financial statements.
6
<PAGE> 9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(UNAUDITED)
(2) CONTINGENCIES
The Company has been named as a defendant in certain lawsuits arising
in the ordinary course of business. While the outcome of these lawsuits cannot
be predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows or results of
operations of the Company.
The Company's operations are subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company believes its current operations are in material compliance with current
environmental laws and regulations. There can be no assurance, however, that
current regulatory requirements will not change, currently unforeseen
environmental incidents will not occur or past non-compliance with environment
laws will not be discovered.
(3) ACQUISITION OF GULF AUSTRALIA
On July 15, 1999, the Company completed the purchase of Gulf Australia
Resources Limited for $23 million. Included in the purchase price was a
substantial amount of working capital, including an inventory of 479 MBbls of
oil. The acquisition includes interests in two producing oil fields in the
Timor Sea, offshore Australia.
(4) CONVERTIBLE PREFERRED SECURITIES OF NEWFIELD FINANCIAL TRUST I
In August 1999, Newfield Financial Trust I, a subsidiary of the
Company, issued, through an underwritten public offering, $144 million of
6.50% convertible preferred securities. Newfield Finanacial Trust I, a
business trust in which the Company owns all of the issued common securities
(the "Trust"), issued $143,750,000 (2,875,000 securities having a liquidation
preference of $50 each) of 6 1/2% Cumulative Quarterly Income Convertible
Securities, Series A (the "Trust Preferred Securities"). The proceeds of the
issuance of the Trust Preferred Securities were used to purchase $148,196,000
of the Company's 6 1/2% Junior Subordinated Convertible Debentures, due 2029
(the "Debentures"). The financial terms of the Debentures are generally the
same as those of the Trust Preferred Securities. The Trust Preferred
Securities accrue and pay distributions quarterly in arrears at a rate of
6 1/2% per annum on the stated liquidation amount of $50 per Trust Preferred
Security on February 15, May 15, August 15, and November 15 of each year
to security holders of record 15 business days immediately preceding the
distribution payment date. The Company has guaranteed, on a subordinated basis,
distributions and other payments due on the Trust Preferred Securities to the
extent that there are funds available in the Trust. The Company may cause the
Trust to defer the payment of distributions for successive periods up to 20
consecutive periods unless an event of default on the Debentures has occurred
and is continuing. During such periods, accrued distributions on the Trust
Preferred Securities will compound quarterly and the Company will generally not
be permitted to declare or pay distributions on its common stock or debt
securities that rank equal or junior to the Debentures.
7
<PAGE> 10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(UNAUDITED)
The Trust Preferred Securities are convertible at the option of the holder
at any time into common stock of the Company at the rate of 1.3646 shares of
Company common stock per Trust Preferred Security. This conversion rate will be
subject to adjustment to prevent dilution and is currently equivalent to a
conversion price of $36.64 per share of Company common stock. The Trust
Preferred Securities are mandatorily redeemable upon maturity of the Debentures
on August 15, 2029, or to the extent of any earlier redemption of any Debenture
by the Company and are callable by the Trust at any time after August 15, 2002.
(5) GEOGRAPHIC INFORMATION
The Company's operations are primarily related to natural gas and
crude oil exploration and production. Accordingly, such operations are
classified as one business segment. Financial information by geographic
area is presented below (in thousands):
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
Revenues: 1999 1998
--------- ---------
<S> <C> <C>
United States ..................................... $ 180,691 $ 145,180
Australia ......................................... 11,034 --
Other foreign ..................................... -- --
--------- ---------
Total $ 191,725 $ 145,180
========= =========
Long-Lived Assets: September 30, December 31,
1999 1998
--------- ---------
United States ..................................... $ 612,839 $ 569,259
Australia ......................................... 171 --
Other foreign ..................................... 10,300 9,164
--------- ---------
Total $ 623,310 $ 578,423
========= =========
</TABLE>
8
<PAGE> 11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(UNAUDITED)
(6) HEDGING TRANSACTIONS
As of October 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its 1999 and 2000 natural gas and oil
production, some of which were entered into subsequent to September 30, 1999,
as follows:
<TABLE>
<CAPTION>
NATURAL GAS
Swaps Collars Floor Contracts
-------------------------- ----------------------------------- -----------------------------
Weighted NYMEX Weighted
Average Contract Price Average
NYMEX per MMBtu NYMEX
Volume in Contract Price Volume in --------------------- Volume in Contract Price
Period MMMBtus per MMBtu MMMBtus Floors Ceilings MMMBtus per MMBtu
- ------------------------------- ---------- --------------- --------- ------- -------- ---------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 1999 .................. 3,510 $2.62 350 $2.38 $3.01 1,000 $2.55
November 1999 ................. 1,610 $2.74 2,000 $2.53-$2.68 $3.10-$3.14 --- ---
December 1999 ................. 1,610 $2.88 500 $2.55 $3.25-$3.32 1,500 $2.67
January 2000 - December 2000 .. 17,500 $2.56 250 $2.63 $3.25 4,700 $2.57
</TABLE>
<TABLE>
<CAPTION>
OIL
Swaps Collars Floor Contracts
------------------------- ---------------------------------- -----------------------------
Weighted NYMEX Weighted
Average Contract Price Average
NYMEX per Bbl NYMEX
Volume in Contract Price Volume in --------------------- Volume in Contract Price
Period Bbls per Bbl Bbls Floors Ceilings Bbls per Bbl
- ------------------------------- ---------- -------------- --------- ------- -------- ---------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 1999 .................. 124,000 $21.40 62,000 $15.00-$18.28 $17.00-$21.00 31,000 $19.82
November 1999 ................. 120,000 $21.40 60,000 $15.00-$18.28 $17.00-$21.00 30,000 $19.82
December 1999 ................. 124,000 $21.40 62,000 $15.00-$18.28 $17.00-$21.00 31,000 $19.82
January 2000 - March 2000 ..... 182,000 $21.07 182,000 $18.28-$19.50 $20.10-$21.00 91,000 $19.32
April 2000 - September 2000 ... --- --- 274,000 $18.28-$19.50 $20.10-$21.00 --- ---
</TABLE>
9
<PAGE> 12
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
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, quantities of oil and gas reserves that may be
economically produced and access to capital.
The Company's results of operations and cash flows may vary
significantly from quarter to quarter as a result of development operations,
commodity prices, the curtailment of production in association with workover
and recompletion activities and the incurrence of expenses related thereto, the
timing and amount of reimbursement for customary overhead costs received by the
Company and other factors, and, therefore, the results of operations and cash
flows for any one quarter may not be indicative of results for the full fiscal
year.
The Company uses the full cost method of accounting for its oil and
gas properties. Under this method, all acquisition, exploration and development
costs, including certain related employee costs, (less any joint interest
reimbursements for such costs) incurred for the purpose of acquiring and
finding oil and gas reserves are capitalized in a "full cost pool" as incurred.
These costs are grouped into cost centers on a country-by-country basis. The
Company records depletion of its full cost pool using the unit-of-production
method and uses its internal estimates of proved quantities of oil and gas
reserves for financial accounting matters. For each cost center, to the extent
that such capitalized costs in a full cost pool (net of depreciation, depletion
and amortization and related deferred taxes) exceed the present value (using a
10% discount rate) of estimated future net after-tax cash flows from proved oil
and gas reserves, such excess costs are charged to operations. Once incurred, a
writedown of oil and gas properties is not reversible at a later date even if
oil or gas prices increase.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("Statement No. 133"). The statement
requires companies to report the fair value of derivatives on the balance sheet
and record in income or other comprehensive income, as appropriate, any changes
in the fair value of the derivatives. In June 1999, the FASB issued Statement
No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133." Statement No. 133
will now become effective for the Company on January 1, 2001. The Company is
currently evaluating the impact of this statement.
10
<PAGE> 13
Certain terms relating to the oil and gas business are defined under
the caption "Oil and Gas Terms" at the end of Management's Discussion and
Analysis.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with
respect to the oil and gas operations of the Company:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- --------------------
1999 1998 1999 1998
------- -------- -------- --------
<S> <C> <C> <C> <C>
Production:
Oil and condensate (MBbls) .................. 1,302 826 3,012 2,730
Gas (MMcf) .................................. 21,691 16,036 64,991 47,069
Total production (MMcfe) .................... 29,500 20,991 83,061 63,451
Average Realized Price:
Oil and condensate (per Bbl) ................ $ 20.09 $ 12.28 $ 16.08 $ 13.26
Gas (per Mcf) ............................... 2.42 2.20 2.20 2.32
Average Costs (per Mcfe):
Lease operating ............................. $ 0.41 $ 0.42 $ 0.37 $ 0.39
Depreciation, depletion and amortization..... 1.30 1.39 1.35 1.37
General and administrative, net ............. 0.14 0.11 0.12 0.12
</TABLE>
PRODUCTION. Net production increased 31%, from 63.5 Bcfe for the nine months
ended September 30, 1998 to 83.1 Bcfe for the nine months ended September 30,
1999. Oil and condensate production for the nine months ended September 30,
1999 increased 282 MBbls, or 10%, compared to the same period in 1998.
Increased oil production for the first nine months of 1999 was primarily due
to the acquisition of interests in two producing oil fields in the Timor Sea,
offshore Australia, from Gulf Australia Resources Limited during the third
quarter of 1999. The increase in foreign production was partially offset by
a decrease in domestic oil and condensate production. The decrease in domestic
production was primarily due to well downtime at Vermillion 398 and South
Timbalier 148 and natural decline on other properties of the Company partially
offset by production increases from development wells that were placed on
production during 1998 and 1999 at Ship Shoal 354, High Island 537 and South
Marsh Island 141. Gas production increased by 17.9 Bcf, or 38%, from 47.1
Bcf for the nine months ended September 30, 1998 to 65.0 Bcf for the
comparable period of 1999. Increased gas production was primarily due to
production increases from drilling activities at East Cameron 373, East
Cameron 286, High Island 304 and South Marsh Island 141. These increases
were partially offset by natural production decline on other properties of
the Company. All of the Company's current gas production is generated from
domestic properties.
11
<PAGE> 14
Net production increased 40%, from 21.0 Bcfe for three months ended
September 30, 1998 to 29.5 Bcfe for the three months ended September 30, 1999.
Oil and condensate production for the three months ended September 30, 1999
increased 476 MBbls, or 58%, compared to the same period in 1998. Increased
oil and condensate production was primarily due to the acquisition of interests
in two producing oil fields in the Timor Sea, offshore Australia, from Gulf
Australia Resources Limited during the third quarter of 1999 and increased
domestic oil and condensate production. The increased domestic production
primarily resulted from drilling activities at Main Pass 138, High Island
537 and Vermillion 215 partially offset by well downtime at South Timbalier
148, High Island 474, Ship Shoal 354 and the sale of Eugene Island 128 in
the second quarter of 1999, as well as natural decline from other properties
of the Company. Gas production increased by 5.7 Bcf, or 36%, from 16.0 Bcf
for the three months ended September 30, 1998 to 21.7 Bcf for the comparable
period of 1999. Increased gas production was primarily related to production
increases from drilling activities at East Cameron 286, Main Pass 256 and High
Island 304.
OIL AND GAS REVENUES. Oil and gas revenues for the nine months ended September
30, 1999 increased by $46.2 million, or 32%, to $191.4 million from $145.2 for
the same period of 1998. Included in the 1999 total is $11.0 million in
international oil revenues resulting from the Company's acquisition of Gulf
Australia Resources Limited. The remaining increase is primarily a result of
increased domestic gas production and increased oil and condensate prices
partially offset by decreased realized natural gas prices and decreased
domestic oil and condensate production. The average realized price of natural
gas decreased by 5% and the average realized price of oil increased by 21%
for the nine months ended September 30, 1999 compared to the same period of
1998.
For the nine months ended September 30, 1999, the average realized
gas price was $2.20 per Mcf, which, as a result of hedging activities, was
102% of the $2.15 per Mcf average gas sales price that would have otherwise
been received. As a result of hedging activities for gas production for the
nine months ended September 30, 1998, the Company realized an average gas
price of $2.32 per Mcf, or 107% of the $2.16 per Mcf average gas sales price
that would have otherwise been received. For the nine months ended September
30, 1999, the average realized oil and condensate price was $16.08, which,
as a result of hedging activities, was 96% of the $16.76 that would have
otherwise been received. For the nine months ended September 30, 1998, the
average realized oil and condensate price was $13.26 per barrel, which, as
a result of hedging activities, was 101% of the $13.07 per barrel average
oil and condensate price that would have otherwise been received.
Oil and gas revenues for the three months ended September 30, 1999
increased by $33.1 million, or 73%, compared to the same period of 1998.
Included in the 1999 total is $11.0 million in international oil revenues
resulting from the Company's acquisition of Gulf Australia Resources Limited.
The remaining increase is a result of increased domestic gas and oil and
condensate production and higher realized natural gas and oil and condensate
prices. The average realized price of natural gas and oil and condensate
increased by 10% and 64%, respectively, for the three months ended September
30, 1999 compared to the same period in 1998.
12
<PAGE> 15
For the three months ended September 30, 1999, the average realized
natural gas price was $2.42 per Mcf, which, as a result of hedging activities
was 93%, of the $2.60 per Mcf average natural gas sales price that would have
otherwise been received. As a result of hedging activities for gas production
for the three months ended September 30, 1998, the Company realized an average
natural gas sales price of $2.20 per Mcf, which, as a result of hedging
activities, was 109% of the $2.01 per Mcf average natural gas sales price
that would have otherwise been received. For the three months ended September
30, 1999, the average realized oil and condensate price was $20.09 per barrel,
which, as a result of hedging activities, was 93% of the $21.71 per barrel
average oil and condensate price that would have otherwise been received.
There were no oil hedging activities for the three months ended September
30, 1998.
LEASE OPERATING EXPENSE. Lease operating expense for the nine and three month
periods ended September 30, 1999 increased to $30.8 million and $12.0 million,
respectively, from $24.8 million and $8.8 million for the comparable period in
1998. The increase is primarily due to increased domestic operations and the
acquisition of foreign producing properties in Australia. Lease operating
expense per Mcfe for operations in Australia were $1.46 for the three months
ended September 30, 1999. Consolidated lease operating expense per Mcfe
decreased to $0.37 and $0.41 for the nine and three month periods ended
September 30, 1999 from $0.39 and $0.42 for the comparable periods in 1998.
These decreases are primarily attributable to the increases in gas and oil
and condensate production for the nine and three month periods ended
September 30, 1999 as compared to the comparable periods of 1998. Domestic
lease operating expenses per Mcfe were $0.34 and $0.31 for the nine and three
month periods ended September 30, 1999.
PRODUCTION AND OTHER TAXES. Production and other taxes of $1.0 million for
the three and nine months ended September 30, 1999 primarily relates to the
production resource rent tax on the Company's Australian operations which
were acquired during the third quarter of 1999.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. During the nine and
three month periods ended September 30, 1999, depreciation, depletion and
amortization expense increased to $112.2 million and $38.4 million,
respectively, from $87.0 million and $29.3 million, respectively, for the
comparable periods of 1998. The increases were due to increased gas and oil
and condensate production resulting from acquisitions and exploratory and
developmental drilling activity during 1999. The depletion rate per Mcfe
for the nine and three month periods ended September 30, 1999 decreased to
$1.35 and $1.30, respectively, from $1.37 and $1.39, respectively, for the
comparable periods of 1998. The decreases in the depletion rate per unit
are primarily attributable to the non-cash writedown of oil and gas properties
recognized by the Company at December 31, 1998 and the acquisition of foreign
producing properties in Australia that have a significantly lower depletion
rate per Mcfe. The depletion rate per Mcfe for the Company's operations
in Australia was $0.57 for the quarter ended September 30, 1999.
GENERAL AND ADMINISTRATIVE EXPENSE, NET. General and administrative expense,
which is net of overhead reimbursements received by the Company from other
working interest owners, increased to $10.4 million and $4.1 million for the
nine and three month periods ended September 30, 1999, respectively, from
$7.8 million and $2.3 million, respectively, for the comparable periods of
1998 primarily due to direct costs associated with staff increases during 1998
and an increase in performance based compensation in 1999. General and
13
<PAGE> 16
administrative expenses per Mcfe were $0.12 for the nine months ended
September 30 of both 1999 and 1998. General and administrative expense
per Mcfe increased to $0.14 from $0.11 for the three months ended September 30,
1999 compared to the same period in 1998 primarily due to an increase in
performance based compensation. Performance based compensation, as a
component of general and administrative expense, increased from $1.9, or
$0.03 per Mcfe, for the nine month period ended September 30, 1998, to
$2.2 million, or $0.03 per Mcfe, for the nine month period ended September
30, 1999. Performance based compensation, as a component of general and
administrative expense, increased from $0.3 million, or $0.02 per Mcfe,
for the three month period ended September 30, 1998, to $1.2 million, or
$0.04 per Mcfe, for the three month period ended September 30, 1999. To
the extent the Company continues to grow and increase its ownership in
certain properties, the Company expects general and administrative expenses,
in the aggregate, to continue to increase.
INTEREST EXPENSE, NET. Interest expense, net of capitalized interest, for the
nine months ended September 30, 1999 increased to $9.3 million from $7.1
million for the nine months ended September 30, 1998. The increase was due
to higher average debt levels during the first half of 1999 and a lower
percentage of total interest cost being capitalized partially offset by the
Company's issuance of convertible preferred securities in August 1999, the
proceeds of which were used to repay bank debt. Interest expense, net of
capitalized interest, for the three months ended September 30, 1999 decreased
to $2.7 million from $3.2 million for the comparable period of 1998. The
decrease was due to the Company's issuance of convertible preferred securities
in August 1999, the proceeds of which were used to repay bank debt.
DIVIDENDS ON PREFERRED SECURITIES. Dividends on quarterly income preferred
securities of Newfield Financial Trust I totaled $1.2 million for the three and
nine month periods ended September 30, 1999. This amount represents the
accrued dividends on the $144 million of 6.50% convertible preferred securities
issued by the Trust in August 1999.
NET INCOME. As a result of the foregoing, the Company had net income of $16.6
and $12.4, or $0.39 and $0.29 per diluted share, respectively, for the nine
and three month periods ended September 30, 1999, as compared to $11.3 and
$0.9 million, or $0.29 and $0.02 per diluted share, respectively, for the
comparable periods of 1998.
LIQUIDITY AND CAPITAL RESOURCES.
The Company had $29.9 million of working capital at September 30,
1999 compared to a working capital deficit of $8.8 million at December 31,
1998. The $38.7 million increase in working capital is primarily due to excess
cash available from the issuance of convertible preferred securities in August
1999 coupled with higher net cash provided by operating activities during 1999
as compared to 1998. Long-term debt decreased from $208.7 million at December
31, 1998 to $124.7 at September 30, 1999 due to the Company's issuance of
convertible preferred securities in August 1999. A portion of the $143.8
million in proceeds from these securities were used to repay bank debt.
Working capital balances may fluctuate from quarter to quarter to the extent
the Company increases or decreases borrowing under its revolving credit
facility (the "Credit Facility"). The Company has funded its oil and gas
activities through cash flow from operations, equity capital from private
and public sources, public debt and bank borrowings.
14
<PAGE> 17
The Company maintains its reserve-based revolving Credit Facility
with Chase Bank of Texas, National Association, as agent. The Credit Facility
provides a $225 million revolving credit maturing on October 31, 2002. The
amount available under the Credit Facility is subject to a calculated
borrowing base determined by a majority of the banks participating in the
Credit Facility, which is reduced by the aggregate principal outstanding on
the Company's senior unsecured notes (currently $125 million) (as so reduced,
the "Borrowing Base"). The Borrowing Base is re-determined at least
semi-annually. The Borrowing Base is currently $300 million, but no assurance
can be given that a majority of the banks will not elect to re-determine the
Borrowing Base in the future. The Company has an option, subject to the
Borrowing Base, to increase the Facility to $250 million. As of October 29,
1999, there were no amounts outstanding under the Credit Facility.
The Company has also established money market lines of credit with
various banks in an amount limited by the Credit Facility to $25 million.
As of October 29, 1999, there were no amounts outstanding under these lines
of credit.
At October 29, 1999, the Company had $200 million of available
borrowings under the Credit Facility and money market lines.
The Company's net cash flow from operations for the first nine
months of 1999 was $133.3 million compared to $124.5 million for the same
period of 1998. The increase is primarily due to increased gas and oil and
condensate production, higher realized oil and condensate prices and lower
per unit operating costs, partially offset by a slight decrease in realized
natural gas prices and changes in operating assets and liabilities.
Capital expenditures for the nine months ended September 30, 1999
were $156.6 million, consisting of $29.4 million for exploration, $43.7
million for development and $83.5 million for property acquisitions. The
Company has budgeted $225 million for capital spending in 1999. Of that
amount, $70 million has been allocated to exploration projects, $60 million
has been allocated to identified development drilling projects and the
construction of platforms, facilities and pipelines, (including $7 million
for abandonment or dismantlement of existing wells and facilities), and
$90 million to specifically identified proved property acquisitions and
$5 million to international activities, including the recently completed
$23 million purchase of Gulf Australia. The Company continues to pursue
attractive acquisition opportunities. The timing and size of any acquisition
and the associated capital commitments are unpredictable.
Actual levels of capital expenditures may vary significantly due
to many factors, including drilling results, oil and gas prices, industry
conditions, the prices and availability of goods and services and the extent
to which proved properties are acquired. The Company anticipates that these
capital expenditures will be funded principally from cash flow from
operations, working capital and bank borrowings. During the first nine
months of 1999, the Company borrowed $443 million and repaid $527 million
15
<PAGE> 18
under the Credit Facility and its money market lines of credit and realized
proceeds of $143.8 million through the issuance of convertible preferred
securities. The Company does not anticipate additional borrowings under
the Credit Facility and its money market lines of credit during the remainder
of 1999.
The Company has been named as a defendant in certain lawsuits
arising in the ordinary course of business. While the outcome of these
lawsuits cannot be predicted with certainty, management does not expect
these matters to have a material adverse effect on the financial position,
results of operations or cash flows of the Company.
HEDGING
From time to time, the Company has utilized and expects to continue
to utilize hedging transactions with respect to a portion of its oil and gas
production to achieve a more predictable cash flow, as well as to reduce its
exposure to price fluctuations. 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. Substantially all of the Company's hedging
transactions to date were carried out in the over-the-counter market with
investment grade institutions. The Company accounts for these transactions as
hedging activities and, accordingly, gains or losses are included in oil and
gas revenues when the hedged production is delivered. Neither the hedging
contract nor the unrealized gains and losses on these contracts are recognized
in the financial statements.
As of October 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its 1999 and 2000 natural gas production as
follows:
<TABLE>
<CAPTION>
Swaps Collars Floor Contracts
-------------------------- ------------------------------- --------------------------
Weighted NYMEX Weighted
Average Contract Price Average
NYMEX per MMBtu NYMEX
Volume in Contract Price Volume in ------------------- Volume in Contract Price
Period MMMBtu per MMBtu MMMBtus Floors Ceilings MMMBtus per MMBtu
- ------------------------------- --------- -------------- --------- ------ -------- --------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 1999 .................. 3,510 $2.62 350 $2.38 $3.01 1,000 $2.55
November 1999 ................. 1,610 $2.74 2,000 $2.53-$2.68 $3.10-$3.14 --- ---
December 1999 ................. 1,610 $2.88 500 $2.55 $3.25-$3.32 1,500 $2.67
January 2000 - December 2000 .. 17,500 $2.56 250 $2.63 $3.25 4,700 $2.57
</TABLE>
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or,
occasionally, the penultimate trading day of a particular contract month. With
respect to any particular swap transaction, the counterparty is required to
make a payment to the Company in the event that the settlement price for any
settlement period is less than the swap price for such transaction, and the
16
<PAGE> 19
Company is required to make payment to the counterparty in the event that the
settlement price for any settlement period is greater than the swap price for
such transaction. For any particular collar transaction, the 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 for such transaction. For
any particular floor 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. The Company is not required to make
any payment in connection with the settlement of a floor transaction.
The Company believes that it has no material basis risk with respect
to gas swaps because substantially all of the Company's natural gas production
is sold under spot contracts that have historically correlated with the swap
price.
As of October 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1999 and 2000 as
follows:
<TABLE>
<CAPTION>
Swaps Collars Floor Contracts
------------------------- ----------------------------------- ---------------------------
Weighted NYMEX Weighted
Average Contract Price Average
NYMEX per Bbl NYMEX
Volume in Contract Price Volume in ------------------------ Volume in Contract Price
Period Bbls per Bbl Bbls Floors Ceilings Bbls per Bbl
- ------------------------------- --------- -------------- --------- ----------- ---------- ----------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
October 1999 .................. 124,000 $21.40 62,000 $15.00-$18.28 $17.00-$21.00 31,000 $19.82
November 1999 ................. 120,000 $21.40 60,000 $15.00-$18.28 $17.00-$21.00 30,000 $19.82
December 1999 ................. 124,000 $21.40 62,000 $15.00-$18.28 $17.00-$21.00 31,000 $19.82
January 2000 - March 2000 ..... 182,000 $21.07 182,000 $18.28-$19.50 $20.10-$21.00 91,000 $19.32
April 2000 - September 2000 ... --- --- 274,000 $18.28-$19.50 $20.10-$21.00 --- ---
</TABLE>
Because substantially all of the Company's oil production is sold
under spot contracts that correlate to the NYMEX West Texas Intermediate price,
the Company believes that it has no material Basis Risk with respect to these
transactions. The actual cash price the Company receives however, generally is
$1.50 - $2.00 per barrel less than the NYMEX West Texas Intermediate price when
adjusted for location and quality differences.
17
<PAGE> 20
YEAR 2000 ISSUES
Year 2000 issues result from the inability of computer programs or
equipment to accurately calculate, store or use a date subsequent to December
31, 1999. The erroneous date can be interpreted in a number of different ways;
typically the year 2000 is interpreted as the year 1900. This could result in a
system failure or miscalculations causing disruptions of operations, including,
among other things, a temporary inability to process transactions, send
invoices or engage in similar normal business.
Because the Company's software systems are relatively new, the Company
was aware of and considered Year 2000 issues at the time of purchase or
development of its software systems. In addition, the Company has recently
completed an assessment of its core financial and operational software systems
to ensure compliance. The licensor of the Company's core financial software
system has certified that such software is Year 2000 compliant. Additionally,
other less critical software systems and various types of equipment have been
assessed and are believed to be compliant. The Company believes that the
potential impact, if any, of these less critical systems not being Year 2000
compliant will at most require employees to manually complete otherwise
automated tasks or calculations and it should not impact the Company's ability
to continue exploration, drilling, production or sales activities.
The Company recently completed an assessment of its operated domestic
offshore platforms and facilities for Year 2000 sensitive components. Company
owned and operated equipment on platforms and facilities that account for 55%
and 80% of the Company's operated domestic offshore natural gas and oil
production, respectively, were surveyed by third party professionals and
in-service components appear to be Year 2000 compliant. Based upon the results
of this assessment and a review of Company and third party files, platforms and
facilities accounting for an additional 29% and 4% of the Company's operated
domestic offshore natural gas and oil production, respectively, appear not to
have Year 2000 sensitive equipment.
The Company has initiated and will continue to have formal
communications with its significant suppliers, business partners and customers
to determine the extent to which the Company is vulnerable to those third
parties' failure to correct their own Year 2000 issues. There can be no
assurance, however, that the systems of other companies on which the Company's
systems rely will be timely converted, or that a failure to convert by another
company, or a conversion that is incompatible with the Company's systems would
not have a material adverse effect on the Company. The Company has determined
it has no exposure to contingencies related to the Year 2000 issue with respect
to products sold to third parties.
The Company has and will utilize both internal and external resources
to complete tasks and perform testing necessary to address Year 2000 issues.
The Company has substantially completed the Year 2000 project. The Company has
not incurred, and does not anticipate that it will incur, any significant costs
relating to the assessment and remediation of Year 2000 issues.
18
<PAGE> 21
Certain business information systems in the recently acquired offices
of the Company in Perth, Australia are not Year 2000 compliant. Software
products that are not Year 2000 compliant can, and will be, upgraded with a
Year 2000 compliant version. The cost of upgrades is not expected to be
material. The floating production storage and offloading vessels (FPSOs) in the
Jabiru and Challis oil fields have undergone extensive Year 2000 compliance
evaluation. Business contingency plans have been developed for non-compliant
elements of the FPSO operations. The Company does not anticipate an
interruption in oil production in these fields as a result of Year 2000 issues.
FORWARD LOOKING INFORMATION
Certain of the statements set forth in this document regarding planned
capital expenditures and activities are forward looking and are based upon
assumptions and anticipated results that are subject to numerous uncertainties.
Actual results may vary significantly from those anticipated due to many
factors, including drilling results, oil and gas prices, industry conditions,
the prices of goods and services, the availability of drilling rigs and other
support services and the availability of capital resources. In addition, the
drilling of oil and gas wells and the production of hydrocarbons are subject to
governmental regulations and operating risks.
OIL AND GAS TERMS
Set forth below are definitions of certain terms used in the oil and
gas business.
<TABLE>
<S> <C>
Basis Risk. The risk associated with the sales point price for oil or
gas production varying from the reference (or settlement) price
for a particular hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined by using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees to
59.5 degrees Fahrenheit.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
19
<PAGE> 22
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.
</TABLE>
20
<PAGE> 23
PART II
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
10.1 Second Amendment to Amended and Restated Credit Agreement
dated as of August 6, 1999 among Newfield Exploration
Company as the Company, and The Chase Manhattan Bank
as Agent, and the Bank's signatory thereto (without
Exhibits)
27 Financial Data Schedule (included only in the electronic
filing of this document)
(b) Reports on Form 8-K:
On August 13, 1999, the Company filed a Current Report on
Form 8-K reporting that Newfield Exploration Company, Newfield
Financial Trust I and Newfield Financial Trust II had entered
into an Underwriting Agreement and a Pricing Agreement covering
the issue and sale by the Trust of up to 2,875,000 6-1/2%
Quarterly Income Convertible Preferred Securities.
On August 16, 1999, the Company filed a Current Report on
Form 8-K reporting the acquisition of interests in the Gulf of
Mexico and the offering of $125 million of cumulative quarterly
income convertible preferred securities.
21
<PAGE> 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: November 2, 1999 By: /s/ TERRY W. RATHERT
------------------------------------
Terry W. Rathert
Vice President-Planning and
Administration and Secretary
(Authorized Officer and Principal
Financial Officer)
22
<PAGE> 25
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description of Exhibits
------- -----------------------
<S> <C>
10.1 Second Amendment to Amended and Restated Credit Agreement
dated as of August 6, 1999 among Newfield Exploration
Company as the Company, and The Chase Manhattan Bank
as Agent, and the Bank's signatory thereto (without
Exhibits)
27 Financial Data Schedule (included only in the electronic
filing of this document)
</TABLE>
<PAGE> 1
SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
THIS SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this
"Amendment") dated as of August 6, 1999 is among: NEWFIELD EXPLORATION
COMPANY, a corporation formed under the laws of the State of Delaware (the
"Company"); each of the lenders that is a signatory hereto; and CHASE BANK OF
TEXAS, NATIONAL ASSOCIATION (in its individual capacity, "Chase"), as agent
for the Banks (in such capacity, together with its successors in such
capacity, the "Agent").
R E C I T A L S
A. The Company, the Agent, and the Banks (as defined in the Credit
Agreement as hereafter defined) have entered into that certain Amended and
Restated Credit Agreement dated as of October 9, 1997 as amended by the First
Amendment to Amended and Restated Credit Agreement dated as of August 20,
1998 (as amended, the "Credit Agreement"), pursuant to which the Banks have
agreed to make certain loans and extensions of credit to the Company upon the
terms and conditions as provided therein; and
B. The Company, the Agent, and the Banks now desire to make certain
amendments to the Credit Agreement.
NOW, THEREFORE, in consideration of the premises and other good and
valuable consideration and the mutual benefits, covenants and agreements
herein expressed, the parties hereto now agree as follows:
1. All capitalized terms used in this Amendment and not otherwise
defined herein shall have the meanings ascribed to such terms in the Credit
Agreement.
2. Section 1.02 of the Credit Agreement is hereby supplemented, where
alphabetically appropriate, with the addition of the following definitions:
"QUIPS" shall mean the 6.50% Cumulative Quarterly Income
Convertible Preferred Securities, Series A issued or to be issued
by the QUIPS Trust for an aggregate liquidation preference
amount not to exceed $144,000,000.
"QUIPS Debentures" shall mean the 6.50% Junior Subordinated
Convertible Debentures, Series A due 2029 issued by the Company
to the QUIPS Trust in an aggregate principal amount not to
exceed $149,000,000.
"QUIPS Guaranty" shall mean the Company's guarantee of the
payment of the distributions on and redemption of the QUIPS.
"QUIPS Trust" shall mean Newfield Financial Trust I, a
Delaware business trust and Subsidiary of the Company.
<PAGE> 2
"Second Amendment" shall mean that certain Second Amendment
to Amended and Restated Credit Agreement dated as of August 6,
1999, among the Company, the Banks and the Agent.
3. Section 9.01 of the Credit Agreement is hereby amended by adding
the following clause (l):
"(l) The QUIPS Debentures, the QUIPS and the QUIPS Guaranty."
4. Section 9.04 of the Credit Agreement is hereby amended by adding the
following sentence:
"Payment of interest on the QUIPS Debentures and payment of
distributions on the QUIPS shall not be subject to the terms
of this Section 9.04."
5. The Credit Agreement is hereby amended by adding the following
Section:
"9.22 QUIPS. The Company and its Subsidiaries will not
modify or amend the terms of the indenture under which the QUIPS
Debentures are issued and any related documents without the
consent of the Majority Banks, if the effect of such modification
or amendment would be to shorten the maturity to less than August
13, 2009 on any QUIPS Debentures, increase the aggregate principal
amount of the QUIPS Debentures above $149,000,000, increase the
rate of interest on any QUIPS Debenture or change the method of
calculating interest so as to effectively increase the rate of
interest on any QUIPS Debenture, change any of the provisions of
subordination, the covenants and events of default and any of
the definitions used in or relating thereto, or any other
provisions which would detrimentally effect the rights of the
Banks. The Company and its Subsidiaries will not modify or
amend the terms of the QUIPS or the QUIPS Trust and any related
documents, including without limitation, the QUIPS Guaranty,
without the consent of the Majority Banks, if the effect of
such modification or amendment would be to shorten the maturity
to less than August 13, 2009 on any QUIPS, issue additional QUIPS
above $144,000,000 in the aggregate for the liquidation preference
amount for all QUIPS outstanding, increase the distribution rate
on any QUIPS or change the method of calculating the distribution
rate so as to effectively increase the distribution rate on any
QUIPS, change any of the provisions of subordination, the
covenants and events of default and any of the definitions used
in or relating thereto, or any other provisions which would
detrimentally effect the rights of the Banks."
6. This Amendment shall become binding on the Banks when, and only
when, the Agent shall have received or have been satisfied with each of the
following in form and substance satisfactory to the Agent or its counsel:
(a) counterparts of this Amendment executed by the Company
and the Majority Banks; and
<PAGE> 3
(b) the terms and provisions of the QUIPS Trust, the QUIPS,
the QUIPS Debentures (including the indentures under which they
are issued) and the QUIPS Guaranty as of the date of their
effectiveness will not be materially more detrimental to the
Banks than as set forth in the Prospectus of the Company dated
September 4, 1998 as supplemented by the Prospectus Supplement
dated August 6, 1999.
7. The parties hereto hereby acknowledge and agree that, except as
specifically supplemented and amended, changed or modified hereby, the Loan
Documents shall remain in full force and effect in accordance with its terms.
8. The Company hereby reaffirms that as of the date of this Amendment,
the representations and warranties contained in Article VII of the Credit
Agreement are true and correct on the date hereof as though made on and as of
the date of this Amendment, except as such representations and warranties are
expressly limited to an earlier date.
9. THIS AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND
ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH,
THE LAWS OF THE STATE OF NEW YORK.
10. This Amendment may be executed in two or more counterparts, and it
shall not be necessary that the signatures of all parties hereto be contained
on any one counterpart hereof; each counterpart shall be deemed an original,
but all of which together shall constitute one and the same instrument.
Delivery of an executed signature page of this Amendment by facsimile
transmission shall be effective as delivery of a manually executed counterpart
hereof.
[SIGNATURES BEGIN NEXT PAGE]
<PAGE> 4
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed as of date first above written.
NEWFIELD EXPLORATION COMPANY
By: /s/ TERRY W. RATHERT
Name: Terry W. Rathert
Title: Vice President
Planning and Administration
CHASE BANK OF TEXAS, NATIONAL ASSOCIATION,
individually and as Agent
By: /s/ RUSSELL A. JOHNSON
Name: Russell A. Johnson
Title: Vice President
BANK OF MONTREAL
By: /s/ MELISSA BAUMAN
Name: Melissa Bauman
Title: Director
CREDIT LYONNAIS NEW YORK BRANCH
By: /s/ PHILIPPE SOUSTRA
Name: Philippe Soustra
Title: Senior Vice President
FIRST UNION NATIONAL BANK
By: /s/ ROBERT R. WETTEROFF
Name: Robert R. Wetteroff
Title: Senior Vice President
BANK OF AMERICA, N.A., formerly
NationsBank, N.A.
By: /s/ JAMES V. DUCOTE
Name: James V. Ducote
Title: Vice President
SOCIETE GENERALE
SOUTHWEST AGENCY
By: /s/ PAUL E. CORNELL
Name: Paul E. Cornell
Title: Managing Director
<PAGE> 5
BANKBOSTON, N.A.
By: /s/ TERRENCE RONAN
Name: Terrence Ronan
Title: Director
HIBERNIA NATIONAL BANK
By: /s/ DAVID R. REID
Name: David R. Reid
Title: Senior Vice President
BANK ONE, TEXAS, NA
By: /s/ THOMAS OKAMOTO
Name: Thomas Okamoto
Title: Vice President
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NEWFIELD
EXPLORATION COMPANY'S BALANCE SHEET AT SEPTEMBER 30, 1999 AND STATEMENT OF
INCOME FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999, THAT ARE CONTAINED IN ITS
FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999. THE SCHEDULE IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 30,425
<SECURITIES> 0
<RECEIVABLES> 42,777
<ALLOWANCES> 0
<INVENTORY> 9,234
<CURRENT-ASSETS> 85,526
<PP&E> 1,149,224
<DEPRECIATION> 525,914
<TOTAL-ASSETS> 719,030
<CURRENT-LIABILITIES> 55,669
<BONDS> 124,672
<COMMON> 265,648
0
143,750
<OTHER-SE> 90,180
<TOTAL-LIABILITY-AND-EQUITY> 719,030
<SALES> 191,725
<TOTAL-REVENUES> 191,725
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 144,069
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,492
<INCOME-PRETAX> 26,044
<INCOME-TAX> 9,434
<INCOME-CONTINUING> 16,610
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 16,610
<EPS-BASIC> 0.40
<EPS-DILUTED> 0.39
</TABLE>
