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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-------------------------------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 July 29, 1999, there were 41,482,069 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
PART I
<S> <C>
Item 1. Financial Statements:
Consolidated Balance Sheet as of June 30,
1999 and December 31, 1998...............................1
Consolidated Statement of Income for the three months ended
June 30, 1999 and 1998 and for the six months ended
June 30, 1999 and 1998...................................2
Consolidated Statement of Cash Flows for the
six months ended June 30, 1999
and 1998.................................................3
Notes to Financial Statements...................................4
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................7
PART II
Item 4. Submission of Matters to a Vote of Security Holders..............18
Item 6. Exhibits and Reports on Form 8-K.................................19
</TABLE>
ii
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS OF DOLLARS, EXCEPT SHARE DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
----------- -----------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents ............................... $ 3,681 $ 92
Accounts receivable, oil and gas ........................ 32,255 43,095
Other ................................................... 3,657 2,082
----------- -----------
Total current assets ................................. 39,593 45,269
----------- -----------
Oil and gas properties (full cost method, of which $34,371
at June 30, 1999 and $34,234 at December 31,
1998 were excluded from amortization) ................... 1,040,715 992,629
Less-accumulated depreciation, depletion and amortization ... (487,715) (414,206)
----------- -----------
553,000 578,423
----------- -----------
Furniture, fixtures and equipment, net ...................... 2,422 2,208
Other assets ................................................ 3,143 3,411
----------- -----------
Total assets ......................................... $ 598,158 $ 629,311
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities ................ $ 32,291 $ 52,123
Advances from joint owners .............................. 2,967 1,952
----------- -----------
Total current liabilities ........................ 35,258 54,075
----------- -----------
Other liabilities ........................................... 9,995 11,467
Long-term debt .............................................. 184,664 208,650
Deferred taxes .............................................. 27,899 31,171
----------- -----------
Total long-term liabilities .......................... 222,558 251,288
----------- -----------
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; 41,389,899 and
40,429,729 shares issued and outstanding at
June 30, 1999 and December 31, 1998, respectively) ... 414 404
Additional paid-in capital .................................. 261,939 250,642
Unearned compensation ....................................... (4,125) (5,007)
Retained earnings ........................................... 82,114 77,909
----------- -----------
Total stockholders' equity ........................... 340,342 323,948
----------- -----------
Total liabilities and stockholders' equity ........... $ 598,158 $ 629,311
=========== ===========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
1
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oil and gas revenues ....................... $ 60,072 $ 49,902 $ 112,986 $ 99,884
--------- --------- --------- ---------
Operating expenses:
Lease operating ............................ 9,472 8,584 18,767 16,052
Depreciation, depletion and amortization ... 37,060 30,377 73,850 57,749
General and administrative, net ............ 3,193 2,583 6,256 5,494
Stock compensation ......................... 461 573 991 1,108
--------- --------- --------- ---------
Total operating expenses .............. 50,186 42,117 99,864 80,403
--------- --------- --------- ---------
Income from operations ......................... 9,886 7,785 13,122 19,481
Other income (expense):
Other income ............................... 140 287 288 612
Interest expense, net ...................... (3,124) (2,224) (6,649) (3,877)
--------- --------- --------- ---------
(2,984) (1,937) (6,361) (3,265)
--------- --------- --------- ---------
Income before income taxes ..................... 6,902 5,848 6,761 16,216
Income tax provision ........................... 2,527 2,076 2,556 5,732
--------- --------- --------- ---------
Net income ..................................... $ 4,375 $ 3,772 $ 4,205 $ 10,484
========= ========= ========= =========
Basic earnings per common share ................ $ 0.11 $ 0.10 $ 0.10 $ 0.29
========= ========= ========= =========
Diluted earnings per common share .............. $ 0.10 $ 0.10 $ 0.10 $ 0.27
========= ========= ========= =========
Weighted average number of shares
outstanding for basic earnings per share ....... 41,078 36,175 40,796 36,113
========= ========= ========= =========
Weighted average number of shares
outstanding for diluted earnings per share ..... 42,221 38,348 41,967 38,316
========= ========= ========= =========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
2
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
----------------------
1999 1998
---------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income ..................................................... $ 4,205 $ 10,484
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization ..................... 73,850 57,749
Deferred taxes ............................................... 2,556 5,732
Stock compensation ........................................... 991 1,108
--------- ---------
81,602 75,073
Changes in operating assets and liabilities:
Decrease in accounts receivable, oil and gas ................. 10,840 17,060
(Increase) decrease in other current assets .................. (1,575) 3
Decrease in other assets ..................................... 268 140
Decrease in accounts payable and accrued liabilities ......... (16,172) (14,772)
Increase in advance from joint owners ........................ 1,015 3,603
Increase (decrease) in other liabilities ..................... (1,458) 812
--------- ---------
Net cash provided by operating activities .................. 74,520 81,919
--------- ---------
Cash flows from investing activities:
Additions to oil and gas properties .......................... (51,746) (141,789)
Additions to furniture, fixtures and equipment ............... (556) (647)
--------- ---------
Net cash used in investing activities ...................... (52,302) (142,436)
--------- ---------
Cash flows from financing activities:
Proceeds from borrowings ..................................... 190,000 187,750
Repayments of borrowings ..................................... (214,000) (125,750)
Proceeds from issuance of common stock, net .................. 5,371 478
--------- ---------
Net cash provided by (used in) financing activities ........ (18,629) 62,478
--------- ---------
Increase in cash and cash equivalents ............................... 3,589 1,961
Cash and cash equivalents, beginning of period ...................... 92 8,217
--------- ---------
Cash and cash equivalents, end of period ............................ $ 3,681 $ 10,178
========= =========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
3
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NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(1) ACCOUNTING POLICIES
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 June 30, 1999 and the Company's consolidated results of operations
for the three and six month periods ended June 30, 1999 and 1998 and
consolidated cash flows for the six month periods ended June 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 period.
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.
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.
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 six month periods
ended June 30, 1999 and 1998, respectively:
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Shares outstanding for basic EPS ................ 41,078,007 36,174,893 40,796,377 36,112,769
Dilutive effect of stock options
outstanding at end of period .............. 1,142,775 2,173,343 1,171,002 2,203,593
---------- ---------- ---------- ----------
Shares outstanding for diluted EPS .............. 42,220,782 38,348,236 41,967,379 38,316,362
========== ========== ========== ==========
</TABLE>
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
4
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NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(UNAUDITED)
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.
(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 unforseen
environmental incidents will not occur or past non-compliance with environment
laws will not be discovered.
(3) SUBSEQUENT EVENTS
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. On July 26, 1999, the Company announced it had entered into an agreement
with Ocean Energy, Inc. to acquire the interests of Ocean Energy in three Gulf
of Mexico fields for approximately $66 million. This transaction is expected to
close by mid-August 1999. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Recent Developments" and "-Year 2000
Issues."
5
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NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(UNAUDITED)
As of July 28, 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 June 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>
July 1999 ....................... 2,060 $2.26 2,000 $2.05-$2.10 $2.40-$2.50 --- ---
August 1999 ..................... 2,710 $2.36 2,000 $2.05-$2.10 $2.40-$2.50 --- ---
September 1999 .................. 2,710 $2.37 2,000 $2.05-$2.10 $2.40-$2.50 --- ---
October 1999 - December 1999 .... 1,680 $2.51 --- --- --- 5,350 $2.59
January 2000 - February 2000 .... --- --- --- --- --- 1,150 $2.73
January 2000 - December 2000 .... 6,800 $2.41 --- --- --- --- ---
</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>
July 1999 ....................... 93,000 $17.48 93,000 $14.00-$17.00 $15.25-$19.15 --- ---
August 1999 ..................... 62,000 $17.93 93,000 $14.00-$17.00 $15.25-$19.15 --- ---
September 1999 .................. 90,000 $18.54 90,000 $15.00-$18.28 $17.00-$21.00 --- ---
October 1999 - December 1999 .... 92,000 $19.77 184,000 $15.00-$18.28 $17.00-$21.00 92,000 $19.82
January 2000 - March 2000 ....... --- --- --- --- --- 91,000 $19.32
January 2000 - September 2000 ... --- --- 274,000 $18.28 $21.00 --- ---
</TABLE>
6
<PAGE> 9
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. Statement No. 133 will become effective
for the Company on January 1, 2001. The Company is currently evaluating the
impact of this statement.
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.
7
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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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------- --------------------
1999 1998 1999 1998
------- -------- -------- --------
<S> <C> <C> <C> <C>
Production:
Oil and condensate (MBbls) .................. 802 975 1,710 1,905
Gas (MMcf) .................................. 22,206 16,545 43,300 31,032
Total production (MMcfe) .................... 27,019 22,393 53,561 42,460
Average Realized Price:
Oil and condensate (per Bbl) ................ $ 15.02 $ 12.84 $ 13.03 $ 13.69
Gas (per Mcf) ............................... 2.17 2.27 2.10 2.38
Average Costs (per Mcfe):
Lease operating ............................. $ 0.35 $ 0.38 $ 0.35 $ 0.38
Depreciation, depletion and amortization..... 1.37 1.36 1.38 1.36
General and administrative, net ............. 0.12 0.12 0.12 0.13
</TABLE>
PRODUCTION. Net production increased 26%, from 42.5 Bcfe for the six
months ended June 30, 1998 to 53.6 Bcfe for the six months ended June 30, 1999.
Oil and condensate production for the six months ended June 30, 1999 decreased
195 MBbls, or 10%, compared to the same period of 1998. Decreased oil
production for the first six months of 1999 was due primarily to well downtime
at Vermilion 398 and South Timbalier 148 and natural decline on other
properties of the Company. These decreases were partially offset by production
increases from development wells that were placed on production during mid-
1998 at Ship Shoal 354 and High Island 537. Gas production increased by 12.3
Bcf, or 40%, from 31.0 Bcf for the six months ended June 30, 1998 to 43.3 Bcf
for the comparable period of 1999. Increased gas production was due to
production increases from drilling activities at East Cameron 373, East Cameron
286 and South Marsh Island 141. These increases were partially offset by
natural production decline on other properties of the Company.
Net production increased 21%, from 22.4 Bcfe for the three months
ended June 30, 1998 to 27.0 Bcfe for the three months ended June 30, 1999. Oil
and condensate production for the three months ended June 30, 1999 decreased
173 MBbls, or 18%, compared to the same period of 1998. Decreased oil
production was due primarily to well downtime at Vermilion 398, South Timbalier
148 and Ship Shoal 157 and the sale of Eugene Island 128 in the second quarter
of 1999. Gas production increased by 5.7 Bcf, or 34%, from 16.5 Bcf for the
three months ended June 30, 1998 to 22.2 Bcf for the comparable period of 1999.
Increased gas production was due to production increases from drilling
activities at East Cameron 373, East Cameron 286 and Main Pass 256.
OIL AND GAS REVENUES. Oil and gas revenues for the six months ended
June 30, 1999 increased by $13.1 million, or 13%, compared to the same period
of 1998, primarily as a result of increased gas production partially offset by
lower realized natural gas and oil and condensate prices and decreased oil and
condensate production. The average realized price of natural gas and oil and
condensate before hedging activities decreased by 14% and 3%, respectively, for
the six months ended June 30, 1999 compared to the same period of 1998.
8
<PAGE> 11
For the six months ended June 30, 1999, the average realized gas price
was $2.10 per Mcf, which, as a result of hedging activities, was 109% of the
$1.93 per Mcf average gas sales price that would have otherwise been received.
As a result of hedging activities for gas production for the six months ended
June 30, 1998, the Company realized an average gas price of $2.38 per Mcf, or
106% of the $2.24 per Mcf average gas sales price that would have otherwise
been received. Oil and condensate hedging activities for the six months ended
June 30, 1999 had a negligible impact on revenues. For the six months ended
June 30, 1998, the average realized oil and condensate price was $13.69 per
barrel, which, as a result of hedging activities, was 102% of the $13.41 per
barrel average oil and condensate sales price that would have otherwise been
received.
Oil and gas revenues for the three months ended June 30, 1999
increased by $10.2 million, or 20%, compared to the same period of 1998,
primarily as a result of increased gas production and higher realized oil and
condensate prices offset by lower realized natural gas prices. The average
realized price of oil and condensate increased by 17% for the three months
ended June 30, 1999 compared to the same period of 1998.
For the three months ended June 30, 1999, the average realized gas
price was $2.17 per Mcf, which, as a result of hedging activities, was 101% of
the $2.16 per Mcf average gas sales price that would have otherwise been
received. As a result of hedging activities for gas production for the three
months ended June 30, 1998, the Company realized an average gas price of $2.27
per Mcf, or 101% of the $2.24 per Mcf average gas sales price that would have
otherwise been received. For the three months ended June 30, 1999, the average
realized oil and condensate price was $15.02 per barrel, which, as a result of
hedging activities, was 96% of the $15.57 per barrel average oil and condensate
sales price that would have otherwise been received. For the three months ended
June 30, 1998, the average realized oil and condensate price was $12.84 per
barrel, which, as a result of hedging activities, was 102% of the $12.56 per
barrel average oil and condensate sales price that would have otherwise been
received.
LEASE OPERATING EXPENSE. Lease operating expense for the six and three
month periods ended June 30, 1999 increased to $18.8 million and $9.5 million,
respectively, from $16.1 million and $8.6 million, respectively, for the
comparable periods of 1998. The increases in lease operating expenses are due
primarily to increased operations and property acquisitions. Lease operating
expense per Mcfe decreased from $0.38 for the six and three month periods ended
June 30, 1998 to $0.35 for the comparable periods of 1999. These decreases are
primarily attributable to the increase in gas production for the six and three
month periods ended June 30, 1999 as compared to the comparable periods of 1998.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. During the six and
three month periods ended June 30, 1999, depreciation, depletion and
amortization expense increased to $73.9 million and $37.1 million,
respectively, from $57.7 million and $30.4 million, respectively, for the
comparable periods of 1998. The increases were the result of an
9
<PAGE> 12
increased depletion rate per Mcfe combined with production increases from
acquisitions and exploratory and development drilling activities during 1998.
The depletion rate per unit for the six and three month periods ended June 30,
1999 increased to $1.38 and $1.37 per Mcfe, respectively, from $1.36 per Mcfe
for the comparable periods of 1998. The increases in the depletion rate per
unit are primarily attributable to increased costs of drilling goods and
services, platforms and facilities construction and transportation services in
the industry that were experienced during 1998, partially offset by the
non-cash writedown of oil and gas properties recognized by the Company at
December 31, 1998.
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 $6.3 million and $3.2 million, for
the six and three month periods ended June 30, 1999, respectively from $5.5
million and $2.6 million, respectively, for the comparable periods of 1998.
General and administrative expense increased primarily as a result of direct
costs associated with staff increases during 1998. General and administrative
expenses per unit decreased from $0.13 per Mcfe for the six month period ended
June 30, 1998, to $0.12 per Mcfe for the comparable period of 1999 due primarily
to increased natural gas production during 1999. To the extent that 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. Performance based compensation, as a component of general and
administrative expense, decreased from $1.6 million, or $0.04 per Mcfe, for the
six month period ended June 30, 1998, to $1.0 million, or $0.02 per Mcfe, for
the six month period ended June 30, 1999. Performance based compensation, as a
component of general and administrative expense, increased from $0.7 million, or
$0.03 per Mcfe, for the three month period ended June 30, 1998, to $0.8 million,
or $0.03 per Mcfe, for the three month period ended June 30, 1999.
INTEREST EXPENSE NET. Interest expense, net of capitalized interest,
for the six and three months ended June 30, 1999 increased to $6.6 million and
$3.1 million, respectively, from $3.9 million and $2.2 million, respectively,
for the comparable periods of 1998. The increase was attributable to higher
average debt levels during the first half of 1999 and a lower percentage of
total interest cost being capitalized.
NET INCOME. As a result of the foregoing, the Company had net income of
$4.2 million and $4.4 million, or $0.10 per diluted share, respectively, for the
six and three month periods ended June 30, 1999, as compared to $10.5 million
and $3.8 million, or $0.27 and $0.10 per diluted share, respectively, for the
comparable periods of 1998.
LIQUIDITY AND CAPITAL RESOURCES
The Company had $4.3 million of working capital at June 30, 1999
compared to a working capital deficit of $8.8 million at December 31, 1998. The
$13.1 million increase in working capital is primarily due to decreased
drilling activity during 1999. Long-term debt decreased from $208.7 million at
December 31, 1998 to $184.7 million at June 30, 1999. Working capital balances
may fluctuate from quarter to quarter to the extent the Company increases or
decreases borrowings 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.
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<PAGE> 13
The Company maintains its reserve-based revolving Credit Facility with
Chase Bank of Texas, National Association, as agent. As of June 30, 1999, $60
million was outstanding under the Credit Facility. 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 redetermined at least semi-annually. The Borrowing Base is
currently $150 million, but no assurances can be given that a majority of the
banks will not elect to redetermine the Borrowing Base in the future. The
Company has an option, subject to the Borrowing Base, to increase the facility
to $250 million. At July 30, 1999 the Company had $69 million outstanding under
the Credit Facility. The Company anticipates an increase in the Borrowing Base
at the next scheduled redetermination in the fourth quarter of 1999 as a result
of its recent Australian acquisition and, assuming completion, of its pending
Gulf of Mexico proved property acquisitions. See "-- Recent Developments."
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
July 30, 1999, there was $3 million outstanding under these lines of credit.
At July 30, 1999, the Company had $103 million of available borrowings
under the Credit Facility and money market lines. This capacity is sufficient
to complete the contemplated acquisitions described under "-- Recent
Developments."
The Company's net cash flow from operations for the first six months
of 1999 was $74.5 million compared to $81.9 million for the same period of
1998. The decrease is primarily due to decreased average realized oil and gas
prices and higher operating expenses and changes in operating assets and
liabilities. Net cash flow from operations before changes in operating assets
and liabilities for the first six months of 1999 was $81.6 million compared to
$75.1 million for the same period of 1998. The increase in net cash flow from
operations before changes in operating assets and liabilities is primarily
attributable to increases in gas production offset by decreased average
realized natural gas and oil and condensate prices and higher operating
expenses.
Capital expenditures for the six months ended June 30, 1999 were $48.1
million, consisting of $19.2 million for exploration, $22.3 million for
development and $6.6 million for property acquisitions. The Company has budgeted
$200 million for capital spending in 1999. Of that amount, $54 million has been
allocated to exploration projects, $58 million has been allocated to identified
development drilling projects and the construction of platforms, facilities and
pipelines, (including $5 million for abandonment or dismantlement of existing
wells and facilities), and $61 million to specifically identified proved
property acquisitions and $27 million to international activities, including the
$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 six months of 1999, the
Company borrowed $190.0 million and repaid $214.0 million under the Credit
Facility and its money market lines of credit. The Company anticipates
additional borrowings under the Credit Facility and its money market lines of
credit during the remainder of 1999.
11
<PAGE> 14
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.
RECENT DEVELOPMENTS
On July 15, 1999, the Company completed the purchase of Gulf Australia
Resources Limited. The acquisition includes interests in two producing oil
fields with identified drilling potential in the Timor Sea, offshore Australia.
The acquired Jabiru and Challis fields are currently producing at a net daily
rate of 6,000 barrels of oil per day. Jabiru and Challis have cumulative gross
production of 100 and 50 million barrels of oil, respectively. The Company plans
to drill two or three infill wells in 2000, increasing the oil production rate
and thereby extending the economic life of the fields. The current lifting costs
of approximately $8 per barrel (or $1.33 per Mcfe) would be decreased
significantly on a unit of production basis with successful infill drilling.
Gulf Australia has approximately 125 employees. Four labor unions represent the
non-administrative employees.
The Australian acquisition also includes an interest in nine
exploration and production licenses covering three million gross acres in the
Timor Sea and 5,000 square kilometers of 3-D seismic data. Current drilling
plans on these licenses include seven exploratory wells over the next two to
three years. The combined net cost of the seven tests is approximately $25
million. In Australia, offshore exploration expenses are deductible for both
federal tax and the determination of the petroleum resource rent tax against
income generated from offshore production such as that from Jabiru and Challis,
thereby making the net after-tax cost of this anticipated exploration drilling
approximately $10 million.
The Company funded the Australian acquisition with $23 million of
borrowings under the Credit Facility. Included in the purchase price was a
substantial amount of working capital, including an inventory of 479 MBbls
barrels of oil.
On July 21, 1999, the Company announced it had entered into an
agreement with Ocean Energy, Inc. to acquire the interest of Ocean Energy in
three Gulf of Mexico oil and gas fields for approximately $66 million. Closing
of the transaction is expected by mid-August. Production from these fields net
to the interests to be acquired is approximately 25 MMcfe per
12
<PAGE> 15
day and the production is 70% oil. The purchase price and the interests to be
acquired are subject to customary adjustments, including the possible exercise
of preferential purchase rights by third parties.
The Company is currently in the latter stages of negotiating additional
proved property acquisitions in the Gulf of Mexico from multiple sellers. If the
acquisitions are successfully completed, the aggregate purchase price for the
interests in more than twenty fields is expected to be approximately $25
million. The purchase price and the interests to be acquired will be subject to
customary adjustments, including the possible exercise of preferential purchase
rights by third parties.
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 June 28, 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>
July 1999 ....................... 2,060 $2.26 2,000 $2.05-$2.10 $2.40-$2.50 --- ---
August 1999 ..................... 2,710 $2.36 2,000 $2.05-$2.10 $2.40-$2.50 --- ---
September 1999 .................. 2,710 $2.37 2,000 $2.05-$2.10 $2.40-$2.50 --- ---
October 1999 - December 1999 .... 1,680 $2.51 --- --- --- 5,350 $2.59
January 2000 - February 2000 .... --- --- --- --- --- 1,150 $2.73
January 2000 - December 2000 .... 6,800 $2.41 --- --- --- --- ---
</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
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
13
<PAGE> 16
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 July 28, 1999, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1999 and 2000 as
follows:
<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>
July 1999 ....................... 93,000 $17.48 93,000 $14.00-$17.00 $15.25-$19.15 --- ---
August 1999 ..................... 62,000 $17.93 93,000 $14.00-$17.00 $15.25-$19.15 --- ---
September 1999 .................. 90,000 $18.54 90,000 $15.00-$18.28 $17.00-$21.00 --- ---
October 1999 - December 1999 .... 92,000 $19.77 184,000 $15.00-$18.28 $17.00-$21.00 92,000 $19.82
January 2000 - March 2000 ....... --- --- --- --- --- 91,000 $19.32
January 2000 - September 2000 ... --- --- 274,000 $18.28 $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.
14
<PAGE> 17
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 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
offshore natural gas and oil production, respectively, appear not have Year 2000
sensitive equipment.
15
<PAGE> 18
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.
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.
16
<PAGE> 19
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.
MMS. Minerals Management Service of the United States Department of
the Interior.
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>
17
<PAGE> 20
PART II
Item 4. Submission of Matters to a Vote of Security Holders
At the May 5, 1999 Annual Meeting of Stockholders, the Company's
stockholders voted on two matters; 40,631,953 shares of common stock were
outstanding and entitled to vote as of the March 15, 1999 record date.
(1) Election of Ten Directors:
The stockholders elected the ten nominees for director until the
next annual meeting by the following vote:
<TABLE>
<CAPTION>
NOMINEE ELECTED FOR WITHHELD
------------------- ------------------- -----------------
<S> <C> <C>
Joe B. Foster 29,022,641 5,560,870
Robert W. Waldrup 29,028,441 5,555,070
Charles W. Duncan, Jr. 29,158,641 5,424,870
Howard H. Newman 29,161,241 5,422,270
Thomas G. Ricks 29,166,241 5,417,270
C.E. (Chuck) Shultz 29,161,241 5,422,270
Terry Huffington 29,028,441 5,555,070
Dennis R. Hendrix 29,021,941 5,561,570
Philip J. Burguieres 29,019,341 5,564,170
John C. Sawhill 25,581,295 9,002,216
</TABLE>
(2) Appointment of Independent Public Accountants:
The stockholders ratified the appointment of
PricewaterhouseCoopers LLP as the Company's independent public
accountants for the year 1999 by the following vote:
<TABLE>
<CAPTION>
FOR AGAINST ABSTENTIONS
-------------- -------------- ----------------
<S> <C> <C>
34,571,066 8,104 2,141
</TABLE>
18
<PAGE> 21
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
27 Financial Data Schedule (included only in the electronic
filing of this document)
(b) Reports on Form 8-K:
None.
19
<PAGE> 22
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: July 29, 1999 By: /s/ TERRY W. RATHERT
------------------------------------
Terry W. Rathert
Vice President-Planning and
Administration and Secretary
(Authorized Officer and Principal
Financial Officer)
20
<PAGE> 23
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description of Exhibits
-------- -----------------------
<S> <C>
27 Financial Data Schedule (included only in the electronic filing of
this document)
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NEWFIELD
EXPLORATION COMPANY'S BALANCE SHEET AT JUNE 30, 1999 AND STATEMENT OF INCOME FOR
THE SIX MONTHS ENDED JUNE 30, 1999, THAT ARE CONTAINED IN ITS FORM 10-Q FOR THE
QUARTERLY PERIOD ENDED JUNE 30, 1999. THE SCHEDULE IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> JUN-30-1999
<CASH> 3,681
<SECURITIES> 0
<RECEIVABLES> 32,255
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 39,593
<PP&E> 1,040,715
<DEPRECIATION> 487,715
<TOTAL-ASSETS> 598,158
<CURRENT-LIABILITIES> 35,258
<BONDS> 184,664
0
0
<COMMON> 262,353
<OTHER-SE> 77,989
<TOTAL-LIABILITY-AND-EQUITY> 598,158
<SALES> 112,986
<TOTAL-REVENUES> 112,986
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 92,617
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 6,649
<INCOME-PRETAX> 6,761
<INCOME-TAX> 2,556
<INCOME-CONTINUING> 4,205
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,205
<EPS-BASIC> 0.10
<EPS-DILUTED> 0.10
</TABLE>
