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 MARCH 31, 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 April 29, 1999, there were 40,979,503 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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TABLE OF CONTENTS
Page
PART I
Item 1. Financial Statements:
Consolidated Balance Sheet as of March 31,
1999 and December 31, 1998 . . . . . . . . . 1
Consolidated Statement of Income for the three
months ended March 31, 1999 and 1998 . . . . 2
Consolidated Statement of Cash Flows for the
three months ended March 31, 1999 and 1998 . 3
Notes to Consolidated Financial Statements . . 4
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . 6
PART II
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . 15
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
MARCH 31, DECEMBER 31,
1999 1998
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents . . . . . . . . . $ 139 $ 92
Accounts receivable-oil and gas . . . . . . 29,556 43,095
Other . . . . . . . . . . . . . . . . . . . 1,152 2,082
------------ ------------
Total current assets. . . . . . . . . . . 30,847 45,269
------------ ------------
Oil and gas properties (full cost method, of
which $36,715 at March 31, 1999 and $34,234
at December 31, 1998 were excluded from
amortization) . . . . . . . . . . . . . . . 1,015,379 992,629
Less-accumulated depreciation, depletion and
amortization. . . . . . . . . . . . . . . . (450,834) (414,206)
------------ ------------
564,545 578,423
------------ ------------
Furniture, fixtures and equipment, net. . . . 2,315 2,208
Other assets. . . . . . . . . . . . . . . . . 3,281 3,411
------------ ------------
Total assets. . . . . . . . . . . . . . . $ 600,988 $ 629,311
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities. . $ 25,323 $ 52,123
Advances from joint owners. . . . . . . . . 1,796 1,952
------------ ------------
Total current liabilities . . . . . . . . 27,119 54,075
------------ ------------
Other liabilities . . . . . . . . . . . . . . 11,253 11,467
Long-term debt. . . . . . . . . . . . . . . . 205,657 208,650
Deferred taxes. . . . . . . . . . . . . . . . 29,509 31,171
------------ ------------
Total long-term liabilities . . . . . . . 246,419 251,288
------------ ------------
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; 40,747,653 and
40,429,729 shares issued and outstanding
at March 31, 1999 and December 31, 1998,
respectively) . . . . . . . . . . . . . . 407 404
Additional paid-in capital. . . . . . . . . . 253,797 250,642
Unearned compensation . . . . . . . . . . . . (4,493) (5,007)
Retained earnings . . . . . . . . . . . . . . 77,739 77,909
------------ ------------
Total stockholders' equity. . . . . . . . 327,450 323,948
------------ ------------
Total liabilities and stockholders' equity $ 600,988 $ 629,311
============ ============
The accompanying notes are an integral part of these financial statements.
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In thousands, except per share data)
(Unaudited)
Three Months Ended
March 31,
-------------------------
1999 1998
----------- -----------
Oil and gas revenues. . . . . . . . . . . . . $ 52,914 $ 49,982
----------- -----------
Operating expenses:
Lease operating . . . . . . . . . . . . . . 9,295 7,468
Depreciation, depletion and amortization. . 36,790 27,372
General and administrative, net . . . . . . 3,063 2,911
Stock compensation. . . . . . . . . . . . . 530 535
----------- -----------
Total operating expenses. . . . . . . . . 49,678 38,286
----------- -----------
Income from operations. . . . . . . . . . . . 3,236 11,696
Other income (expenses):
Interest income . . . . . . . . . . . . . . 148 325
Interest expense, net . . . . . . . . . . . (3,525) (1,653)
----------- -----------
(3,377) (1,328)
----------- -----------
Income (loss) before income taxes . . . . . . (141) 10,368
Income tax provision. . . . . . . . . . . . . 29 3,656
----------- -----------
Net income (loss) . . . . . . . . . . . . . . $ (170) $ 6,712
=========== ===========
Basic earnings per common share . . . . . . . $ 0.00 $ 0.19
=========== ===========
Diluted earnings per common share . . . . . . $ 0.00 $ 0.18
=========== ===========
Weighted average number of shares outstanding
for basic earnings per share. . . . . . . . . 40,512 36,051
=========== ===========
Weighted average number of shares outstanding
for diluted earnings per share. . . . . . . . 40,512 38,284
=========== ===========
The accompanying notes are an integral part of these financial statements.
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended
March 31,
--------------------------
1999 1998
------------ -----------
Cash flows from operating activities:
Net income (loss) . . . . . . . . . . . . $ (170) $ 6,712
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion
and amortization. . . . . . . . . . . 36,790 27,372
Deferred taxes. . . . . . . . . . . . . 29 3,656
Stock compensation. . . . . . . . . . . 530 535
------------ -----------
37,179 38,275
Changes in assets and liabilities:
Decrease in accounts receivable,
oil and gas . . . . . . . . . . . . . 13,539 24,092
(Increase) decrease in other
current assets. . . . . . . . . . . . 930 (460)
Decrease in other assets . . . . . . . 130 52
Decrease in accounts payable
and accrued liabilities . . . . . . . (20,837) (19,664)
Increase (decrease) in advances
from joint owners . . . . . . . . . . (156) 3,884
Increase (decrease)in other liabilities (207) 692
------------ -----------
Net cash provided by
operating activities. . . . . . . . 30,578 46,871
------------ -----------
Cash flows from investing activities:
Additions to oil and gas properties . . (28,713) (67,649)
Additions to furniture, fixtures and
equipment . . . . . . . . . . . . . . (269) (380)
------------ -----------
Net cash used in
investing activities. . . . . . . . (28,982) (68,029)
------------ -----------
Cash flows from financing activities:
Proceeds from borrowings. . . . . . . . 81,000 87,750
Repayments of borrowings. . . . . . . . (84,000) (47,750)
Proceeds from issuances of common
stock, net. . . . . . . . . . . . . . 1,451 175
------------ -----------
Net cash provided by (used in)
financing activities . . . . . . . (1,549) 40,175
------------ -----------
Increase in cash and cash equivalents.. . . . 47 19,017
Cash and cash equivalents,
beginning of period . . . . . . . . . . 92 8,217
------------ -----------
Cash and cash equivalents, end of period. . . $ 139 $ 27,234
============ ===========
The accompanying notes are an integral part of these financial statements.
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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 March 31, 1999 and the Company's consolidated results of
operations and cash flows for the three-month periods ended March 31, 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
fiscal 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.
Basic earnings (loss) per common share ("EPS") is computed by dividing
net income (loss) 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 (loss) for purposes of
calculating earnings per share. The following is a calculation of basic and
diluted weighted average shares outstanding for the three months ended March
31, 1999 and 1998, respectively:
Three Months Ended
March 31,
-----------------------
1999 1998
---------- ----------
Shares outstanding for basic EPS . . . . 40,511,882 36,050,644
Dilution effect of stock options
outstanding at end of period. . . . . --- 2,233,843
---------- ----------
Shares outstanding for diluted EPS . . . 40,511,882 38,284,487
========== ==========
The calculation of shares outstanding for diluted EPS above does not
include the effect of stock options outstanding at March 31, 1999 of 3,642,320
shares, because to do so would have been antidilutive.
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
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NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
such transactions. Substantially all of the Company's hedging transactions to
date were carried out in the over-the-counter market and the obligations of the
counterparties have been guaranteed by entities with at least an investment
grade rating or secured by letters of credit. 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) Oil and Gas Properties
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. As of
March 31, 1999, the Company's net capitalized costs of oil and gas properties
exceeded the present value of its estimated proved oil and gas reserves.
The Company did not adjust its net capitalized costs because, subsequent
to March 31, 1999, oil and gas prices increased such that the Company's
net capitalized costs did not exceed the present value of its estimated
proved oil and gas reserves determined on such prices.
(3) Contingencies
The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot
be predicted with certainty, management does not expect these matters to have
a material adverse effect on the financial position, cash flows or results of
operations of the Company.
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.
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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, as
evidenced by the recent volatility of oil and gas prices, 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 or 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. As of
March 31, 1999, the Company's net capitalized costs of oil and gas properties
exceeded the present value of its estimated proved oil and gas reserves.
The Company did not adjust its net capitalized costs because, subsequent
to March 31, 1999, oil and gas prices increased such that the Company's
net capitalized costs did not exceed the present value of its estimated
proved oil and gas reserves determined on such prices.
In June 1998, the Financial Accounting Standards Board (the "FASB")
issued Statement of Financial Accounting Standards 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 derivative.
Statement No. 133 will become effective for the Company on January 1,
2000. The Company is currently evaluating the impact of this statement.
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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:
Three Months Ended
March 31,
--------------------------
1999 1998
------------ ------------
Production:
Oil and condensate (MBbls). . . . . . . . . . 908 930
Gas (MMcf). . . . . . . . . . . . . . . . . . 21,094 14,487
Total production (MMcfe). . . . . . . . . . . 26,542 20,066
Average Realized Price:
Oil and condensate (per Bbl). . . . . . . . . $ 11.28 $ 14.57
Gas (per Mcf) . . . . . . . . . . . . . . . . 2.02 2.52
Average Costs (per Mcfe):
Lease operating . . . . . . . . . . . . . . . $ 0.35 $ 0.37
Depreciation, depletion and amortization. . . 1.39 1.36
General and administrative, net . . . . . . . 0.12 0.15
Production. Net production increased 32%, from 20.1 Bcfe for the three
months ended March 31, 1998 to 26.5 Bcfe for the three months ended March 31,
1999. Oil and condensate production for the three months ended March 31,
1999 decreased 22 MBbls, or 2%, compared to the same period of 1998.
Decreased oil and condensate production was due primarily to well downtime
at Vermilion 398 and South Timbalier 148 and natural production 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 6.6 Bcf, or 46%, from 14.5 Bcf for the three months
ended March 31, 1998 to 21.1 Bcf for the comparable period of 1999.
Increased gas production was due to production increases from drilling
activities at East Cameron 373 and the acquisition of interests in nine
offshore blocks in the East Cameron, West Cameron and High Island areas of
the Gulf of Mexico in July 1997. These increases were partially offset by
natural production decline on other properties of the Company.
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Oil and Gas Revenues. Oil and gas revenues for the three months ended
March 31, 1999 increased by $2.9 million, or 6%, compared to the same period
of 1998, primarily as a result of increased gas production offset by
significantly lower realized oil and gas prices. The average realized price
of natural gas and oil and condensate before hedging activities decreased by
24% and 25%, respectively.
For the three months ended March 31, 1999, the average realized gas price
was $2.02 per Mcf, which, as a result of hedging activities, was 120% of the
$1.69 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 March 31, 1998, the Company realized an average gas price of $2.52 per
Mcf, or 113% of the $2.23 per Mcf average gas sales price that would have
otherwise been received. For the three months ended March 31, 1999, the
average realized oil and condensate price was $11.28 per barrel, which, as a
result of hedging activities, was 105% of the $10.71 per barrel average oil
and condensate sales price that would have otherwise been received. For the
three months ended March 31, 1998, the average realized oil and condensate
price was $14.57 per barrel, which, as a result of hedging activities, was
102% of the $14.31 per barrel average oil and condensate sales price that
would have otherwise been received.
Lease Operating Expense. Lease operating expense for the three months
ended March 31, 1999 increased to $9.3 million from $7.5 million for the
comparable period of 1998. The increase in lease operating expenses is due
primarily to increased operations and property acquisitions. Lease
operating expense per Mcfe decreased from $0.37 for the three months ended
March 31, 1998 to $0.35 for the comparable period of 1999. This decrease
is primarily attributable to the increase in gas production for the three
months ended March 31, 1999 as compared to the comparable period of 1998.
Depreciation, Depletion and Amortization Expense. During the three
months ended March 31, 1999, depreciation, depletion and amortization
expense increased to $36.8 million from $27.4 million for the comparable
period of 1998. The increase was the result of an 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 three months ended March 31, 1999 increased to $1.39 per
Mcfe from $1.36 per Mcfe for the comparable period of 1998. The increase in
the depletion rate per unit is primarily attributable to increased costs of
drilling goods and services, platforms and facilities construction and
transportation services in the industry which 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 $3.1 million for the three months
ended March 31, 1999 as compared to $2.9 million for the same period of 1998.
General and administrative expense increased primarily as a result of direct
costs associated with staff increases during 1998. General and administrative
expense per unit decreased from $0.15 per Mcfe for the three months ended
March 31, 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 in the aggregate
from $0.9 million, or $0.04 per Mcfe, for the three months ended
March 31, 1998 to $0.2 million, or $0.01 per Mcfe, for the three months
ended March 31, 1999.
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Interest Expense, Net. Interest expense, net of capitalized interest,
for the three months ended March 31, 1999 increased to $3.5 million from $1.7
million for the comparable period of 1998. The increase was attributable to
higher average debt levels during the first quarter of 1999 and a lower
percentage of total interest cost being capitalized.
Net Income. As a result of the foregoing, particularly the substantial
decrease in realized oil and gas prices for the three months ended
March 31, 1999 compared to the same period of 1998, the Company had a net
loss of $0.2 million, or $0.00 per diluted share, for the three months
ended March 31, 1999, a decrease of $6.9 million compared to net income of
$6.7 million, or $0.18 per diluted share, for the comparable period of 1998.
Liquidity and Capital Resources
The Company had $3.7 million of working capital at March 31, 1999
compared to a working capital deficit of $8.8 million at December 31, 1998.
The $12.5 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 $205.7 million at March 31, 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.
The Company maintains its reserve-based revolving Credit Facility with
Chase Bank of Texas, National Association, as agent. As of March 31, 1999,
$81 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 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. Without so increasing the facility,
the Company currently has approximately $69 million of available
capacity 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 March 31, 1999, there were no borrowings outstanding under these
lines of credit.
The Company's net cash flow from operations for the first three months of
1999 was $30.6 million compared to $46.9 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 three months of 1999 was $37.2 million compared
to $38.3 million for the same period of 1998. The decrease in net cash flow
from operations before changes in operating assets and liabilities is primarily
attributable to decreased average realized oil and gas prices and higher
operating expenses partially offset by the increase in gas production.
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Capital expenditures for the three months ended March 31, 1999 were $22.8
million, consisting of $11.0 million for exploration, $10.2 million for
development and $1.6 million for property acquisitions. The Company has
budgeted approximately $150 million for capital spending in 1999. Of that
amount, $45 million has been allocated to exploration projects, $55 million
has been allocated to identified development drilling projects and the
construction of platforms, facilities and pipelines (including $6 million for
abandonment or dismantlement of existing wells and facilities) and $5 million
to proved property acquisitions. Not more than $2 million is currently
allocated to international exploration activities. 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 capital
expenditures will be funded principally from cash flow from operations,
working capital and bank borrowings. During the first quarter of 1999, the
Company borrowed $81.0 million and repaid $84.0 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.
To cover the various obligations of lessees on the Outer Continental
Shelf (the "OCS"), the MMS generally requires that lessees post substantial
bonds or other acceptable assurances that such obligations will be met. The
cost of such bonds or other surety can be substantial and there is no
assurance that bonds or other surety can be obtained in all cases.
Additionally, the MMS may require operators in the OCS to post supplemental
bonds in excess of lease and area wide bonds to assure that abandonment
obligations on specific properties will be met. The Company is currently
exempt from the supplemental bonding requirements of the MMS. Under certain
circumstances, the MMS may require any Company operations on federal leases
to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial position, cash flows and
operations.
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.
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.
Hedging
From time to time, the Company has utilized 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
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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 and the obligations of
the counterparties have been guaranteed by entities with at least an investment
grade rating or secured by letters of credit. 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.
As of March 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its 1999 and 2000 natural gas production as
follows:
NYMEX Contract Price per MMBtu
----------------------------------------
Volume Collars
in Swaps ------------------------------
Period MMMBtus (Average) Floors Ceilings
- -------------------------------- ------- ------- ------------- -------------
April 1999 - June 1999
Price Swap Contracts . . . . . 5,080 $1.91 --- ---
Collar Contracts . . . . . . . 6,250 --- $2.10 - $2.15 $2.25 - $2.50
July 1999 - September 1999
Price Swap Contracts . . . . . 930 $2.24 --- ---
Collar Contracts . . . . . . . 3,750 --- $2.10 $2.40
October 1999 - December 1999
Price Swap Contracts . . . . . 930 $2.40 --- ---
January 2000 - December 2000
Price Swap Contracts . . . . . 3,000 $2.31 --- ---
Additionally, the Company will recognize approximately $0.4 million of
gas revenue in the second quarter of 1999 as a result of closing a portion
of its second quarter of 1999 natural gas hedge positions in December 1998 and
January 1999.
These hedging transactions are settled based upon the average of the
reported settlement prices on the New York Mercantile Exchange (the "NYMEX")
for the last three trading days or, occasionally, the penultimate trading day
of a particular contract month (the "settlement price"). 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 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.
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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 March 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1999 as follows:
NYMEX Contract Price per Bbl
---------------------------------
Volume Collars
in ---------------------------------
Period Bbls Floors Ceilings
- ------------------------------ -------- --------------- ---------------
April 1999 - June 1999
Collar Contracts . . . . . . 273,000 $14.00 - $17.00 $15.25 - $18.70
July 1999 - September 1999
Collar Contracts . . . . . . 276,000 $14.00 - $17.00 $15.25 - $19.15
October 1999 - December 1999
Collar Contracts . . . . . . 184,000 $14.00 - $15.00 $15.25 - $17.00
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.
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.
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The Company recently completed an assessment of its operated offshore
platforms and facilities for Year 2000 compliance of Year 2000 sensitive
components. Company owned and operated equipment on platforms and facilities
which 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,
do not 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
the Year 2000 issue. 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.
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.
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.
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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.
MMBbls. One million barrels of crude oil or other liquid
hydrocarbons.
MMbtu. One million Btus.
MMMbtu. Ten million 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. New York Mercantile Exchange
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Part II
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:
On February 18, 1999, the Company filed a Current Report on
Form 8-K, dated February 12, 1999, reporting the adoption of
a stockholder rights plan.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NEWFIELD EXPLORATION COMPANY
Date: April 30, 1999 By: /s/ TERRY W. RATHERT
Terry W. Rathert
Vice President-Planning and Administration
and Secretary
(Authorized Officer and Principal
Financial Officer)
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EXHIBIT INDEX
Exhibit
Number Description of Exhibits
--------- -----------------------
27 Financial Data Schedule (included
only in the electronic filing of
this document)