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, 1998
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 30, 1998, there were 36,171,344 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,
1998 and December 31, 1997 . . . . . . . . . 1
Consolidated Statement of Income for the three
months ended March 31, 1998 and 1997 . . . . 2
Consolidated Statement of Cash Flows for the
three months ended March 31, 1998 and 1997 . 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. . . . . . . . . 14
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In thousands of dollars, except share data)
(Unaudited)
MARCH 31, DECEMBER 31,
1998 1997
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents . . . . . . . . . $ 27,234 $ 8,217
Accounts receivable-oil and gas . . . . . . 30,031 54,123
Other . . . . . . . . . . . . . . . . . . . 2,886 2,426
------------ ------------
Total current assets. . . . . . . . . . . 60,151 64,766
------------ ------------
Oil and gas properties (full cost method, of
which $80,610 at March 31, 1998 and $79,264
at December 31, 1997 were excluded from
amortization) . . . . . . . . . . . . . . . 847,937 775,585
Furniture, fixtures and equipment . . . . . . 3,480 3,100
Less-accumulated depreciation, depletion and
amortization. . . . . . . . . . . . . . . . (320,483) (293,111)
------------ ------------
530,934 485,574
------------ ------------
Other assets. . . . . . . . . . . . . . . . . 3,229 3,281
------------ ------------
Total assets. . . . . . . . . . . . . . . $ 594,314 $ 553,621
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities. . $ 48,873 $ 63,834
Advances from joint owners. . . . . . . . . 4,444 560
------------ ------------
Total current liabilities . . . . . . . . 53,317 64,394
------------ ------------
Other liabilities . . . . . . . . . . . . . . 4,308 3,846
Long-term debt. . . . . . . . . . . . . . . . 169,629 129,623
Deferred taxes. . . . . . . . . . . . . . . . 66,964 63,710
------------ ------------
Total long-term liabilities . . . . . . . 240,901 197,179
------------ ------------
Commitments and contingencies (Note 2). . . . --- ---
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; 36,149,044 and
35,975,777 shares issued and outstanding
at March 31, 1998 and December 31, 1997,
respectively) . . . . . . . . . . . . . . 361 360
Additional paid-in capital. . . . . . . . . . 163,969 160,672
Unearned compensation . . . . . . . . . . . . (6,554) (4,592)
Retained earnings . . . . . . . . . . . . . . 142,320 135,608
------------ ------------
Total stockholders' equity. . . . . . . . 300,096 292,048
------------ ------------
Total liabilities and stockholders' equity $ 594,314 $ 553,621
============ ============
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,
-------------------------
1998 1997
----------- -----------
Oil and gas revenues. . . . . . . . . . . . . $ 49,982 $ 46,927
----------- -----------
Operating expenses:
Lease operating . . . . . . . . . . . . . . 7,468 5,583
Depreciation, depletion and amortization. . 27,372 19,754
General and administrative, net . . . . . . 2,911 2,953
Stock compensation. . . . . . . . . . . . . 535 430
----------- -----------
Total operating expenses. . . . . . . . . 38,286 28,720
----------- -----------
Income from operations. . . . . . . . . . . . 11,696 18,207
Other income (expense):
Interest income . . . . . . . . . . . . . . 325 373
Interest expense, net . . . . . . . . . . . (1,653) (325)
----------- -----------
(1,328) 48
----------- -----------
Income before income taxes. . . . . . . . . . 10,368 18,255
Income tax provision. . . . . . . . . . . . . 3,656 6,368
----------- -----------
Net income. . . . . . . . . . . . . . . . . . $ 6,712 $ 11,887
=========== ===========
Basic earnings per common share . . . . . . . $ 0.19 $ 0.34
=========== ===========
Diluted earnings per common share . . . . . . $ 0.18 $ 0.31
=========== ===========
Weighted average number of shares outstanding
for basic earnings per share. . . . . . . . . 36,051 35,250
=========== ===========
Weighted average number of shares outstanding
for diluted earnings per share. . . . . . . . 38,284 37,759
=========== ===========
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,
--------------------------
1998 1997
------------ ------------
Cash flows from operating activities:
Net income. . . . . . . . . . . . . . . . $ 6,712 $ 11,887
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion
and amortization. . . . . . . . . . . 27,372 19,754
Deferred taxes. . . . . . . . . . . . . 3,656 6,473
Stock compensation. . . . . . . . . . . 535 430
------------ ------------
38,275 38,544
Changes in assets and liabilities:
Decrease in accounts receivable,
oil and gas . . . . . . . . . . . . . 24,092 17,750
(Increase) decrease in other
current assets. . . . . . . . . . . . (460) 109
Decrease in other assets . . . . . . . 52 185
Decrease in accounts payable
and accrued liabilities . . . . . . . (19,664) (12,177)
Increase (decrease) in advances
from joint owners . . . . . . . . . . 3,884 (2,933)
Increase in other liabilities . . . . . 692 992
------------ ----------
Net cash provided by
operating activities. . . . . . . . 46,871 42,470
------------ ----------
Cash flows from investing activities:
Additions to oil and gas properties . . (67,649) (43,050)
Additions to furniture, fixtures and
equipment . . . . . . . . . . . . . . (380) (231)
------------ -----------
Net cash used in
investing activities. . . . . . . . (68,029) (43,281)
------------ -----------
Cash flows from financing activities:
Proceeds from borrowings. . . . . . . . 87,750 94,000
Repayments of borrowings. . . . . . . . (47,750) (94,000)
Proceeds from issuances of common
stock, net. . . . . . . . . . . . . . 175 400
Payments on capital lease obligations . - (60)
------------ -----------
Net cash provided by
financing activities . . . . . . . 40,175 340
------------ -----------
Increase (decrease) in cash and
cash equivalents. . . . . . . . . . . . 19,017 (471)
Cash and cash equivalents,
beginning of period . . . . . . . . . . 8,217 13,290
------------ -----------
Cash and cash equivalents, end of period. . . $ 27,234 $ 12,819
============ ===========
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. 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, 1998 and the Company's consolidated results of
operations and cash flows for the three-month periods ended March 31, 1998 and
1997. 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.
The consolidated financial statements include the accounts of Newfield
Exploration Company and its subsidiaries. All significant intercompany
balances and transactions have been eliminated.
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, 1997, including those financial statements and notes
thereto incorporated by reference from the Company's 1997 Annual Report to
Stockholders.
The following is a calculation of basic and diluted weighted average
shares outstanding for the three months ended March 31, 1998 and March 31,
1997, respectively:
Three Months Ended
March 31,
-----------------------
1998 1997
---------- ----------
Shares outstanding for basic EPS . . . . 36,050,644 35,249,962
Dilution effect of stock options
outstanding at end of period. . . . . 2,233,843 2,508,591
---------- ----------
Shares outstanding for diluted EPS . . . 38,284,487 37,758,553
========== ==========
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
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. 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) 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, results of operations or
cash flows 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 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 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 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 write-down of oil and gas properties
is not reversible at a later date even if oil or gas prices increase.
In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 130, "Reporting Comprehensive Income" ("Statement No. 130"). The
statement establishes standards for reporting and display of comprehensive
income and its components. Statement No. 130 became effective for the
Company on January 1, 1998, however, the Company has no comprehensive income
other than net income. In June 1997, the FASB issued Statement of Financial
Accounting Standards No. 131, "Disclosures About Segments of an Enterprise
and Related Information" ("Statement No. 131"). The statement specifies
revised guidelines for determining an entity's operating and geographic
segments and the type and level of financial information about those segments
to be disclosed. In March 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, "Employers' Disclosures about Pensions and
Other Postretirement Benefits" ("Statement No 132"). This statement revises
employers' disclosures about pension and other postretirement benefit plans.
It standardizes the disclosure requirements for pensions and other
postretirement benefits to the extent practicable, requires additional
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information on changes in the benefits obligations and fair values of plan
assets that will facilitate analysis and eliminates certain disclosures that
are no longer as useful as they were previously. The Company will adopt the
provisions of Statement Nos. 131 and 132 in its consolidated financial
statements for the year ended December 31, 1998. The Company does not
believe that such adoption will have a material effect on its results of
operations.
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,
--------------------------
1998 1997
------------ ------------
Production:
Oil and condensate (MBbls). . . . . . . . . . 930 806
Gas (MMcf). . . . . . . . . . . . . . . . . . 14,487 11,387
Total production (MMcfe). . . . . . . . . . . 20,066 16,222
Average Realized Price:
Oil and condensate (per Bbl). . . . . . . . . $ 14.57 $ 22.32
Gas (per Mcf) . . . . . . . . . . . . . . . . 2.52 2.55
Average Costs (per Mcfe)
Lease operating . . . . . . . . . . . . . . . $ 0.37 $ 0.34
Depreciation, depletion and amortization. . . 1.36 1.22
General and administrative, net . . . . . . . 0.15 0.18
Production. Net production increased 24%, from 16.2 Bcfe for the three
months ended March 31, 1997 to 20.1 Bcfe for the three months ended March 31,
1998. Oil and condensate production for the three months ended March 31,
1998 increased 124 MBbls, or 15%, compared to the same period of 1997.
Increased oil and condensate production was due primarily to production
increases from development drilling activities at West Delta 152 and South
Timbalier 148, the acquisitions of the Second Bayou field, onshore south
Louisiana in the second quarter of 1997 and Eugene Island 324 late in the
first quarter of 1997. Gas production increased by 3.1 Bcf, or 27%, from
11.4 Bcf for the three months ended March 31, 1997 to 14.5 Bcf for the
comparable period of 1998. Increased gas production was due to production
increases from development drilling activities at South Timbalier 148 and
Ship Shoal 69 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, 1998 increased by $3.1 million, or 7%, compared to the same period
of 1997, primarily as a result of increased oil and gas production offset by
lower realized oil and gas prices. The average realized price of oil and
condensate decreased significantly for the three months ended March 31, 1998
compared to the same period of 1997. The average realized price of oil and
condensate decreased by 35% and the average realized price of natural gas
decreased by 1%.
For the three months ended March 31, 1998, the average realized gas price
was $2.52 per Mcf, which, as a result of hedging activities, was 113% of the
$2.23 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, 1997, the Company realized an average gas price of $2.55 per
Mcf, or 87% of the $2.93 per Mcf average gas 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, 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. There were
no oil hedging activities for the three months ended March 31, 1997.
Lease Operating Expense. Lease operating expense for the three months
ended March 31, 1998 increased to $7.5 million from $5.6 million for the
comparable period of 1997. Lease operating expense per Mcfe increased from
$0.34 for the three months ended March 31, 1997 to $0.37 for the comparable
period of 1998. These increases are primarily attributable to a general
increase in costs in the oilfield service industry and lease operating costs
associated with properties acquired after March 31, 1997.
Depreciation, Depletion and Amortization Expense. During the three
months ended March 31, 1998, depreciation, depletion, and amortization
expense increased to $27.4 million from $19.8 million for the comparable
period of 1997. 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 1997 and 1998. The depletion rate
per unit for the three months ended March 31, 1998 increased 11% to $1.36 per
Mcfe from $1.22 per Mcfe for the comparable period of 1997. 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.
General and Administrative Expense, Net. General and administrative
expense, which is net of overhead reimbursements received by the Company from
other working interest owners, decreased to $2.9 million, or $0.15 per Mcfe,
for the three months ended March 31, 1998 as compared to $3.0 million, or
$0.18 per Mcfe, for the same period of 1997. General and administrative
expense decreased primarily as a result of decreased performance based
compensation partially offset by direct costs associated with staff increases
during 1997. Performance based compensation, as a component of general and
administrative expense, decreased in the aggregate from $1.4 million, or
$0.08 per Mcfe, for the three months ended March 31, 1997 to $0.9 million, or
$0.04 per Mcfe, for the three months ended March 31, 1998. Direct costs
associated with staff increases during 1997 were partially offset by joint
interest reimbursements. 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.
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Interest Expense, Net. Interest expense, net of capitalized interest,
for the three months ended March 31, 1998 increased to $1.7 million from $0.4
million for the comparable period of 1997. The increase was attributable to
higher average debt levels during the first quarter of 1998 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 condensate prices for the three months ended
March 31, 1998 compared to the same period of 1997, the Company had net
income of $6.7 million, or $0.18 per diluted share, for the three months
ended March 31, 1998, a decrease of $5.2 million compared to $11.9 million,
or $0.31 per diluted share, for the comparable period of 1997.
Liquidity and Capital Resources
The Company had $6.8 million of working capital at March 31, 1998
compared to $0.4 million of working capital at December 31, 1997. The $6.4
million increase in working capital is primarily due to additional borrowings
under the Company's revolving credit facility (the "Credit Facility") offset
by the impact of increased drilling activity during 1998. Long-term debt
increased from $129.6 million at December 31, 1997 to $169.6 million at March
31, 1998. Working capital balances may fluctuate from quarter to quarter to
the extent the Company increases or decreases borrowings under its Credit
Facility. The Company has funded its oil and gas activities through cash
flow from operations, equity capital from private and public sources, a
private placement of $125 million in senior unsecured notes due October 2007
and bank borrowings.
The Company maintains its reserve-based revolving Credit Facility with
The Chase Manhattan Bank, as agent. As of March 31, 1998, $45 million was
outstanding under the Credit Facility. The Credit Facility provides a $125
million revolving credit maturing on October 31, 2002. The amount available
under the Credit Facility is subject to a borrowing base, which is reduced by
the principal amount of the senior notes outstanding at the time of
calculation. The Company has an option, subject to the borrowing base, to
increase the facility to $200 million. Without so increasing the facility,
the Company currently has approximately $90 million of available capacity
under the Credit Facility.
The Company's net cash flow from operations for the first three months of
1998 was $46.9 million compared to $42.5 million for the same period of 1997.
The increase is primarily due to increases in oil and gas production 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 1998 was $38.3 million compared to $38.6 million for the same period of
1997. 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 increases in oil and gas production.
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. 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, 1998, the Company had entered into commodity price
hedging contracts with respect to its 1998 production as follows:
Swaps Collars Floor Contracts
--------------------------- ----------------------------- ---------------------------
Weighted NYMEX
Average Contract Price
NYMEX per MMBtu NYMEX
Volume in Contract Price Volume in ------------------- Volume in Contract Price
Period MMMBtu per MMBtu MMMBtu Floor Ceiling MMMBtu per MMBtu
----------- --------- ------------- --------- ------- ------- --------- --------------
April 1998 . . . . 1,000 (1) $2.27 500 $2.28-$2.34 $2.83-$2.89 250 $2.33
May 1998 . . . . . 1,500 (2) $2.35 250 $2.19 $2.65 2,000 $2.20-$2.32
June 1998. . . . . 1,500 (2) $2.34 --- --- --- 2,250 $2.20-$2.32
July 1998. . . . . 1,500 (2) $2.34 --- --- --- 2,500 $2.20-$2.32
August 1998. . . . 1,500 (2) $2.34 --- --- --- 2,500 $2.20-$2.32
September 1998 . . 1,500 (2) $2.34 --- --- --- 2,500 $2.20-$2.32
- -----------
(1) The Company has entered into a basis swap with respect to 75% of the
indicated volume.
(2) The Company has entered into a basis swap with respect to 16% of the
indicated volume.
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. For any particular floor transaction,
the counterparty is required to make a payment to the Company if the
settlement price for any settlement period is below the floor price for
such transaction. The Company is not required to make any payment in
connection with the settlement of a floor transaction.
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The Company may enter into basis swaps (either as part of a particular
hedging transaction or separately) tied to a particular NYMEX-based
transaction to mitigate basis risk. Because substantially all of the
Company's natural gas production is sold under spot contracts that have
historically correlated with the swap price, the Company believes that it has
no material basis risk with respect to gas swaps that are not coupled with
basis swaps.
The Company has entered into a crude oil swap agreement for 15,000
barrels of oil production per month for the period April 1998 through June
1998, which effectively fixes the price of such production against the NYMEX
West Texas Intermediate contract price ranging from $20.77 to $21.04 per
barrel. Because substantially all of the Company's oil production is sold
under spot contracts which correlate to the West Texas Intermediate price,
the Company believes that it has no material basis risk with respect to this
transaction.
Subsequent to March 31, 1998, the Company sold calls against the floor
contracts already owned for the time period May 1998 through September 1998,
thereby converting a portion of its hedge positions into collars. The
volumes for the respective periods were as follows:
Call Options Sold
---------------------------
NYMEX
Volume in Contract Price
Period MMMBtu per MMBtu
----------- --------- -------------
May 1998 . . . . . 2,000 $3.00
June 1998. . . . . 2,250 $3.00
July 1998. . . . . 2,250 $3.00
August 1998. . . . 1,250 $3.00
September 1998 . . 1,250 $3.00
Capital expenditures for the three months ended March 31, 1998 were $72
million, consisting of $24 million for exploration and $48 million for
development. The Company's exploration capital expenditures budget for 1998
is $73 million. The Company has budgeted $120 million in 1998 for
development drilling and construction expenditures for platforms, facilities
and pipelines including $4 million for abandonment or dismantlement of
existing wells and facilities. The Company continues to pursue attractive
acquisition opportunities. Additionally, the Company has budgeted $7 million
for property acquisitions. 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. The Company has increased its 1998
production target to 87 Bcfe. During the first quarter of 1998, the Company
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borrowed $87.8 million and repaid $47.8 million under the Credit Facility.
The Company anticipates additional borrowings under the Credit Facility
during the remainder of 1998.
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 supplement
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 condition 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, results of operations or
cash flows of the Company.
Forward Looking Information
Certain of the statements set forth in this document regarding production
targets and growth and 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.
Certain Oil and Gas Terms
The definitions set forth below shall apply to the indicated terms as
used in this document. All volumes of natural gas referred to herein are
stated at the legal pressure base of the state or area where the reserves
exist and at 60 degrees Fahrenheit and in most instances are rounded to the
nearest major multiple.
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.
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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.
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.
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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:
None
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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: May 1, 1998 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)