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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1998
COMMISSION FILE NUMBER 1-12534
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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
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Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports, and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
As of October 30, 1998, there were 40,289,215 shares of the
Registrant's Common Stock, par value $0.01 per share, outstanding.
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TABLE OF CONTENTS
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PART I
Item 1. Financial Statements:
Consolidated Balance Sheet as of September 30,
1998 and December 31, 1997.........................................................1
Consolidated Statement of Income for the three months ended
September 30, 1998 and 1997 and for the nine months ended
September 30, 1998 and 1997........................................................2
Consolidated Statement of Cash Flows for the
nine months ended September 30, 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...........................................................15
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS OF DOLLARS, EXCEPT SHARE DATA)
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
1998 1997
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents ................................... $ 3,394 $ 8,217
Accounts receivable, oil and gas ............................ 35,911 54,123
Other ....................................................... 3,778 2,426
------------ ------------
Total current assets ..................................... 43,083 64,766
------------ ------------
Oil and gas properties (full cost method, of which $107,659
at September 30, 1998 and $79,264 at December 31,
1997 were excluded from amortization) ....................... 1,053,602 775,585
Furniture, fixtures and equipment ............................... 3,995 3,100
Less-accumulated depreciation, depletion and amortization ....... (380,116) (293,111)
------------ ------------
677,481 485,574
------------ ------------
Other assets .................................................... 3,296 3,281
------------ ------------
Total assets ............................................. $ 723,860 $ 553,621
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities .................... $ 52,897 $ 63,834
Advances from joint owners .................................. 8,558 560
------------ ------------
Total current liabilities ................................ 61,455 64,394
------------ ------------
Other liabilities ............................................... 15,516 3,846
Long-term debt .................................................. 187,643 129,623
Deferred taxes .................................................. 69,725 63,710
------------ ------------
Total long-term liabilities .............................. 272,884 197,179
------------ ------------
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; 40,230,490 and
35,975,777 shares issued and outstanding at
September 30, 1998 and December 31, 1997,
respectively) ............................................ 402 360
Additional paid-in capital ...................................... 247,758 160,672
Unearned compensation ........................................... (5,581) (4,592)
Retained earnings ............................................... 146,942 135,608
------------ ------------
Total stockholders' equity ............................... 389,521 292,048
------------ ------------
Total liabilities and stockholders' equity ............... $ 723,860 $ 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 OF DOLLARS, EXCEPT PER SHARE DATA)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ------------------------------
1998 1997 1998 1997
------------ ------------ ------------ ------------
Oil and gas revenues ............................. $ 45,296 $ 49,863 $ 145,180 $ 139,135
------------ ------------ ------------ ------------
Operating expenses:
Lease operating .............................. 8,779 7,177 24,831 17,782
Depreciation, depletion and amortization ..... 29,279 25,442 87,028 67,415
General and administrative, net .............. 2,274 2,724 7,768 8,251
Stock compensation ........................... 587 297 1,695 1,005
------------ ------------ ------------ ------------
Total operating expenses ................ 40,919 35,640 121,322 94,453
------------ ------------ ------------ ------------
Income from operations ........................... 4,377 14,223 23,858 44,682
Other income (expense):
Interest income .............................. 190 160 802 768
Interest expense, net ........................ (3,188) (926) (7,065) (1,783)
------------ ------------ ------------ ------------
(2,998) (766) (6,263) (1,015)
------------ ------------ ------------ ------------
Income before income taxes ....................... 1,379 13,457 17,595 43,667
Income tax provision ............................. 529 4,742 6,261 15,292
------------ ------------ ------------ ------------
Net income ....................................... $ 850 $ 8,715 $ 11,334 $ 28,375
============ ============ ============ ============
Basic earnings per common share .................. $ 0.02 $ 0.24 $ 0.31 $ 0.80
============ ============ ============ ============
Diluted earnings per common share ................ $ 0.02 $ 0.23 $ 0.29 $ 0.75
============ ============ ============ ============
Weighted average number of shares
outstanding for basic earnings per share ......... 36,721 35,759 36,315 35,505
============ ============ ============ ============
Weighted average number of shares
outstanding for diluted earnings per share ....... 38,776 38,213 38,470 37,926
============ ============ ============ ============
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)
NINE MONTHS ENDED
SEPTEMBER 30,
------------------------------
1998 1997
------------ ------------
Cash flows from operating activities:
Net income ........................................................... $ 11,334 $ 28,375
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization ........................... 87,028 67,415
Deferred taxes ..................................................... 6,261 15,315
Stock compensation ................................................. 1,695 1,005
------------ ------------
106,318 112,110
Changes in operating assets and liabilities:
Decrease in accounts receivable, oil and gas ....................... 18,212 9,592
Increase in other current assets ................................... (1,352) (1,511)
(Increase) decrease in other assets ................................ (15) 4,431
Decrease in accounts payable and accrued liabilities ............... (7,321) (7,310)
Increase (decrease) in advance from joint owners ................... 7,998 (2,697)
Increase in other liabilities ...................................... 687 2,655
------------ ------------
Net cash provided by operating activities ........................ 124,527 117,270
------------ ------------
Cash flows from investing activities:
Additions to oil and gas properties ................................ (270,406) (181,652)
Additions to furniture, fixtures and equipment ..................... (918) (566)
------------ ------------
Net cash used in investing activities ............................ (271,324) (182,218)
------------ ------------
Cash flows from financing activities:
Proceeds from borrowings ........................................... 569,750 315,000
Repayments of borrowings ........................................... (511,750) (255,000)
Proceeds from issuance of common stock, net ........................ 83,974 7,100
Payments on capital lease obligations .............................. -- (163)
------------ ------------
Net cash provided by financing activities ........................ 141,974 66,937
------------ ------------
Increase (decrease) in cash and cash equivalents .......................... (4,823) 1,989
Cash and cash equivalents, beginning of period ............................ 8,217 13,290
------------ ------------
Cash and cash equivalents, end of period .................................. $ 3,394 $ 15,279
============ ============
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 September 30, 1998 and December 31, 1997 and the Company's
consolidated results of operations for the three and nine month periods
ended September 30, 1998 and 1997 and consolidated cash flows for the nine
month periods ended September 30, 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 represents basic and diluted weighted average shares
outstanding for the purposes of calculating basic and diluted earnings per
share for the three and nine month periods ended September 30, 1998 and
September 30, 1997, respectively. There are no adjustments to reported net
income for purposes of calculating earnings per share.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -----------------------------
1998 1997 1998 1997
------------ ------------ ------------ ------------
Shares outstanding for basic EPS ....... 36,720,935 35,759,265 36,315,491 35,504,668
Dilution effect of stock options
outstanding at end of period ..... 2,055,005 2,454,071 2,154,063 2,421,647
------------ ------------ ------------ ------------
Shares outstanding for diluted EPS ..... 38,775,940 38,213,336 38,469,554 37,926,315
============ ============ ============ ============
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
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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.
(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 unforeseen
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 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 may vary significantly from quarter
to quarter as a result of development operations, commodity prices, the
curtailment of production as a result of inclement weather or 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 Financial Accounting Standards Board (the "FASB")
issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("Statement No. 130"). The statement establishes standards
with respect to 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
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Postretirement Benefits" ("Statement No 132"). This statement standardizes the
disclosure requirements for pensions and other postretirement benefits to the
extent practicable, requires additional 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 disclosure provisions of Statement
Nos. 131 and 132 in its consolidated financial statements for the year ended
December 31, 1998.
In June 1998, the 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-market 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 with respect to the Company
on January 1, 2000. The Company is currently evaluating the impact of the
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.
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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- ------------------------
1998 1997 1998 1997
---------- ---------- ---------- ----------
Production:
Oil and condensate (MBbls)............................. 826 867 2,730 2,491
Gas (MMcf)............................................. 16,036 14,719 47,069 39,002
Total production (MMcfe)............................... 20,991 19,920 63,451 53,950
Average Realized Price:
Oil and condensate (per Bbl)........................... $ 12.28 $ 17.60 $ 13.26 $ 19.26
Gas (per Mcf).......................................... 2.20 2.35 2.32 2.34
Average Costs (per Mcfe)
Lease operating........................................ $ 0.42 $ 0.36 $ 0.39 $ 0.33
Depreciation, depletion and amortization............... 1.39 1.28 1.37 1.25
General and administrative, net........................ 0.11 0.14 0.12 0.15
PRODUCTION. Net production increased 18%, from 54.0 Bcfe for the nine
months ended September 30, 1997 to 63.5 Bcfe for the nine months ended
September 30, 1998. Oil and condensate production for the nine months ended
September 30, 1998 increased 239 MBbls, or 10%, compared to the same period of
1997. Increased oil production for the first nine months of 1998 was due
primarily to production increases from development drilling activities during
1997 at Ship
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Shoal 354, West Delta 152 and Eugene Island 324. Gas production increased by 8.1
Bcf, or 21%, from 39.0 Bcf for the nine months ended September 30, 1997 to 47.1
Bcf for the comparable period of 1998. Increased gas production was due to
production increases from development drilling activities during 1997 at East
Cameron 373, West Cameron 561 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 production
curtailments as a result of the tropical storm activity during the third
quarter of 1998 and by natural production decline on other properties of the
Company.
Net production increased 5%, from 19.9 Bcfe for the three months ended
September 30, 1997 to 21.0 Bcfe for the three months ended September 30, 1998.
Oil and condensate production for the three months ended September 30, 1998
decreased 41 MBbls, or 5%, compared to the same period of 1997. Decreased oil
production was due primarily to production curtailments as a result of the
tropical storm activity during the third quarter of 1998. This decrease was
partially offset by production increases from development drilling activities
during 1997 at Ship Shoal 354, Ship Shoal 69 and High Island 537. Gas production
increased by 1.3 Bcf, or 9%, from 14.7 Bcf for the three months ended September
30, 1997 to 16.0 Bcf for the comparable period of 1998. Increased gas
production was due to production increases from development drilling activities
during 1997 at West Cameron 561, 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 production curtailments as a result of the tropical storm activity
during the third quarter of 1998 and by natural production decline on other
properties of the Company.
OIL AND GAS REVENUES. Oil and gas revenues for the nine months ended
September 30, 1998 increased by $6.0 million, or 4%, compared to the same period
of 1997, primarily as a result of increased oil and gas production offset by
significantly lower realized oil prices. The average realized price of oil and
condensate decreased by 31% for the nine months ended September 30, 1998
compared to the same period of 1997.
For the nine months ended September 30, 1998, the average realized gas
price was $2.32 per Mcf, which, as a result of hedging activities, was 107% 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 nine
months ended September 30, 1997, the Company realized an average gas price of
$2.34 per Mcf, or 95% of the $2.46 per Mcf average gas sales price that would
have otherwise been received. For the nine months ended September 30, 1998, the
average realized oil and condensate price was $13.26, which, as a result of
hedging activities, was 101% of the $13.07 per barrel average oil and condensate
sales price that would have otherwise been received. There were no oil hedging
activities for the nine months ended September 30, 1997.
Oil and gas revenues for the three months ended September 30, 1998
decreased by $4.6 million, or 9%, compared to the same period of 1997, primarily
as a result of significantly lower realized oil prices, lower realized gas
prices and decreased oil and condensate production partially offset by increased
gas production. The average realized price of oil and condensate decreased by
30% for the three months ended September 30, 1998 compared to the same period of
1997.
For the three months ended September 30, 1998, the average realized gas
price was $2.20 per Mcf, which, as a result of hedging activities, was 109% of
the $2.01 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 September 30, 1997, the Company realized an average gas price of
$2.35 per Mcf, or 99% of the $2.37 per Mcf average gas sales price
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that would have otherwise been received. There were no oil hedging activities
for the three months ended September 30, 1998 and September 30, 1997.
LEASE OPERATING EXPENSE. Lease operating expense for the nine months
ended September 30, 1998 increased to $24.8 million from $17.8 million for the
comparable period of 1997. Lease operating expense per Mcfe increased from $0.33
for the nine months ended September 30, 1997 to $0.39 for the comparable
period of 1998. These increases are primarily attributable to a general increase
in fees charged by the oilfield service industry, lease operating costs
associated with properties acquired after September 30, 1997 and lease operating
costs associated with the initiation of production at East Cameron 373.
Lease operating expense for the three months ended September 30, 1998
increased to $8.8 million from $7.2 million for the comparable period of 1997.
Lease operating expense per Mcfe increased from $0.36 for the three months ended
September 30, 1997 to $0.42 for the comparable period of 1998. The increase in
lease operating expense per unit is primarily attributable to a general increase
in fees charged by the oilfield service industry, lease operating costs
associated with properties acquired after September 30, 1997, lease operating
costs associated with the initiation of production at East Cameron 373, fixed
costs that continued during the three months ended September 30, 1998 although
production was disrupted and transportation expenses associated with the
tropical storm activity.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. During the nine and
three month periods ended September 30, 1998, depreciation, depletion, and
amortization expense increased to $87.0 million and $29.3 million, respectively,
from $67.4 million and $25.4 million, respectively, for the comparable periods
of 1997. The increases were the result of an increased depletion rate per Mcfe
and production increases from acquisitions and exploratory and development
drilling activities during 1997 and 1998. The depletion rate per unit for
the nine and three month periods ended September 30, 1998 increased to $1.37
and $1.39 per Mcfe, respectively, from $1.25 and $1.28 per Mcfe for the
comparable periods of 1997, respectively. The increases in the depletion rate
per unit are primarily attributable to a general increase in the costs of
drilling goods and services, platform and facilities construction and
transportation services to the industry and the capitalization of a portion of
future costs for lease operating, transportation and location differential
expense associated with the acquisition of proved property interests during the
third quarter 1998 that are subject to a preexisting volumetric production
payment.
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 $7.8 million and $2.3 million
for the nine and three month periods ended September 30, 1998, respectively,
from $8.3 million and $2.7 million for the comparable periods of 1997,
respectively. General and administrative expenses per Mcfe decreased from $0.15
and $0.14 for the nine and three month periods ended September 30, 1997,
respectively, to $0.12 and $0.11 for the comparable periods of 1998,
respectively. The decrease per Mcfe is due to increased production during 1998
and a decrease in performance based compensation. Performance based
compensation, as a component of general and administrative expense, decreased
from $3.8 million, or $0.07 per Mcfe, and $1.3 million, or $0.06 per Mcfe, for
the nine and three month periods ended June 30, 1997, respectively, to $1.9
million, or $0.03 per Mcfe, and $0.3 million, or $0.02 per Mcfe, for the nine
and three month periods ended September 30, 1998, respectively. General and
administrative expenses exclusive of performance based compensation, however,
increased from $4.4 million and $1.4 million for the nine and three month
periods ended September 30, 1997, respectively, to $5.6 million and $1.9 million
for the comparable periods of 1998, resepectively. Direct costs associated with
staff increases during 1997 and 1998 were partially offset by joint interest
reimbursements. To the extent that the Company continues to grow and increase
its
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ownership in certain properties, the Company expects general and administrative
expenses, in the aggregate, to increase.
INTEREST EXPENSE, NET. Interest expense, net of capitalized interest,
for the nine and three months ended September 30, 1998 increased to $7.1 million
and $3.2 million, respectively, from $1.8 million and $0.9 million,
respectively, for the comparable periods of 1997. The increase was attributable
to higher average debt levels during the first nine months 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 nine and three months
ended September 30, 1998 compared to the same periods of 1997, the Company had
net income of $11.3 million and $0.9 million, or $0.29 and $0.02 per diluted
share, for the nine and three month periods ended September 30, 1998,
respectively, as compared to $28.4 million and $8.7 million, or $0.75 and $0.23
per diluted share, respectively, for the comparable periods of 1997.
LIQUIDITY AND CAPITAL RESOURCES
The Company had a working capital deficit of $18.4 million at
September 30, 1998 compared to a working capital surplus of $0.4 million at
December 31, 1997. The $18.8 million decrease in working capital is primarily
due to increased drilling activity during the first nine months of 1998.
Long-term debt increased from $129.6 million at December 31, 1997 to $187.6
million at September 30, 1998. 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, a private placement of $125 million
in senior unsecured notes due October 2007 and bank borrowings.
The Company filed a "universal shelf" registration statement with the
Securities and Exchange Commission with respect to the offering and sale of an
array of debt and equity securities in July 1998 in order to better position
itself to take advantage of future opportunities and to provide additional
financing alternatives. In September 1998, the Company completed the sale
of four million newly issued shares of its common stock under this registration
statement. The Company used the $83 million of net proceeds to reduce
outstanding debt under its Credit Facility.
The Company maintains its reserve-based revolving Credit Facility with
The Chase Manhattan Bank, as agent. As of September 30, 1998, $45 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 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 $250 million. Without so increasing the facility, the Company
currently has approximately $100 million of available capacity under the Credit
Facility.
The Company has also established money market lines of credit with
various banks. As of September 30, 1998, the Company had aggregate borrowings
of $18 million under these lines of credit.
The Company's net cash flow from operations for the first nine months
of 1998 was $124.5 million compared to $117.3 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 nine months of
1998 was $106.3 million compared to $112.1 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
prices and higher operating expenses 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 contract
nor the unrealized gains and losses on these contracts are recognized in the
financial statements.
As of September 30, 1998, the Company had entered into commodity price
hedging contracts with respect to its gas production for 1998 through 2000 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 MMMBtus per MMBtu MMMBtus Floor Ceiling MMMBtus per MMBtu
- ------------------------------------ --------- -------------- --------- ----------- ----------- ---------- ------------
October 1998 ...................... -- -- 1,200 $2.00 $2.46 1,100 $2.11-$2.28
November 1998 ..................... 500 $2.13 1,700 $2.00-$2.20 $2.50-$2.66 1,850 $2.17-$2.43
December 1998 ..................... 500 $2.40 1,700 $2.30-$2.41 $2.80-$2.86 1,850 $2.42-$2.60
January 1999 ............... ...... 500 $2.53 1,700 $2.40-$2.47 $2.90-$2.93 1,850 $2.50-$2.63
February 1999 ..................... 500 $2.45 1,700 $2.35-$2.36 $2.82-$2.85 1,850 $2.40-$2.47
March 1998 ........................ 500 $2.38 1,700 $2.23-$2.25 $2.69-$2.75 1,850 $2.30-$2.34
January 1999 - December 1999 ...... 3,720 $2.34 -- -- -- -- --
January 2000 - December 2000 ...... 3,000 $2.31 -- -- -- -- --
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 (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 for any settlement period is greater than
the swap price for such transaction. For any particular collar transaction, the
counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price for such transaction,
and the Company is required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for such
transaction. For any particular floor transaction, the counterparty is required
to make a payment to the Company if the settlement price for any settlement
period is below the floor price for such transaction. The Company is not
required to make any payment in connection with the settlement of a floor
transaction.
The Company enters 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.
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As of September 30, 1998, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1998 and 1999 as
follows:
Swaps Collars
--------------------------- --------------------------------------
NYMEX
Contract Price
NYMEX per Bbl
Volume in Contract Price Volume in --------------------------
Period Bbls per Bbl Bbls Floor Ceiling
- ----------------------------------- ---------- -------------- ---------- ------------- -----------
October 1998 -December 1998 ....... 92,000 $ 17.20 -- -- --
January 1999-March 1999 ........... -- -- 180,000 $15.00-$17.00 $17.00-$18.10
April 1999-June 1999 .............. -- -- 182,000 $15.00-$17.00 $17.00-$18.70
July 1999-September 1999 .......... -- -- 184,000 $15.00-$17.00 $17.00-$19.15
October 1999-December 1999 ........ -- -- 92,000 $15.00 $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
averages approximately $1.75 per barrel less than the NYMEX West Texas
Intermediate price when adjusted for location and quality differences.
Subsequent to September 30, 1998, the Company entered into commodity
price hedging contracts with respect to its gas production for 1999 as follows:
Collars
---------------------------------------------
NYMEX
Contract Price
per MMBtu
Volume in ----------------------------
Period MMMBtus Floor Ceiling
- ------------------------------ --------- ------------ -----------
April 1999................... 3,250 $2.10-$2.15 $2.25-$2.50
May 1999..................... 3,250 $2.10-$2.15 $2.25-$2.50
June 1999.................... 1,250 $2.10 $2.40
July 1999.................... 1,250 $2.10 $2.40
August 1999.................. 1,250 $2.10 $2.40
September 1999............... 1,250 $2.10 $2.40
Subsequent to September 30, 1998, the Company sold a call against
a floor contract already owned for February 1999, thereby converting a portion
of its hedge position into a collar for 500 MMMBtus of natural gas with a floor
price of $2.46 per MMMBtu and a ceiling price of $3.50 per MMBtu.
Capital expenditures for the nine months ended September 30, 1998 were
$267 million, consisting of $61 million for exploration, $119 million for
development and $87 million for property acquisitions. The Company's exploration
capital expenditures budget for 1998 is $66 million. The Company has budgeted
$161 million in 1998 for development drilling and construction expenditures for
platforms, facilities and pipelines, including $2 million for abandonment or
dismantlement of existing wells and facilities. 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
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operations, working capital and bank borrowings. During the first nine months of
1998, the Company borrowed $569.8 million and repaid $511.8 million under the
Credit Facility and its money market lines. The Company anticipates additional
borrowings under the Credit Facility and its money market lines 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 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 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 unforeseen
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.
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 was recently formed, it 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 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
guarantee, 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.
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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.
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.
NYMEX. New York Mercantile Exchange.
RECOMPLETION The completion for production of an existing well bore in another
formation from that in which the well has been previously
completed.
WORKOVER. Operations on a producing well to restore or increase production.
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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 August 28, 1998, the Company filed a Current Report on Form
8-K, dated August 24, 1998, reporting the acquisition of interests
in nine oil and gas fields and the increase of the Company's
revolving credit facility to $225 million.
On September 16, 1998, the Company filed a Current Report on Form
8-K, dated September 16, 1998, reporting the sale of 4,000,000
newly issued shares of its common stock, par value $0.01 per
share.
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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: October 30, 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)
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