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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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FORM 10-Q
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X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-9743
ENRON OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 47-0684736
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER
OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
1400 SMITH STREET, HOUSTON, TEXAS 77002-7369
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161
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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 [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of October 31, 1998.
Common Stock, $.01 Par Value 153,695,172 shares
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CLASS NUMBER OF SHARES
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2
ENRON OIL & GAS COMPANY
TABLE OF CONTENTS
PAGE NO.
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PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Statements of Income - Three Months Ended September 30, 1998 and 1997
and Nine Months Ended September 30, 1998 and 1997 3
Consolidated Balance Sheets - September 30, 1998 and December 31, 1997 4
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 1998 and 1997 5
Notes to Consolidated Financial Statements 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 9
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings 19
ITEM 6. Exhibits and Reports on Form 8-K 19
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
1998 1997 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
NET OPERATING REVENUES
Natural Gas
Trade $ 142,107 $ 128,719 $ 406,787 $ 381,579
Associated Companies 12,117 21,280 50,650 39,928
Crude Oil, Condensate and Natural Gas Liquids
Trade 32,638 31,019 90,152 82,729
Associated Companies 2,005 8,164 7,559 27,745
Gains on Sales of Reserves and Related Assets and Other, Net 2,395 3,938 19,252 13,543
--------- --------- --------- ---------
TOTAL 191,262 193,120 574,400 545,524
OPERATING EXPENSES
Lease and Well 24,488 22,490 72,254 71,932
Exploration 16,231 10,717 50,229 41,219
Dry Hole 9,281 4,833 19,443 7,403
Impairment of Unproved Oil and Gas Properties 8,092 6,177 23,795 19,090
Depreciation, Depletion and Amortization 84,376 72,219 229,408 204,041
General and Administrative 15,812 14,942 47,570 40,663
Taxes Other Than Income 13,783 12,985 41,547 42,630
--------- --------- --------- ---------
TOTAL 172,063 144,363 484,246 426,978
--------- --------- --------- ---------
OPERATING INCOME 19,199 48,757 90,154 118,546
OTHER INCOME (EXPENSE), NET (1,601) 214 (2,644) 2,426
--------- --------- --------- ---------
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 17,598 48,971 87,510 120,972
INTEREST EXPENSE, NET 13,629 7,996 33,162 18,575
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES 3,969 40,975 54,348 102,397
INCOME TAX PROVISION (BENEFIT) (1,975) 9,802 8,142 23,588
--------- --------- --------- ---------
NET INCOME $ 5,944 $ 31,173 $ 46,206 $ 78,809
========= ========= ========= =========
EARNINGS PER SHARE OF COMMON STOCK
Basic $ 0.04 $ 0.20 $ 0.30 $ 0.50
========= ========= ========= =========
Diluted $ 0.04 $ 0.20 $ 0.30 $ 0.50
========= ========= ========= =========
AVERAGE NUMBER OF COMMON SHARES
Basic 154,083 157,072 154,559 157,809
========= ========= ========= =========
Diluted 154,409 158,049 155,234 158,609
========= ========= ========= =========
The accompanying notes are an integral part of
these consolidated financial statements.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
SEPTEMBER 30, DECEMBER 31,
1998 1997
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(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 9,241 $ 9,330
Accounts Receivable
Trade 165,468 185,979
Associated Companies 17,655 46,120
Inventories 35,056 32,040
Other 7,851 8,566
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TOTAL 235,271 282,035
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 4,744,888 4,291,405
Less: Accumulated Depreciation, Depletion and Amortization (2,079,633) (1,904,198)
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Net Oil and Gas Properties 2,665,255 2,387,207
OTHER ASSETS 60,928 54,113
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TOTAL ASSETS $ 2,961,454 $ 2,723,355
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LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Trade $ 175,432 $ 198,109
Associated Companies 38,362 37,613
Accrued Taxes Payable 28,082 28,841
Dividends Payable 4,700 4,705
Other 21,941 21,729
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TOTAL 268,517 290,997
LONG-TERM DEBT
Trade 978,087 548,775
Affiliate 96,300 192,500
OTHER LIABILITIES
Trade 19,446 37,740
Associated Companies 43,811 44,698
DEFERRED INCOME TAXES 273,739 287,678
DEFERRED REVENUE 5,743 39,918
SHAREHOLDERS' EQUITY
Common Stock, $.01 Par, 320,000,000 Shares Authorized and
160,000,000 Shares Issued 201,600 201,600
Additional Paid In Capital 402,430 402,877
Unearned Compensation (5,239) (4,694)
Cumulative Foreign Currency Translation Adjustment (35,220) (19,771)
Retained Earnings 833,017 800,709
Common Stock Held in Treasury, 6,286,544 shares at
September 30, 1998 and 4,935,744 shares at December 31, 1997 (120,777) (99,672)
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TOTAL SHAREHOLDERS' EQUITY 1,275,811 1,281,049
--------------- ---------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,961,454 $ 2,723,355
=============== ===============
The accompanying notes are an integral part of
these consolidated financial statements.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
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1998 1997
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income $ 46,206 $ 78,809
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization 229,408 204,041
Impairment of Unproved Oil and Gas Properties 23,795 19,090
Deferred Income Taxes (5,039) 8,510
Other, Net 5,080 1,168
Exploration Expenses 50,229 41,219
Dry Hole Expenses 19,443 7,403
Gains on Sales of Reserves and Related Assets and Other, Net (13,319) (7,602)
Other, Net (7,230) (4,580)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable 44,319 47,122
Inventories (3,016) (11,340)
Accounts Payable (25,379) (28,277)
Accrued Taxes Payable (759) (4,499)
Other Liabilities (24,304) 3,595
Other, Net 2,176 3,876
Amortization of Deferred Revenue (32,419) (32,420)
Changes in Components of Working Capital Associated with
Investing and Financing Activities 9,782 22,423
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NET OPERATING CASH INFLOWS 318,973 348,538
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (580,182) (448,405)
Exploration Expenses (50,229) (41,219)
Dry Hole Expenses (19,443) (7,403)
Proceeds from Sales of Reserves and Related Assets 54,780 23,331
Changes in Components of Working Capital Associated with
Investing Activities (9,782) (21,730)
Other, Net (6,390) (2,771)
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NET INVESTING CASH OUTFLOWS (611,246) (498,197)
FINANCING CASH FLOWS
Long-Term Debt
Trade 429,312 216,442
Affiliate (96,200) --
Dividends Paid (13,903) (14,232)
Treasury Stock Purchased (25,301) (58,428)
Proceeds from Sales of Treasury Stock 2,263 4,661
Other, Net (3,987) (303)
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NET FINANCING CASH INFLOWS 292,184 148,140
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INCREASE IN CASH AND CASH EQUIVALENTS (89) (1,519)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,330 7,644
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CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 9,241 $ 6,125
============= =============
The accompanying notes are an integral part of
these consolidated financial statements.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The consolidated financial statements of Enron Oil & Gas Company and
subsidiaries (the "Company") included herein have been prepared by
management without audit pursuant to the rules and regulations of the
Securities and Exchange Commission. Accordingly, they reflect all
adjustments which are, in the opinion of management, necessary for a fair
presentation of the financial results for the interim periods. Certain
information and notes normally included in financial statements prepared in
accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations. However,
management believes that the disclosures are adequate to make the
information presented not misleading. These consolidated financial
statements should be read in conjunction with the consolidated financial
statements and the notes thereto included in the Company's Annual Report on
Form 10-K for the year ended December 31, 1997.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
Certain reclassifications have been made to prior period financial
statements to conform with the current presentation.
As more fully discussed in notes 1 and 13 to the consolidated financial
statements included in the Company's 1997 Annual Report on Form 10-K, the
Company engages in price risk management activities from time to time
primarily for non-trading and to a lesser extent for trading purposes.
Derivative financial instruments (primarily price swaps and costless
collars) are utilized for non-trading purposes to hedge the impact of
market fluctuations on natural gas and crude oil market prices. Hedge
accounting is utilized in non-trading activities when there is a high
degree of correlation between price movements in the derivative and the
item designated as being hedged. Gains and losses on derivative financial
instruments used for hedging purposes are recognized as revenue in the same
period as the hedged item. Gains and losses on hedging instruments that are
closed prior to maturity are deferred in the consolidated balance sheets.
In instances where the anticipated correlation of price movements does not
occur, hedge accounting is terminated and future changes in the value of
the derivative are recognized as gains or losses using the mark-to-market
method of accounting. Derivative and other financial instruments utilized
in connection with trading activities, primarily price swaps and call
options, are accounted for using the mark-to-market method, under which
changes in the market value of outstanding financial instruments are
recognized as gains or losses in the period of change. The cash flow impact
of derivative and other financial instruments used for non-trading and
trading purposes is reflected as cash flows from operating activities in
the consolidated statements of cash flows.
2. Income tax provision (benefit) for the three-month and nine-month periods
ended September 30, 1998 and 1997 includes tax benefits of $5.4 million,
$2.6 million, $9.2 million and $7.8 million, respectively, related to tight
gas sand federal income tax credit utilization.
3. Natural gas revenues, trade for the three-month and nine-month periods
ended September 30, 1998 and 1997, are net of costs of natural gas
purchased for sale related to natural gas marketing activities of $9.3
million, $16.0 million, $33.6 million and $55.4 million, respectively.
Natural gas revenues, associated for the three-month and nine-month periods
ended September 30, 1998 and 1997, are net of costs of natural gas
purchased for sale related to natural gas marketing activities of $12.2
million, $11.9 million, $36.6 million and $35.1 million, respectively.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. The difference between the average number of common shares outstanding for
basic and diluted earnings per share of common stock is due to the assumed
issuance of 326,000, 977,000, 675,000 and 800,000 common shares relating to
employee stock options in the three-month and nine-month periods ended
September 30, 1998 and 1997, respectively.
5. As reported in the Company's Annual Report on Form 10-K for the year ended
December 31, 1997, Enron Oil & Gas India Ltd. ("EOGIL"), a wholly-owned
subsidiary of the Company, is a respondent in two public interest lawsuits
filed in the Delhi High Court, India. The first (the "Wadehra Action") was
brought by B. L. Wadehra, an Indian public interest lawyer, against the
Union of India, EOGIL, EOGIL co-participants in the Panna and Mukta fields,
Reliance Industries Limited ("Reliance") and Oil & Natural Gas Corporation
Limited ("ONGC"), and certain other respondents. ONGC is the Indian
national oil company and is wholly-owned by the Union of India. The second
suit (the "CPIL Action") was brought by the Centre for Public Interest
Litigation and the National Alliance of People's Movement against the Union
of India, the Central Bureau of Investigation, ONGC, Reliance and EOGIL.
Petitioners in both the Wadehra Action and the CPIL Action allege various
improprieties in the award of the Panna and Mukta fields to EOGIL, Reliance
and ONGC, and seek the cancellation of the Production Sharing Contract for
the Panna and Mukta fields. The Union of India is vigorously disputing
these allegations. The Company believes that the public competitive bidding
process for the fields was fair and that the award of these fields to
EOGIL, Reliance and ONGC was proper. Although no assurances can be given,
based on currently available information the Company believes that the
claims made by the petitioners in both actions are without merit, and that
the ultimate resolution of these matters will not have a material adverse
effect on its financial condition or results of operations. There are
various other suits and claims against the Company that have arisen in the
ordinary course of business. However, management does not believe these
suits and claims will individually or in the aggregate have a material
adverse effect on the Company's financial condition or results of
operations.
The Company has been named as a potentially responsible party in certain
Comprehensive Environmental Response Compensation and Liability Act
proceedings. However, management does not believe that any potential
assessments resulting from such proceedings will individually or in the
aggregate have a materially adverse effect on the financial condition or
results of operations of the Company.
6. In April 1998, the Company issued, pursuant to a public offering, $150
million of 6.65% Notes due April 1, 2028.
7. The Company has adopted Statement of Financial Accounting Standards
("SFAS") No. 130 - "Reporting Comprehensive Income", which established
standards for reporting and displaying comprehensive income and its
components in an annual financial statement that is displayed with the same
prominence as other financial statements. This statement also requires that
an entity report a total for comprehensive income in condensed financial
statements of interim periods.
The Company's total comprehensive income (loss) was $(2.5) million, $31.0
million, $30.8 million and $77.1 million for the three-month and nine-month
periods ended September 30, 1998 and 1997, respectively. The only
adjustment made to net income in the periods was for foreign currency
translation losses of $8.4 million, $.2 million, $15.4 million and $1.7
million for the three-month and nine-month periods ended September 30, 1998
and 1997, respectively.
8. In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133 - "Accounting for Derivative Instruments and Hedging Activities"
effective for fiscal years beginning after June 15, 1999. The statement
cannot be applied retroactively and must be applied to (a) derivative
instruments and (b) certain derivative instruments embedded in hybrid
contracts that were issued, acquired or substantively modified after
December 31, 1997.
The statement establishes accounting and reporting standards requiring that
every derivative instrument be recorded in the balance sheet as either an
asset or liability measured at its fair value. The statement requires that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the statements of income and requires a
company to formally document, designate and assess the effectiveness of
transactions that receive hedge accounting treatment.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONCLUDED)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has not yet quantified the impacts of adopting SFAS No. 133 on
its financial statements and has not determined the timing of or method of
adoption. Based on the criterion of SFAS No. 133 and current
interpretations thereof, the Company believes that 3,200,000 options it
owns to purchase Enron Corp. common shares, at a price of $39.1875 per
share that expire in December 2007, qualify as derivative instruments.
Accordingly, SFAS No. 133 would require the changes in the fair value of
the options to be recognized currently in earnings. The Company cannot
predict whether future interpretations currently being considered by the
Emerging Issues Task Force of the FASB or potential amendments of SFAS No.
133 will result in the options being considered derivative instruments at
the time of its adoption. At December 31, 1997, the carrying value of the
options was approximately $23 million pre-tax, which represented the
estimated fair value at the date of grant. At September 30, 1998, Enron
Corp. common shares closed at $53.50 per share. Based on the Company's
current level of other derivative and hedging activities, the Company does
not expect the impact of adoption relative to those other activities to be
material.
9. On August 31, 1998, the Company entered into a $150 million credit
agreement which matures on August 30, 2000 with NationsBank N.A. Advances
under the agreement bear interest, at the option of the Company, based on a
base rate or a Eurodollar rate. As of September 30, 1998, the full $150
million was outstanding; however, the loan was subsequently repaid on
October 30, 1998.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENRON OIL & GAS COMPANY
The following review of operations for the three-month and nine-month
periods ended September 30, 1998 and 1997 should be read in conjunction with the
consolidated financial statements of Enron Oil & Gas Company (the "Company") and
Notes thereto.
RESULTS OF OPERATIONS
Three Months Ended September 30, 1998 vs. Three Months Ended September 30, 1997
The Company generated third quarter net income of $6 million compared to
net income of $31 million for the third quarter of 1997. Following is an
explanation of the variances causing this reduction.
Wellhead volume and price statistics are summarized below:
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1998 1997
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NATURAL GAS VOLUMES (MMcf PER DAY)(1)
United States (2) 692 639
Canada 106 109
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North America 798 748
Trinidad 163 115
India 58 34
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TOTAL 1,019 897
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AVERAGE NATURAL GAS PRICES ($/Mcf)(3)
United States (4) $ 1.82 $ 2.02
Canada 1.28 1.23
North America Composite 1.75 1.91
Trinidad 1.03 1.04
India 2.34 2.93
COMPOSITE 1.67 1.84
CRUDE OIL/CONDENSATE VOLUMES (MBbl PER DAY)(1)
United States 16.6 12.3
Canada 2.8 2.5
----------- -----------
North America 19.4 14.8
Trinidad 3.1 3.4
India 5.1 2.4
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TOTAL 27.6 20.6
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AVERAGE CRUDE OIL/CONDENSATE PRICES ($/Bbl)(3)
United States $ 12.54 $ 19.19
Canada 11.53 17.39
North America Composite 12.39 18.88
Trinidad 11.37 18.91
India 11.59 18.21
COMPOSITE 12.13 18.81
NATURAL GAS EQUIVALENT VOLUMES (MMcfe PER DAY)(5)
United States (2) 810 731
Canada 129 133
----------- -----------
North America 939 864
Trinidad 181 136
India 89 48
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TOTAL 1,209 1,048
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TOTAL Bcfe(5)DELIVERIES 111 96
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(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Includes 48 MMcf per day for the three-month periods ended September
30, 1998 and 1997 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Includes an average equivalent wellhead value of $1.36/Mcf and
$1.14/Mcf for the three-month periods ended September 30, 1998 and
1997, respectively, for the volumes described in note (2), net of
transportation costs.
(5) Million cubic feet equivalent per day or billion cubic feet equivalent,
as applicable.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Wellhead revenues decreased slightly to $190 million in the third quarter
of 1998 compared to $192 million in the third quarter of 1997, primarily due to
lower average wellhead prices worldwide for natural gas, crude oil and
condensate and natural gas liquids, partially offset by increased production
volumes of natural gas and crude oil and condensate. The Company achieved record
production levels during the third quarter of 1998, producing 1.019 billion
cubic feet per day of natural gas and 31.6 MBbl per day of crude oil, condensate
and natural gas liquids.
Third quarter 1998 average wellhead natural gas prices were approximately
9% lower than the comparable period of 1997 reducing net operating revenues by
approximately $15 million. Average wellhead crude oil and condensate prices were
down by 36% worldwide, decreasing net operating revenues by $17 million.
Revenues from the sale of natural gas liquids also declined $2 million primarily
due to lower wellhead prices.
Third quarter 1998 wellhead natural gas volumes were approximately 14%
higher than the comparable period in 1997 increasing net operating revenues by
$20 million. This increase was primarily due to a 7% increase in North America
volumes, a 71% increase in volumes in India and a 40% increase in Trinidad
mainly due to gas balancing volumes relating to a field allocation agreement of
41 MMcf per day. The North America production increase was attributable to
initial production from certain South Texas wells, increased production from the
Mid-Continent region and the recent completion of an offshore property
acquisition. The improvement in India was primarily due to increased volumes
from the Tapti field and production from the Panna field, which had not
commenced natural gas production in the third quarter of 1997. Wellhead crude
oil and condensate volumes were 34% higher than the prior year period increasing
net operating revenues by $12 million, primarily due to a 31% increase in North
America resulting from recent success in South Texas. Wellhead crude oil and
condensate production in India increased 113% from the Panna and Mukta fields,
which were shut in for a portion of the prior year quarter to allow for the
conversion from temporary to permanent production facilities.
During the third quarter of 1998, operating expenses of $172 million were
approximately $28 million higher than the third quarter of 1997. Depreciation,
depletion and amortization ("DD&A") expense increased approximately $12 million
compared to the third quarter of 1997, primarily reflecting increased worldwide
production volumes and a higher per unit rate in North America. Exploration
expenses and dry hole expenses were $10 million higher than the third quarter of
1997 primarily due to an increase in exploratory drilling and other exploration
activities in North America. Lease and well expenses increased by $2 million
primarily due to expanded operations.
Net interest expense increased $6 million as compared to the third quarter of
1998 reflecting a higher level of long-term debt due to expanded worldwide
operations and common stock repurchases.
The per unit operating costs of the Company for lease and well, DD&A, general
and administrative, interest expense and taxes other than income averaged $1.37
per Mcfe during the third quarter of 1998 compared to $1.36 per Mcfe in 1997.
This increase is primarily due to a higher per unit rate of interest expense and
DD&A expense, partially offset by a lower per unit rate of lease and well
expense, general and administrative expenses and taxes other than income.
Income tax benefit for the third quarter of 1998 was $2 million, as compared to
an income tax provision of approximately $10 million for the same period in
1997. This decrease in income taxes was primarily due to lower pre-tax income
and adjustments for additional tight gas sand credits.
Federal income taxes accrued in interim periods are calculated using the
estimated annual effective income tax rate.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS- (CONTINUED)
ENRON OIL & GAS COMPANY
Nine Months Ended September 30, 1998 vs. Nine Months Ended September 30, 1997
In the first nine months of 1998, the Company generated net income of $46
million compared to net income of $79 million for the first nine months of 1997.
Following is an explanation of the variances causing this reduction.
Wellhead volume and price statistics are summarized below:
- -----------------------------------------------------------------------------------------
1998 1997
- -----------------------------------------------------------------------------------------
NATURAL GAS VOLUMES (MMcf PER DAY)
United States (1) 653 657
Canada 102 99
------------ ------------
North America 755 756
Trinidad 135 114
India 53 11
------------ ------------
TOTAL 943 881
============ ============
AVERAGE NATURAL GAS PRICES ($/Mcf)
United States (2) $ 1.95 $ 2.19
Canada 1.36 1.39
North America Composite 1.87 2.09
Trinidad 1.06 1.04
India 2.52 2.93
COMPOSITE 1.79 1.96
CRUDE OIL/CONDENSATE VOLUMES (MBbl PER DAY)
United States 13.8 11.4
Canada 2.7 2.4
------------ ------------
North America 16.5 13.8
Trinidad 2.9 3.5
India 4.7 1.8
------------ ------------
TOTAL 24.1 19.1
============ ============
AVERAGE CRUDE OIL/CONDENSATE PRICES ($/Bbl)
United States $ 13.35 $ 20.24
Canada 12.34 17.30
North America Composite 13.18 19.72
Trinidad 12.85 18.88
India 13.31 20.78
COMPOSITE 13.17 19.66
NATURAL GAS EQUIVALENT VOLUMES (MMcfe PER DAY)
United States (1) 753 741
Canada 124 121
------------ ------------
North America 877 862
Trinidad 153 135
India 81 22
------------ ------------
TOTAL 1,111 1,019
============ ============
TOTAL Bcfe DELIVERIES 303 278
- --------------------------------------------------------------------------------
(1) Includes 48 MMcf per day for the nine-month periods ended September 30,
1998 and 1997 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.51/Mcf and
$1.61/Mcf for the nine-month periods ended September 30, 1998 and 1997,
respectively, for the volumes described in note (1), net of
transportation costs.
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PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
Wellhead revenues decreased 5% to $556 million in the first nine months of
1998 compared to $587 million in the first nine months of 1997, primarily due to
lower average wellhead prices for natural gas, crude oil and condensate and
natural gas liquids, partially offset by increased production volumes of natural
gas and crude oil and condensate.
During the first nine months of 1998, average wellhead natural gas prices
were approximately 9% lower than the comparable period of 1997 reducing net
operating revenues by approximately $44 million. Average wellhead crude oil and
condensate prices were down by 33% worldwide decreasing net operating revenues
by $43 million. Revenues from the sale of natural gas liquids decreased $4
million primarily due to lower wellhead prices.
Wellhead natural gas volumes were approximately 7% higher than the
comparable period in 1997 increasing net operating revenues by nearly $33
million. Natural gas production in India increased 42 MMcf per day from the
Tapti and Panna fields, which did not commence production until late in the
second quarter of 1997 and the first quarter of 1998, respectively. Production
in Trinidad increased nearly 21 MMcf per day due primarily to gas balancing
volumes relating to a field allocation agreement. North America wellhead natural
gas production was approximately equal to the prior year period. Wellhead crude
oil and condensate volumes were 26% higher than the prior year period increasing
net operating revenues by $27 million, primarily due to a 19% increase in North
America volumes and increased production from the Panna and Mukta fields in
India resulting from the ongoing development program and a shut-down of crude
oil production in the second quarter of 1997 to allow for the conversion from
temporary to permanent production facilities.
Other marketing activities associated with sales and purchases of natural
gas, natural gas and crude oil price hedging and trading transactions and
margins related to the volumetric production payment decreased net operating
revenue by $1 million during the first nine months of 1998, compared to a $55
million reduction in the first nine months of 1997, representing an improvement
of $54 million.
During the first nine months of 1998, operating expenses of $484 million
were approximately $57 million higher than the first nine months of 1997. DD&A
expense increased approximately $25 million compared to the first nine months of
1997, primarily reflecting a higher per unit rate in North America and increased
international production volumes. Dry hole expenses and exploration expenses
increased $12 million and $9 million, respectively, primarily due to an increase
in exploratory drilling and other exploration activities in North America during
the first nine months of 1998. General and administrative expenses were $7
million higher than the comparable prior year period due to expanded worldwide
operations.
Net interest expense increased $15 million during the first nine months of
1998 reflecting a higher level of long-term debt due to expanded worldwide
operations and common stock repurchases.
The per unit operating costs of the Company for lease and well, DD&A,
general and administrative, interest expense and taxes other than income
averaged $1.40 per Mcfe during the first nine months of 1998 compared to $1.36
per Mcfe in 1997. This increase is primarily due to a higher per unit rate of
interest expense, DD&A expense and general and administrative expenses,
partially offset by a lower per unit rate of lease and well expense and taxes
other than income.
Income tax provision decreased $15 million for the first nine months of
1998 as compared to the first nine months of 1997 primarily due to lower pre-tax
income.
Federal income taxes accrued in interim periods are calculated using the
estimated annual effective income tax rate.
-12-
13
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources of cash during the nine months ended
September 30, 1998, included funds generated from operations, proceeds from
sales of selected oil and gas reserves and related assets and proceeds from new
borrowings. Primary cash outflows included funds used in operations, exploration
and development expenditures, common stock repurchases, dividends paid to
Company shareholders and the repayment of debt.
Net operating cash flows of $319 million for the first nine months of 1998
decreased approximately $30 million as compared to the first nine months of 1997
primarily reflecting increased working capital for operating activities, higher
interest expense and increased cash operating expenses, partially offset by
higher operating revenues.
Net investing cash outflows of $611 million for the first nine months of
1998 increased by $113 million as compared to the comparable prior year period
due primarily to increased exploration and development expenditures, partially
offset by higher proceeds from the sale of reserves and related assets.
Exploration and development expenditures for the first nine months of 1998
and 1997 were as follows (in millions):
- ----------------------------------------------------------------
1998 1997
- ----------------------------------------------------------------
NORTH AMERICA $ 556 $ 419
OUTSIDE NORTH AMERICA
India 38 57
Venezuela 27 9
Trinidad 20 1
Other 9 11
--------- ---------
TOTAL $ 650 $ 497
========= =========
- ----------------------------------------------------------------
Exploration and development expenditures of $650 million for the first nine
months of 1998 were $153 million higher than the prior year period due to the
third quarter acquisition of producing properties in the Gulf of Mexico for $156
million. Expenditures in Venezuela reflected the drilling of the Company's first
well in the Gulf of Paria during the third quarter. Proved hydrocarbons were
present, however, further evaluation of the block has been postponed until 1999
due to the current crude oil price environment. Spending in Trinidad increased
due to drilling expenditures relating to the U(a) block and ongoing development
of the SECC block. While development activities are continuing in India, 1998
expenditures decreased because the prior year included expenditures associated
with the installation of permanent production facilities.
The level of exploration and development expenditures will vary in future
periods depending on energy market conditions and other related economic
factors. The Company has significant flexibility with respect to financing
alternatives and the ability to adjust its exploration and development
expenditure budget as circumstances warrant. There are no material continuing
commitments associated with expenditure plans.
Cash provided by financing activities was $292 million for the first nine
months of 1998 as compared to $148 million for the prior year period. Financing
activities for 1998 included the net issuance of $333 million of long-term debt
primarily to fund exploration and development activities, repurchase shares of
the Company's common stock and to pay cash dividends. Share repurchases for the
first nine months of 1998 totaled $25 million as compared to repurchases of $58
million in the prior year period. Based upon existing economic and market
conditions, management believes net operating cash flow and available financing
alternatives will be sufficient to fund net investing and other cash
requirements of the Company for the foreseeable future.
-13-
14
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
YEAR 2000
The Year 2000 problem generally results from the use in computer hardware
and software of two digits rather than four digits to define the applicable
year. When computer systems must process dates both before and after January 1,
2000, two-digit year "fields" may create processing ambiguities that can cause
errors and system failures. For example, a date represented by "00" may be
interpreted as referring to the year 1900, instead of 2000.
The effects of the Year 2000 problem can be exacerbated by the
interdependence of computer and telecommunications systems in the United States
and throughout the world. This interdependence can affect the Company and its
suppliers, trading partners, and customers, as well as governments of countries
around the world where the Company does business.
State of Readiness
The Company Board of Directors has been briefed about the Year 2000
problem. The Board has adopted a Year 2000 Project (the "Project") aimed at
preventing the Company's mission-critical functions from being impaired due to
the Year 2000 problem. "Mission-critical" functions are those critical functions
whose loss would cause an immediate stoppage of or significant impairment to
core business processes (a core business process is one of material importance
to the Company business).
Implementation of the Project is directly supervised by a Year 2000
Oversight Committee, made up of four senior executives of the Company and its
affiliates. Each operating division of the Company is implementing procedures
specific to it that are part of the overall Project. The Company also has
engaged certain outside consultants, technicians and other external resources to
aid in formulating and implementing the Project.
The Company is actively implementing the Project, which will be modified as
events warrant. Under the Project, the Company will continue to inventory
mission-critical computer hardware and software systems and embedded
microprocessors (microprocessors with date-related functions, contained in a
wide variety of devices), and software; assess the effects of Year 2000 problems
on the mission-critical functions of the Company; remedy systems, software and
embedded microprocessors in an effort to avoid material disruptions or other
material adverse effects on mission-critical functions, processes and systems;
verify and test the mission-critical systems to which remediation efforts have
been applied; and attempt to mitigate those mission-critical aspects of the Year
2000 problem that are not remediated by January 1, 2000, including the
development of contingency plans to cope with the mission-critical consequences
of Year 2000 problems that have not been identified or remediated by that date.
The Project recognizes that the computer, telecommunications, and other
systems ("Outside Systems") of outside entities ("Outside Entities") have the
potential for major, mission-critical, adverse effects on the conduct of Company
business. The Company does not have control of these Outside Entities or Outside
Systems. (In some cases, Outside Entities are U.S., state and local governmental
organizations, foreign governments or businesses located in foreign countries.)
However, the Project includes an ongoing process of identifying and contacting
Outside Entities whose systems in the Company's judgment have, or may have, a
substantial effect on the Company's ability to continue to conduct the
mission-critical aspects of Company business without disruption from Year 2000
problems. The Project envisions the Company making an attempt to inventory and
assess the extent to which these Outside Systems may not be "Year 2000 ready" or
"Year 2000 compatible". The Company will attempt reasonably to coordinate with
these Outside Entities in an ongoing effort to obtain assurance that the Outside
Systems that are mission-critical will be Year 2000 compatible well before
January 1, 2000. Consequently, the Company will work prudently with Outside
Entities in a reasonable attempt to inventory, assess, analyze, convert (where
necessary), test, and develop contingency plans for connections to these
mission-critical Outside Systems and to ascertain the extent to which they are,
or can be made to be, Year 2000 ready and compatible with the Company's
remediation of its own mission-critical systems.
-14-
15
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
YEAR 2000 (CONTINUED)
As of November 1998, the Company is at various stages in implementation of
the Project, as shown in the following tables. Any notation of "complete"
conveys the fact only that the initial iteration of this phase has been
substantially completed. All dates are only relevant for the initial iteration
of the applicable stage of the Project.
- ---------------------------------------------------------------------------------------------------------
Year 2000 Project Readiness
- ---------------------------------------------------------------------------------------------------------
Inventory Assessment Analysis Conversion Testing Y2K-Ready Contingency Plan
- ---------------------------------------------------------------------------------------------------------
Mission-Critical IP IP IP IP IP IP IP
Internal Items
- ---------------------------------------------------------------------------------------------------------
Mission-Critical IP IP IP IP IP IP IP
Outside Entities
- ---------------------------------------------------------------------------------------------------------
Legend: C = Complete IP = In Process
- ---------------------------------------------------------------------------------------------------------
Year 2000 Project Estimated
Completion Dates
- ---------------------------------------------------------------------------------------------------------
Inventory Assessment Analysis Conversion Testing Y2K-Ready Contingency Plan
- ---------------------------------------------------------------------------------------------------------
Mission-Critical 12/98 12/98 3/99 6/99 9/99 9/99 9/99
Internal Items
- ---------------------------------------------------------------------------------------------------------
Mission-Critical 3/99 6/99 6/99 9/99 9/99 9/99 9/99
Outside Entities
- ---------------------------------------------------------------------------------------------------------
It is important to recognize that the processes of inventorying, assessing,
analyzing, converting (where necessary), testing, and developing contingency
plans for mission-critical items in anticipation of the Year 2000 event may be
iterative processes, requiring a repeat of some or all of these processes as the
Company learns more about the Year 2000 problem and its effects on internal
business information systems and on Outside Systems, and about the effects of
embedded microprocessors on systems and business operations. The Company
anticipates that it will continue with these processes through January 1, 2000
and on into the Year 2000 in order to assess and remediate problems that
reasonably can be identified only after the start of the new century.
The Project envisions verification and validation of certain
mission-critical facilities and functions by independent consultants. These
consultants will participate to varying degrees in many or all of the stages,
including the inventory, assessment, and testing phases. Currently, the Company
is utilizing Raytheon Engineers & Constructors, Inc. to assist Company personnel
in the inventory and assessment phases of onshore and offshore and domestic and
international operations.
Costs to Address Year 2000 Issues
The Company has not incurred material historical costs for Year 2000
awareness, inventory, assessment, analysis, conversion, testing, or contingency
planning and anticipates that any future costs for these purposes, including
those for implementing Year 2000 contingency plans, are not likely to be
material.
Although management believes that its estimates are reasonable, there can
be no assurance, for the reasons stated in the "Summary" section below, that the
actual costs of implementing the Project will not differ materially from the
estimated costs or that the Company will not be materially adversely affected by
Year 2000 issues.
Year 2000 Risk Factors
Regulatory requirements. Certain of the Company's operations are regulated
by governmental authorities. The Company expects to satisfy these regulatory
authority requirements for achieving Year 2000 readiness. If the Company's
reasonable expectations in this regard are in error, and if a regulatory
authority should order the temporary cessation of operations in one or more of
these areas, the adverse effect on the Company could be material. Outside
Entities may face similar problems that materially adversely affect the Company.
-15-
16
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
YEAR 2000 (CONTINUED)
Shortage of Resources. Between now and 2000 it is anticipated that there
will be increased competition for people with technical and managerial skills
necessary to deal with the Year 2000 problem. While the Company is taking
substantial precautions to recruit and retain sufficient people skilled in
dealing with the Year 2000 problem, and has hired consultants who bring
additional skilled people to deal with the Year 2000 problem, the Company could
face shortages of skilled personnel or other resources, such as particular
microprocessors or components containing Year 2000 ready microprocessors, and
these shortages might delay or otherwise impair the Company's ability to assure
that its mission-critical systems are Year 2000 ready. Outside Entities could
face similar problems that materially adversely affect the Company. The Company
believes that the possible impact of the shortage of skilled people and
resources is not, and will not be, unique to the Company.
Potential Shortcomings. The Company estimates that mission-critical
systems, domestic and international, will be Year 2000-ready substantially
before January 1, 2000. However, there is no assurance that the Project will
succeed in accomplishing its purpose, or that unforeseen circumstances will not
arise during implementation of the Project that would materially and adversely
affect the Company.
Cascading Effect. The Company is taking reasonable steps to identify,
assess, and, where appropriate, to replace devices that contain embedded
microprocessors. Despite these reasonable efforts, the Company anticipates that
it will not be able to find and remediate all embedded microprocessors in all
systems. Further, it is anticipated that Outside Entities also will not be able
to find and remediate all embedded microprocessors in their systems. Some of the
embedded microprocessors that fail to operate or that produce anomalous results
may create system disruptions or failures. Some of these disruptions or failures
may spread from the systems in which they are located to other systems causing
adverse effects upon the Company's ability to maintain safe operations, to serve
its customers and otherwise to fulfill certain contractual and other legal
obligations. The embedded microprocessor problem is widely recognized as one of
the more difficult aspects of the Year 2000 problem across industries and
throughout the world. The possible adverse impact of the embedded microprocessor
problem is not, and will not be, unique to the Company.
Third parties. The Company cannot assure that suppliers upon which it
depends for essential goods and services will convert and test their
mission-critical systems and processes in a timely manner. Failure of delay by
all or some of these entities, including the U.S. and state or local governments
and foreign governments, could create substantial disruptions having a material
adverse affect on Company business.
Contingency Plans
As part of the Project, the Company is developing contingency plans that
deal with, among others, two primary aspects of the Year 2000 problem: (1) that
the Company, despite its good-faith, reasonable efforts, may not have
satisfactorily remediated all internal, mission-critical systems; and (2) that
Outside Systems may not be Year 2000 ready, despite the Company's good-faith,
reasonable efforts to work with Outside Entities. These contingency plans are
being designed to minimize the disruptions or other adverse effects resulting
from Year 2000 incompatibilities regarding these mission-critical functions or
systems, and to facilitate the early identification and remediation of
mission-critical Year 2000 problems that first manifest themselves after January
1, 2000.
These contingency plans will contemplate an assessment of all
mission-critical internal information technology systems and internal
operational systems that use computer-based controls. This process will be
pursued continuously into the Year 2000 as circumstances require. Further, the
Company will in that time frame assess any mission-critical disruptions due to
Year 2000-related failures that are external to the Company.
These contingency plans include the creation, as deemed reasonably
appropriate, of teams that will be standing by on the eve of the new millennium,
prepared to respond rapidly and otherwise as necessary to mission-critical Year
2000-related problems as soon as they become known. The composition of teams
that are assigned to deal with Year 2000 problems will vary according to the
nature, mission-criticality, and location of the problem. Because the Company
operates internationally, some of its Year 2000 contingency teams will be
located at mission-critical facilities overseas.
-16-
17
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
ENRON OIL & GAS COMPANY
YEAR 2000 (CONTINUED)
Worst Case Scenario
The Securities and Exchange Commission requires that public companies must
forecast the most reasonably likely worst case Year 2000 scenario, assuming that
the Company's Year 2000 plan is not effective. Analysis of the most reasonably
likely worst case Year 2000 scenarios the Company may face leads to
contemplation of the following possibilities which, though considered highly
unlikely, must be included in any consideration of worst cases: widespread
failure of electrical, gas, and similar supplies by utilities serving the
Company domestically and internationally; widespread disruption of the services
of communications common carriers domestically and internationally; similar
disruption to means and modes of transportation for the Company and its
employees, contractors, suppliers, and customers; significant disruption to the
Company's ability to gain access to, and continue working in, office buildings
and other facilities; the failure of substantial numbers of mission-critical
hardware and software computer systems, including both internal business systems
and systems (such as those with embedded microprocessors) controlling
operational facilities such as electrical generation, transmission, and
distribution systems and crude oil and natural gas plants and pipelines,
domestically and internationally; and the failure, domestically and
internationally, of Outside Systems, the effects of which would have a
cumulative material adverse impact on the Company's mission-critical systems.
Among other things, the Company could face substantial claims by customers for
loss of revenues due to supply interruptions, inability to fulfill contractual
obligations, inability to account for certain revenues or obligations or to bill
or pay customers accurately and on a timely basis, and increased expenses
associated with litigation, stabilization of operations following
mission-critical failures, and the execution of contingency plans. The Company
could also experience an inability by customers, traders, and others to pay, on
a timely basis or at all, obligations owed to the Company. Under these
circumstances, the adverse effect on the Company, and the diminution of Company
revenues, could be material, although not quantifiable at this time. Further in
this scenario, the cumulative effect of these failures could have a substantial
adverse effect on the economy, domestically and internationally. The adverse
effect on the Company, and the diminution of Company revenues, from a domestic
or global recession or depression also could be material, although not
quantifiable at this time.
The Company will continue to monitor business conditions with the aim of
assessing and quantifying material adverse effects, if any, that result or may
result from the Year 2000 problem.
Summary
The Company has a plan to deal with the Year 2000 challenge and believes
that it will be able to achieve substantial Year 2000 readiness with respect to
the mission critical systems that it controls. From a forward-looking
perspective, the extent and magnitude of the Year 2000 problem as it will affect
the Company, both before and for some period after January 1, 2000, are
difficult to predict or quantify for a number of reasons. Among these are: the
difficulty of locating "embedded" microprocessors that may be in a great variety
of mission-critical hardware used for process or flow control, environmental,
transportation, access, communications, and other systems; the difficulty of
inventorying, assessing, remediating, verifying and testing, Outside Systems
connected, and vital, to the Company's computer, telecommunications, or other
mission-critical systems; the difficulty of locating all mission-critical
software (computer code) that is not Year 2000 compatible; and the
unavailability of certain necessary internal or external resources, including
but not limited to trained hardware and software engineers, technicians, and
other personnel to perform adequate remediation, verification, and testing of
mission-critical Company systems or Outside Systems. Year 2000 costs are
difficult to estimate accurately because of unanticipated vendor delays,
technical difficulties, the impact of tests of Outside Systems, and similar
events. There can be no assurance for example that all Outside Systems with a
mission-critical impact will be adequately remediated so that they are Year 2000
ready by January 1, 2000, or by some earlier date, so as not to create a
material disruption to the Company's business. If, despite reasonable efforts
under the Year 2000 Project, there are mission-critical Year 2000-related
failures that create substantial disruptions to Company business, the adverse
impact on the Company could be material. Additionally, Year 2000 costs are
difficult to estimate accurately because of unanticipated vendor delays,
technical difficulties, the impact of tests of Outside Systems and similar
events. Moreover, despite the Company's belief that costs for implementing the
Project will not be material, the estimated costs of implementing the Project do
not take into account the costs, if any, that might be incurred as a result of
Year 2000-related failures that occur despite implementation of the Project.
-17-
18
PART I. FINANCIAL INFORMATION - (CONCLUDED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONCLUDED)
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes forward looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934. Although the Company believes that its
expectations are based on reasonable assumptions, it can give no assurance that
such expectations will be achieved. Important factors that could cause actual
results to differ materially from those in the forward looking statements herein
include, but are not limited to, the timing and extent of changes in commodity
prices for crude oil, natural gas and related products and interest rates, the
extent of the Company's success in discovering, developing, marketing and
producing reserves and in acquiring oil and gas properties, political
developments around the world and conditions of the capital and equity markets
during the periods covered by the forward looking statements.
-18-
19
PART II. OTHER INFORMATION
ENRON OIL & GAS COMPANY
ITEM 1. Legal Proceedings
See Part 1, Item 1, Note 5 to Consolidated Financial Statements which is
incorporated herein by reference.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges
(b) Reports on Form 8-K - There were no reports on Form 8-K filed for
the period ended September 30, 1998.
-19-
20
SIGNATURES
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.
ENRON OIL & GAS COMPANY
(Registrant)
Date: November 13, 1998 By /S/ W. C. WILSON
--------------------------
W. C. Wilson
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: November 13, 1998 By /S/ BEN B. BOYD
--------------------------
Ben B. Boyd
Vice President and Controller
(Principal Accounting Officer)
-20-
21
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
- ----------- -----------
EX-12 Computation of Ratio of Earning
to Fixed Charges
EX-27 Financial Data Schedule
22
EXHIBIT 12
ENRON OIL & GAS COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS
ENDED YEAR ENDED DECEMBER 31,
- ---------------------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, 1998 1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR
FIXED CHARGES:
Net Income $ 46,206 $ 121,970 $ 140,008 $ 142,118 $ 147,998 $ 138,025
Less: Capitalized Interest Expense (9,942) (13,706) (9,136) (6,490) (6,124) (5,457)
Add: Fixed Charges 43,104 41,423 21,997 18,414 14,613 15,378
Income Tax Provision(Benefit) 8,142 41,500 50,954 41,936 5,937 (25,752)
--------- --------- --------- --------- --------- ---------
EARNINGS AVAILABLE $ 87,510 $ 191,187 $ 203,823 $ 195,978 $ 162,424 $ 122,194
========= ========= ========= ========= ========= =========
FIXED CHARGES:
Interest Expense 33,046 27,369 12,370 11,310 8,135 9,921
Capitalized Interest 9,942 13,706 9,136 6,490 6,124 5,457
Rental Expense Representative of
Interest Factor 116 348 491 614 354 --
--------- --------- --------- --------- --------- ---------
TOTAL FIXED CHARGES $ 43,104 $ 41,423 $ 21,997 $ 18,414 $ 14,613 $ 15,378
========= ========= ========= ========= ========= =========
RATIO OF EARNINGS TO
FIXED CHARGES 2.03 4.62 9.27 10.64 11.12 7.95
- ---------------------------------------------------------------------------------------------------------------------------