<PAGE> 1
================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
-----------------
FORM 10-Q
-----------------
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 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
-----------------
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 July 31, 1998.
Common Stock, $.01 Par Value 154,503,355 shares
---------------------------- ------------------
Class Number of Shares
================================================================================
<PAGE> 2
ENRON OIL & GAS COMPANY
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Statements of Income - Three Months Ended June 30, 1998 and
1997 and Six Months Ended June 30, 1998 and 1997
Consolidated Balance Sheets - June 30, 1998 and December 31, 1997
Consolidated Statements of Cash Flows - Six Months Ended
June 30, 1998 and 1997
Notes to Consolidated Financial Statements
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
ITEM 6. Exhibits and Reports on Form 8-K
<PAGE> 3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
1998 1997 1998 1997
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Trade $ 135,113 $ 111,689 $ 264,680 $ 252,860
Associated Companies 15,510 21,247 38,533 18,648
Crude Oil, Condensate and Natural Gas Liquids
Trade 27,277 20,499 57,514 51,710
Associated Companies 2,815 9,900 5,554 19,581
Gains on Sales of Reserves and Related Assets and Other, Net 2,592 8,418 16,857 9,605
--------- --------- --------- ---------
TOTAL 183,307 171,753 383,138 352,404
OPERATING EXPENSES
Lease and Well 22,857 25,973 47,766 49,442
Exploration 16,600 15,019 33,998 30,502
Dry Hole 2,281 1,586 10,162 2,570
Impairment of Unproved Oil and Gas Properties 7,355 6,900 15,703 12,913
Depreciation, Depletion and Amortization 73,071 69,183 145,032 131,822
General and Administrative 15,204 12,114 31,758 25,721
Taxes Other Than Income 13,270 12,359 27,764 29,645
--------- --------- --------- ---------
TOTAL 150,638 143,134 312,183 282,615
--------- --------- --------- ---------
OPERATING INCOME 32,669 28,619 70,955 69,789
OTHER INCOME (EXPENSE), NET (73) 956 (1,043) 2,212
--------- --------- --------- ---------
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 32,596 29,575 69,912 72,001
INTEREST EXPENSE, NET 10,423 5,464 19,533 10,579
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES 22,173 24,111 50,379 61,422
INCOME TAX PROVISION (BENEFIT) 8,916 (460) 10,117 13,786
--------- --------- --------- ---------
NET INCOME $ 13,257 $ 24,571 $ 40,262 $ 47,636
========= ========= ========= =========
EARNINGS PER SHARE OF COMMON STOCK
Basic $ 0.09 $ 0.16 $ 0.26 $ 0.30
========= ========= ========= =========
Diluted $ 0.09 $ 0.16 $ 0.26 $ 0.30
========= ========= ========= =========
AVERAGE NUMBER OF COMMON SHARES
Basic 154,857 157,489 154,797 158,177
========= ========= ========= =========
Diluted 155,770 157,950 155,646 158,899
========= ========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 4
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1998 1997
----------- ------------
(UNAUDITED)
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and Cash Equivalents $ 13,568 $ 9,330
Accounts Receivable
Trade 161,657 185,979
Associated Companies 26,675 46,120
Inventories 34,816 32,040
Other 8,413 8,566
----------- -----------
TOTAL 245,129 282,035
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 4,487,783 4,291,405
Less: Accumulated Depreciation, Depletion and Amortization (2,027,948) (1,904,198)
----------- -----------
Net Oil and Gas Properties 2,459,835 2,387,207
OTHER ASSETS 57,997 54,113
----------- -----------
TOTAL ASSETS $ 2,762,961 $ 2,723,355
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Trade $ 166,066 $ 198,109
Associated Companies 36,803 37,613
Accrued Taxes Payable 14,633 28,841
Dividends Payable 4,724 4,705
Other 16,942 21,729
----------- -----------
TOTAL 239,168 290,997
LONG-TERM DEBT
Trade 850,860 548,775
Affiliate -- 192,500
OTHER LIABILITIES
Trade 18,119 37,739
Associated Companies 48,069 44,699
DEFERRED INCOME TAXES 291,498 287,678
DEFERRED REVENUE 15,413 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 402,647 402,877
Unearned Compensation (5,474) (4,694)
Cumulative Foreign Currency Translation Adjustment (26,799) (19,771)
Retained Earnings 831,684 800,709
Common Stock Held in Treasury, 5,158,156 shares at
June 30, 1998 and 4,935,744 shares at December 31, 1997 (103,824) (99,672)
----------- -----------
TOTAL SHAREHOLDERS' EQUITY 1,299,834 1,281,049
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,762,961 $ 2,723,355
=========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 5
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
------------------------
1998 1997
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income $ 40,262 $ 47,636
Items Not Requiring Cash
Depreciation, Depletion and Amortization 145,032 131,822
Impairment of Unproved Oil and Gas Properties 15,703 12,913
Deferred Income Taxes 11,980 6,372
Other, Net 3,520 983
Exploration Expenses 33,998 30,502
Dry Hole Expenses 10,162 2,570
Gains on Sales of Reserves and Related Assets and Other, Net (13,447) (7,492)
Other, Net (4,100) (4,141)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable 40,213 73,389
Inventories (2,776) (8,727)
Accounts Payable (37,391) (42,861)
Accrued Taxes Payable (14,208) (8,824)
Other Liabilities (23,196) 1,350
Other, Net (5,034) (611)
Amortization of Deferred Revenue (21,494) (21,494)
Changes in Components of Working Capital Associated with
Investing and Financing Activities 14,665 29,456
--------- ---------
NET OPERATING CASH INFLOWS 193,889 242,843
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (270,684) (297,069)
Exploration Expenses (33,998) (30,502)
Dry Hole Expenses (10,162) (2,570)
Proceeds from Sales of Reserves and Related Assets 54,688 15,822
Changes in Components of Working Capital Associated with
Investing Activities (14,518) (30,187)
Other, Net (5,604) (1,971)
--------- ---------
NET INVESTING CASH OUTFLOWS (280,278) (346,477)
FINANCING CASH FLOWS
Long-Term Debt
Trade 302,085 168,600
Affiliate (192,500) --
Dividends Paid (9,268) (9,519)
Treasury Stock Purchased (7,969) (49,194)
Proceeds from Sales of Treasury Stock 2,222 1,546
Other, Net (3,943) 1,088
--------- ---------
NET FINANCING CASH INFLOWS 90,627 112,521
--------- ---------
INCREASE IN CASH AND CASH EQUIVALENTS 4,238 8,887
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,330 7,644
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 13,568 $ 16,531
========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 6
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 six-month periods
ended June 30, 1998 and 1997 includes tax benefits of $2.5 million, $2.0
million, $3.8 million and $5.2 million, respectively, related to tight gas
sand federal income tax credit utilization. Additionally, the income tax
provision for the six-month period ended June 30, 1998 includes a benefit
of $3.4 million from certain recently incurred international costs and
other benefits of $5.0 million from the resolution of certain domestic and
international issues. Income tax provision (benefit) for the three-month
and six-month periods ended June 30, 1997 includes benefits of $9.7 million
related to the sales of certain international assets and subsidiaries and
the refiling of certain Canadian tax returns.
3. Natural gas revenues, trade for the three-month and six-month periods ended
June 30, 1998 and 1997, are net of costs of natural gas purchased for sale
related to natural gas marketing activities of $11.8 million, $16.3
million, $24.3 million and $39.4 million, respectively. Natural gas
revenues, associated for the three-month and six-month periods ended June
30, 1998 and 1997, are net of costs of natural gas purchased for sale
related to natural gas marketing activities of $12.0 million, $11.6
million, $24.4 million and $23.2 million, respectively.
<PAGE> 7
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Concluded)
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 common shares relating to employee stock options in each period
presented.
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 was $4 million, $24 million, $33
million and $46 million for the three-month and six-month periods ended
June 30, 1998 and 1997, respectively. The only adjustment made to net
income in the periods was for foreign currency translation adjustment.
8. In June 1998, the Financial Accounting Standards Board 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.
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. However, based on the Company's current level of derivative and
hedging activities, the Company does not expect the impact of adoption to
be material.
<PAGE> 8
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 six-month
periods ended June 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 June 30, 1998 vs. Three Months Ended June 30, 1997
The Company generated second quarter net income of $13 million compared to
net income of $25 million for the second quarter of 1997. Net operating revenues
were $183 million as compared to $172 million for the second quarter of 1997.
Operating income of $33 million increased $4 million, or 14%, as compared to the
second quarter of last year.
Wellhead volume and price statistics are as follows:
<TABLE>
<CAPTION>
1998 1997
------ ------
<S> <C> <C>
NATURAL GAS VOLUMES (MMCF PER DAY)(1)
United States (2) 624 689
Canada 98 92
------ ------
North America 722 781
Trinidad 132 114
India 53 1
------ ------
TOTAL 907 896
====== ======
AVERAGE NATURAL GAS PRICES ($/MCF)(3)
United States (4) $ 2.04 $ 1.87
Canada 1.41 1.25
North America Composite 1.96 1.80
Trinidad 1.08 1.04
India 2.57 2.97
COMPOSITE 1.87 1.70
CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY)(1)
United States 12.2 11.2
Canada 2.5 2.4
------ ------
North America 14.7 13.6
Trinidad 2.9 3.5
India 4.8 --
------ ------
TOTAL 22.4 17.1
====== ======
AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL)(3)
United States $13.10 $19.42
Canada 11.47 16.49
North America Composite 12.82 18.89
Trinidad 13.31 16.09
India 13.41 --
COMPOSITE 13.01 18.31
NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY)(5)
United States (2) 713 769
Canada 119 113
------ ------
North America 832 882
Trinidad 149 135
India 82 1
------ ------
TOTAL 1,063 1,018
====== ======
TOTAL BCFE(5)DELIVERIES 97 93
</TABLE>
- --------------------------------------------------------------------------------
(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 June 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 $1.57/Mcf and $1.24/Mcf
for the three-month periods ended June 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.
<PAGE> 9
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 increased 8% to $183 million in the second quarter of
1998 compared to $170 million in the second quarter of 1997 primarily due to
higher wellhead natural gas prices in North America and increased production
volumes of natural gas and crude oil and condensate in India. Second quarter
1998 average wellhead natural gas prices for North America were approximately 9%
higher than the comparable period of 1997 increasing net operating revenues by
approximately $10 million. Average wellhead crude oil and condensate prices were
down by 29% worldwide decreasing net operating revenues by $11 million.
Second quarter wellhead natural gas volumes were slightly higher than the
comparable period in 1997 increasing net operating revenues by $6 million. This
increase was primarily due to 53 MMcf per day from the Tapti and Panna fields in
India, which did not begin sales of natural gas until late in the second quarter
of 1997. North America wellhead natural gas production was approximately 8%
lower than the prior year period. The prior year period reflected benefits from
higher production prior to payout of a South Texas property. Wellhead crude oil
and condensate volumes were 31% higher than the prior year period increasing net
operating revenues by nearly $9 million, primarily due to increased production
from the Panna and Mukta fields in India which were shut down during the second
quarter of 1997 to allow for the conversion from temporary to permanent
production facilities. North America wellhead crude oil and condensate
production increased 8% from the second quarter of 1997.
Gains on sales of reserves and related assets and other, net totaled $3
million in the second quarter of 1998 compared to $8 million in the comparable
period of 1997. Included in 1997 were $5 million in net gains on the sale of
certain international assets and subsidiaries and $2 million in gains on the
sale of producing properties in North America.
During the second quarter of 1998, operating expenses of $151 million were
approximately $8 million higher than in the second quarter of 1997.
Depreciation, depletion and amortization ("DD&A") expense increased by $4
million reflecting increased international production volumes and a higher per
unit rate in North America. General and administrative ("G&A") expense increased
approximately $3 million due primarily to expanded worldwide operations.
Exploration expenses and dry hole expenses were $2 million higher than the
second quarter of 1997 due to increased exploration activities in North America.
Lease and well expense decreased $3 million due primarily to certain North
America workover expenses included in the prior year period. Taxes other than
income were $1 million higher than the second quarter of 1997 due to an increase
in taxable wellhead revenues as discussed above.
The per unit operating costs of the Company for lease and well, DD&A, G&A,
interest expense, and taxes other than income averaged $1.39 per Mcfe during the
second quarter of 1998 compared to $1.35 per Mcfe during the second quarter of
1997. This increase is primarily due to a higher per unit rate of interest
expense, G&A expense and DD&A expense, partially offset by a lower per unit rate
of lease and well expense.
Net interest expense increased $5 million as compared to the second quarter
of 1997 reflecting a higher level of long-term debt due to expanded worldwide
operations and stock repurchases.
Income tax provision (benefit) increased $9 million as compared to the
second quarter of 1997 primarily due to benefits of $9.7 million related to the
sales of certain international assets and subsidiaries and the refiling of
certain Canadian tax returns in the prior year period.
Federal income taxes accrued in interim periods are calculated using the
estimated annual effective income tax rate.
<PAGE> 10
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS--(Continued)
ENRON OIL & GAS COMPANY
Six Months Ended June 30, 1998 vs. Six Months Ended June 30, 1997
In the first half of 1998, the Company generated net income of $40 million
compared to net income of $48 million for the first half of 1997. Net operating
revenues for the first half of 1998 were $383 million as compared to $352
million for the first half of 1997. Operating income of $71 million increased $1
million as compared to the prior year period.
Wellhead volume and price statistics are as follows:
<TABLE>
<CAPTION>
1998 1997
------ ------
<S> <C> <C>
NATURAL GAS VOLUMES (MMCF PER DAY)
United States (1) 634 666
Canada 99 93
------ ------
North America 733 759
Trinidad 121 113
India 50 1
------ ------
TOTAL 904 873
====== ======
AVERAGE NATURAL GAS PRICES ($/MCF)
United States (2) $ 2.03 $ 2.28
Canada 1.40 1.48
North America Composite 1.94 2.18
Trinidad 1.08 1.04
India 2.63 2.97
COMPOSITE 1.87 2.03
CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY)
United States 12.4 10.9
Canada 2.6 2.4
------ ------
North America 15.0 13.3
Trinidad 2.8 3.6
India 4.5 1.4
------ ------
TOTAL 22.3 18.3
====== ======
AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL)
United States $13.90 $20.84
Canada 12.77 17.25
North America Composite 13.70 20.19
Trinidad 13.66 18.86
India 14.31 22.99
COMPOSITE 13.82 20.15
NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY)
United States (1) 724 746
Canada 121 115
------ ------
North America 845 861
Trinidad 138 135
India 78 9
------ ------
TOTAL 1,061 1,005
====== ======
TOTAL BCFE DELIVERIES 192 182
</TABLE>
- --------------------------------------------------------------------------------
(1) Includes 48 MMcf per day for the six-month periods ended June 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 $1.59/Mcf and $1.85/Mcf
for the six-month periods ended June 30, 1998 and 1997, respectively, for
the volumes described in note (1), net of transportation costs.
<PAGE> 11
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 7% to $367 million in the first half of 1998
compared to $396 million in the first half 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 in India. First half 1998 average wellhead natural gas
prices were approximately 8% lower than the comparable period of 1997 reducing
net operating revenues by approximately $34 million. Average wellhead crude oil
and condensate prices were down by 31% worldwide decreasing net operating
revenues by $26 million.
First half wellhead natural gas volumes were approximately 4% higher than
the comparable period in 1997 increasing net operating revenues by $18 million.
This increase was primarily due to 50 MMcf per day from the Tapti and Panna
fields in India, which did not begin sales of natural gas until late in the
second quarter of 1997. North America wellhead natural gas production was
approximately 4% lower than the prior year period, which reflected benefits from
higher production prior to pay-out of a South Texas property. Wellhead crude oil
and condensate volumes were 22% higher than the prior year period increasing net
operating revenues by nearly $15 million, primarily due to a 13% increase in
North America volumes and increased production from the Panna and Mukta fields
in India resulting from the ongoing development program and the previously
mentioned shut-down in the second quarter of 1997.
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 less than $1 million during the first half of 1998, compared to a $53
million reduction in the first half of 1997.
During the first half of 1998, operating expenses of $312 million were
approximately $30 million higher than the first half of 1997. DD&A expense
increased approximately $13 million compared to the first half of 1997,
primarily reflecting a higher per unit rate in North America and increased
international production volumes. Dry hole expenses and exploration expenses
increased $8 million and $3 million, respectively, primarily due to an increase
in exploratory drilling and other exploration activities in North America during
the first half of 1998. G&A expense was $6 million higher than the comparable
prior year period due primarily to expanded worldwide operations.
The per unit operating costs of the Company for lease and well, DD&A, G&A,
interest expense and taxes other than income averaged $1.42 per Mcfe during the
first half 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
G&A expense, partially offset by a lower per unit rate of lease and well expense
and taxes other than income.
Net interest expense increased $9 million during the first half of 1998
reflecting a higher level of long-term debt due to expanded worldwide operations
and stock repurchases.
Income tax provision decreased $4 million in the first half of 1998 as
compared to the first half of 1997 primarily due to lower income before income
taxes. The 1998 income tax provision included a $3.4 million benefit associated
with certain recently incurred international costs and approximately $5.0
million of other benefits from resolution of certain domestic and international
issues. In 1997, the Company recognized $9.7 million in benefits related to the
sales of certain international assets and subsidiaries and the refiling of
certain Canadian tax returns.
Federal income taxes accrued in interim periods are calculated using the
estimated annual effective income tax rate.
<PAGE> 12
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 six months ended June 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.
Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is derived by adjusting net income to
eliminate the effects of DD&A, impairment of unproved oil and gas properties,
deferred income taxes, gains on sales of reserves and related assets, certain
other miscellaneous non-cash amounts, except for amortization of deferred
revenue, and exploration and dry hole expenses. The Company generated
discretionary cash flow of $243 million during the first six months of 1998
compared to $221 million generated for the comparable period in 1997 primarily
reflecting increased cash operating revenues and lower current income taxes
partially offset by higher interest expense.
Net operating cash flows of $194 million for the first half of 1998
decreased approximately $49 million as compared to the first half of 1997
primarily reflecting increased working capital for operating activities. Based
upon existing economic and market conditions, management believes net operating
cash flow and available financing alternatives in 1998 will be sufficient to
fund net investing and other cash requirements of the Company for the remainder
of the year.
Exploration and development expenditures for the first six months of 1998
and 1997 are as follows (in millions):
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
NORTH AMERICA $263 $271
OUTSIDE NORTH AMERICA
India 25 44
Trinidad 13 --
Other 14 15
---- ----
TOTAL $315 $330
==== ====
</TABLE>
Exploration and development expenditures of $315 million for the first half
of 1998 were $15 million lower than expenditures in the first half of 1997
due primarily to lower expenditures in India due to the completion of production
facilities in 1997. Expenditures in North America were lower than the
prior year period due to decreased expenditures for unproved leases partially
offset by increased exploratory and developmental drilling activities. Spending
in Trinidad increased due to expenditures relating to the U(a) block.
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.
<PAGE> 13
PART I. FINANCIAL INFORMATION - (Concluded)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Concluded)
ENRON OIL & GAS COMPANY
Year 2000
The Year 2000 problem results from the use in computer hardware and
software of two digits rather than four digits to define the applicable year.
The use of two digits was a common practice for decades when computer storage
and processing was much more expensive than today. 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, computer programs that have date-sensitive features may recognize
a date represented by "00" as the year 1900, instead of 2000. These errors or
failures may have limited effects, or the effects may be widespread, depending
on the microprocessor, system or software, and its location and function.
The effects of the Year 2000 problem are exacerbated because of the
interdependence of computer and telecommunications systems in the United States
and throughout the world. This interdependence is true for the Company and
some of the suppliers, trading partners, and customers that work with the
Company, as well as among the governments of countries around the world where
the Company does business.
The Company has implemented a course of action to identify and remediate
Year 2000 problems. Under this course of action, an inventory of computer
hardware and software systems and "embedded" microprocessors and related
firmware and software is being prepared; assessments are being made of the
effects of Year 2000-related problems on the Company; remedies for those
problems are being developed to the maximum practicable extent; verification
and testing is being done for the systems to which remediation efforts have
been applied; and attempts are being made to ameliorate those aspects of the
Year 2000 problem that cannot practicably be remediated by January 1, 2000,
including the development of contingency plans to cope with consequences of
Year 2000 problems that may not have been identified or remediated by that
date. The course of action being taken by the Company may be modified as
events warrant.
The Company has engaged certain outside consultants, technicians and other
external resources to aid in formulating and implementing the required changes.
The course of action being taken by the Company recognizes that the
computer, telecommunications, and other systems ("Outside Systems") of outside
entities ("Outside Entities") play a major role in the conduct of the business
of the Company. The Company does not have control of these Outside Entities or
Outside Systems. (In some cases, Outside Entities are foreign governments or
businesses located in foreign countries.) However, the course of action being
taken by the Company includes an ongoing process of contacting Outside
Entities whose systems have, or may have, a substantial effect on the ability
of the Company to continue to conduct business without disruption from Year
2000 problems. The Company will attempt diligently to coordinate with these
Outside Entities in an ongoing effort to obtain assurance that these Outside
Systems will be Year 2000 compatible well before January 1, 2000. To the
extent that Outside Systems are not reasonably expected to be Year 2000 ready,
the Company intends to develop contingency plans in an attempt to minimize the
disruptions or other adverse effects resulting from Year 2000
incompatibilities.
As of August 1, 1998, the Company is in various stages in implementation of
the course of action.
Although it is difficult to estimate the total costs, through January 1,
2000 and beyond, of implementing the course of action, the Company's
preliminary estimate is that such costs will not be material. Although
management believes that its estimate is reasonable, there can be no assurance,
for the reasons stated in the next paragraph, that the actual costs of
implementing the course of action will not differ materially from the estimated
costs or that the Company will not be adversely affected by Year 2000-related
issues.
From a forward-looking perspective, the extent and magnitude of the Year
2000 Problem as it may 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 the most important are the potential complexity of locating
embedded microprocessors that may be in a great variety of hardware used for
process or flow control, environmental, transportation, access, communications
and other systems. The Company believes that it will be able to identify and
remediate mission-critical systems containing embedded microprocessors and will
have contingency plans to deal with these systems. Other important
difficulties relate to the lack of control over, and difficulty associated with
inventorying, assessing, remediating, verifying and testing, Outside Systems
connected, and vital, to computer, telecommunications or other
mission-critical systems of the Company; the complexity of evaluating all
software (computer code) internal to the Company that may not be Year 2000
compatible; and the potential limited availability 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 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 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 Company business. If, despite diligent, prudent efforts under
its Year 2000 course of action being pursued, there are Year 2000-related
failures that create substantial disruptions to Company business, the adverse
impact on Company business could be material. Moreover, the estimated costs
of pursuing the Company's current course of action do not take into account the
costs, if any, that might be incurred as a result of Year 2000-related failures
that occur despite completion by the Company of the course of action currently
being pursued and as it may be modified over time.
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.
<PAGE> 14
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
Current Report on Form 8-K filed on April 17, 1998 to report the
sale on April 8, 1998 of $150 million principal amount of 6.65%
notes due April 1, 2028 pursuant to an underwritten public
offering.
<PAGE> 15
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: August 14, 1998 By /S/ W. C. WILSON
-------------------------------
W. C. Wilson
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 14, 1998 By /S/ BEN B. BOYD
-------------------------------
Ben B. Boyd
Vice President and Controller
(Principal Accounting Officer)
<PAGE> 1
EXHIBIT 12
ENRON OIL & GAS COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------
JUNE 30, 1998 1997 1996 1995 1994 1993
------------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR
FIXED CHARGES:
Net Income $ 40,262 $ 121,970 $ 140,008 $ 142,118 $ 147,998 $ 138,025
Less: Capitalized Interest Expense (6,608) (13,706) (9,136) (6,490) (6,124) (5,457)
Add: Fixed Charges 26,141 41,423 21,997 18,414 14,613 15,378
Income Tax Provision(Benefit) 10,117 41,500 50,954 41,936 5,937 (25,752)
--------- --------- --------- --------- --------- ---------
EARNINGS AVAILABLE $ 69,912 $ 191,187 $ 203,823 $ 195,978 $ 162,424 $ 122,194
========= ========= ========= ========= ========= =========
FIXED CHARGES:
Interest Expense $ 19,417 $ 27,369 $ 12,370 $ 11,310 $ 8,135 $ 9,921
Capitalized Interest 6,608 13,706 9,136 6,490 6,124 5,457
Rental Expense Representative of
Interest Factor 116 348 491 614 354 --
--------- --------- --------- --------- --------- ---------
TOTAL FIXED CHARGES $ 26,141 $ 41,423 $ 21,997 $ 18,414 $ 14,613 $ 15,378
========= ========= ========= ========= ========= =========
RATIO OF EARNINGS TO
FIXED CHARGES 2.67 4.62 9.27 10.64 11.12 7.95
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> APR-01-1998
<PERIOD-END> JUN-30-1998
<CASH> 13,568
<SECURITIES> 0
<RECEIVABLES> 188,332
<ALLOWANCES> 0
<INVENTORY> 34,816
<CURRENT-ASSETS> 245,129
<PP&E> 4,487,783
<DEPRECIATION> 2,027,948
<TOTAL-ASSETS> 2,762,961
<CURRENT-LIABILITIES> 239,168
<BONDS> 0
0
0
<COMMON> 201,600
<OTHER-SE> 1,098,234
<TOTAL-LIABILITY-AND-EQUITY> 2,762,961
<SALES> 180,715
<TOTAL-REVENUES> 183,307
<CGS> 0
<TOTAL-COSTS> 150,638
<OTHER-EXPENSES> 73
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,423
<INCOME-PRETAX> 22,173
<INCOME-TAX> 8,916
<INCOME-CONTINUING> 13,257
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 13,257
<EPS-PRIMARY> .09<F1>
<EPS-DILUTED> .09
<FN>
<F1>Basic
</FN>
</TABLE>
