<PAGE>
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
(X) Quarterly Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the quarterly period ended September 30, 1995
( )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 of (I.R.S. Employer Identification No.)
incorporation or organization)
1400 Smith Street, P.O. Box 4362
Houston, Texas 77210-4362
(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 October 31, 1995.
Common Stock, $.01 Par Value 159,799,955 shares
Class Number of Shares
<PAGE>
ENRON OIL & GAS COMPANY
TABLE OF CONTENTS
Page No.
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Statements of Income -
Three Months Ended September 30, 1995 and 1994
and Nine Months Ended September 30, 1995 and 1994 3
Consolidated Balance Sheets - September 30, 1995 and
December 31, 1994 4
Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 1995 and 1994 5
Notes to Consolidated Financial Statements 6
ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 10
PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K 16
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts)
(Unaudited)
<TABLE>
Three Months Ended Nine Months Ended
September 30, September 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Associated Companies $ 55,893 $ 57,382 $177,963 $198,743
Trade 58,992 48,929 154,052 166,911
Crude Oil, Condensate and Natural Gas Liquids
Associated Companies 14,293 13,130 44,304 31,142
Trade 17,982 7,424 46,038 21,490
Gains on Sales of Reserves and Related Assets 3,268 33,264 62,546 52,212
Other 2,578 554 7,439 3,842
Total 153,006 160,683 492,342 474,340
OPERATING EXPENSES
Lease and Well 19,309 13,416 52,918 44,782
Exploration 9,636 9,958 31,590 29,647
Dry Hole 1,681 2,709 8,586 10,803
Impairment of Unproved Oil & Gas Properties 6,337 6,864 20,453 17,364
Depreciation, Depletion and Amortization 56,172 54,628 157,875 181,645
General and Administrative 14,003 13,766 41,186 38,050
Taxes Other Than Income 7,943 7,322 25,606 22,010
Total 115,081 108,663 338,214 344,301
OPERATING INCOME 37,925 52,020 154,128 130,039
OTHER INCOME(EXPENSE) (1,033) 555 (1,143) 2,238
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 36,892 52,575 152,985 132,277
INTEREST EXPENSE
Incurred
Affiliate 103 275 591 275
Other 5,050 3,306 13,218 10,352
Capitalized (1,605) (1,503) (4,999) (4,516)
Net Interest Expense 3,548 2,078 8,810 6,111
INCOME BEFORE INCOME TAXES 33,344 50,497 144,175 126,166
INCOME TAX PROVISION 376 9,529 33,444 20,728
NET INCOME $ 32,968 $ 40,968 $110,731 $105,438
EARNINGS PER SHARE OF COMMON STOCK $ .21 $ .26 $ .69 $ .66
AVERAGE NUMBER OF COMMON SHARES 159,916 159,777 159,951 159,826
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In Thousands)
<TABLE>
September 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 8,456 $ 5,810
Accounts Receivable
Associated Companies 60,233 57,352
Trade 102,589 68,781
Inventories 11,640 15,731
Other 8,628 8,744
Total 191,546 156,418
OIL AND GAS PROPERTIES (Successful Efforts Method) 3,266,736 3,015,435
Less: Accumulated Depreciation, Depletion and
Amortization (1,423,586) (1,330,624)
Net Oil and Gas Properties 1,843,150 1,684,811
OTHER ASSETS 75,275 20,638
TOTAL ASSETS $2,109,971 $1,861,867
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Associated Companies $ 17,631 $ 13,353
Trade 101,437 117,791
Accrued Taxes Payable 23,404 17,631
Dividends Payable 4,797 4,800
Other 9,237 11,026
Total 156,506 164,601
LONG-TERM DEBT
Affiliate 16,320 25,000
Other 247,552 165,337
OTHER LIABILITIES 13,915 10,035
REDEEMABLE PREFERRED STOCK 19,000 -
DEFERRED INCOME TAXES 292,298 269,292
DEFERRED REVENUE 224,085 184,183
COMMITMENTS AND CONTINGENCIES (Note 8)
SHAREHOLDERS' EQUITY
Common Stock, $.01 Par, 160,000,000 Shares
Authorized and Issued 201,600 201,600
Additional Paid In Capital 399,192 403,488
Cumulative Foreign Currency Translation Adjustment (8,075) (15,298)
Retained Earnings 550,147 453,810
Common Stock Held in Treasury, 115,045 shares at
September 30,1995 and 9,173 shares at December 31,1994 (2,569) (181)
Total Shareholders' Equity 1,140,295 1,043,419
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $2,109,971 $1,861,867
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
<TABLE>
Nine Months Ended
September 30,
1995 1994
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income $ 110,731 $105,438
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization 157,875 181,645
Impairment of Unproved Oil and Gas Properties 20,453 17,364
Deferred Income Taxes 15,586 25,846
Other, Net 3,968 (3,241)
Exploration Expenses 31,590 29,647
Dry Hole Expenses 8,586 10,803
Gains on Sales of Reserves and Related Assets (62,546) (52,212)
Other, Net (148) 3,622
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable (9,093) 30,978
Inventories 4,091 (4,335)
Accounts Payable (12,076) (33,196)
Accrued Taxes Payable 5,773 104
Other Liabilities 2,842 4,675
Other, Net (1,848) (4,186)
Amortization of Deferred Revenue (Note 6) (32,418) (32,419)
Changes in Components of Working Capital Associated with
Investing and Financing Activities (14,156) 20,328
NET OPERATING CASH INFLOWS 229,210 300,861
INVESTING CASH FLOWS (Note 6)
Additions to Oil and Gas Properties (345,351) (313,329)
Exploration Expenses (31,590) (29,647)
Dry Hole Expenses (8,586) (10,803)
Proceeds from Sales of Reserves and Related Assets 100,659 82,167
Changes in Components of Working Capital Associated with
Investing Activities 12,338 (20,328)
Other, Net (9,106) (708)
NET INVESTING CASH OUTFLOWS (281,636) (292,648)
FINANCING CASH FLOWS
Long-Term Debt
Affiliate (8,680) 25,000
Other (Note 7) 83,300 (32,000)
Dividends Paid (14,397) (14,387)
Treasury Stock Purchased (13,231) (4,778)
Proceeds from Sales of Treasury Stock 6,262 1,654
Changes in Components of Working Capital Associated with
Financing Activities 1,818 -
NET FINANCING CASH INFLOWS(OUTFLOWS) 55,072 (24,511)
INCREASE(DECREASE) IN CASH AND CASH EQUIVALENTS 2,646 (16,298)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,810 103,129
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 8,456 $ 86,831
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
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, 1994.
Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.
2. Income Tax Provision for the three-month periods and the nine-
month periods ended September 30, 1995 and 1994 includes tax
benefits of $3.1 million, $14.2 million, $15.8 million and $29.4
million, respectively, related to tight gas sand federal income
tax credit utilization. Income Tax Provision for the three-month
and nine-month periods ended September 30, 1994 also includes a
$4.6 million deferred tax benefit resulting from a reduction in
estimated composite state income tax rates and a $1.5 million
current U.S. tax benefit arising from the discontinuance of
operations in Malaysia. Income tax provision for the three-month
and nine-month periods ended September 30, 1995 also includes a
$10 million and a $12 million benefit, respectively, associated
with the successful resolution on audit of federal income taxes
for certain prior years.
3. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids
Net Operating Revenues
Natural Gas Net Operating Revenues are comprised of the
following (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
1995 1994 1995 1994
Wellhead Natural Gas Revenues
Associated Companies (1)(2) $ 36.4 $ 56.2 $120.2 $218.3
Trade 48.5 35.8 121.9 125.0
Total $ 84.9 $ 92.0 $242.1 $343.3
Other Natural Gas Marketing Activities
Gross Revenues from:
Associated Companies $ 16.8 $ 38.5 $ 60.4 $124.2
Trade (3) 23.5 26.8 74.9 90.8
Total 40.3 65.3 135.3 215.0
Associated Cost from:
Associated Companies (1)(5) 17.4 41.4(4) 64.5(4) 141.6(4)
Trade 13.1 13.7 43.3 48.8
Total 30.5 55.1 107.8 190.4
Net 9.8 10.2 27.5 24.6
Commodity Price Swap Gain(Loss)
Trading - - 11.3(6) -
Non-Trading (7) 20.2 4.1 51.1 (2.3)
Total 20.2 4.1 62.4 (2.3)
Total $ 30.0 $ 14.3 $ 89.9 $ 22.3
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil, Condensate and Natural Gas Liquids, Net Operating
Revenues are comprised of the following (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
1995 1994 1995 1994
Wellhead Crude Oil, Condensate and
Natural Gas Liquid Revenues
Associated Companies $ 13.2 $ 12.9 $ 43.4 $ 30.0
Trade 18.0 7.4 46.0 21.5
Total $ 31.2 $ 20.3 $ 89.4 $ 51.5
Other Crude Oil and Condensate Marketing
Activities
Commodity Price Hedging Gain (7) $ 1.1 $ 0.3 $ 0.9 $ 1.1
(1) Wellhead Natural Gas Revenues include $17.0 million, $27.4
million, $55.0 million and $100.4 million for the three-month
periods and the nine-month periods ended September 30, 1995 and
1994, respectively, associated with deliveries by Enron Oil & Gas
Company to Enron Oil & Gas Marketing, Inc., a wholly-owned
subsidiary, reflected as a cost in Other Natural Gas Marketing
Activities - Associated Costs.
(2) Includes $2.8 million, $5.0 million, $10.0 million and $17.4
million for the three-month periods and the nine-month periods
ended September 30, 1995 and 1994, respectively, associated with
the equivalent wellhead value of volumes delivered under the
terms of a volumetric production payment agreement effective
October 1, 1992, as amended, net of transportation.
(3) Includes $10.9 million for the three-month periods and $32.4
million for the nine-month periods ended September 30, 1995 and
1994 associated with the amortization of deferred revenues under
the terms of volumetric production payment and exchange
agreements effective October 1, 1992, as amended.
(4) Includes the effect of a price swap agreement with a third
party which in effect fixed the price of certain purchases
through February 1995.
(5) Includes $6.3 million, $7.9 million, $19.8 million and $26.2
million for the three-month periods and the nine-month periods
ended September 30, 1995 and 1994, respectively, for volumes
delivered under the terms of volumetric production payment and
exchange agreements effective October 1, 1992, as amended,
including equivalent wellhead value, any applicable
transportation costs and location differentials.
(6) Represents gain associated with commodity price swap
transactions with an Enron Corp. affiliated company designated
for trading purposes. The Company had no open trading positions
at September 30, 1995. Subsequently, the Company sold call
options with a notional volume of 50 billion British thermal
units per day at an average price of $2.10 per million British
thermal units for the period January through December, 1996.
(7)Represents gain or loss associated with commodity price swap
transactions primarily with Enron Corp. affiliated companies
based on NYMEX-related commodity prices in effect on dates of
execution, less customary transaction fees. These
transactions serve as price hedges for a portion of wellhead
sales.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. In March 1995, in a series of transactions with Enron Corp.
and an affiliate of Enron Corp., the Company exchanged all of its
fuel supply and purchase contracts and related price swap
agreements associated with a Texas City cogeneration plant (the
"Cogen Contracts") for certain natural gas price swap agreements
of equivalent value issued by the affiliate that are designated
as hedges (the "Swap Agreements"). Such Swap Agreements were
closed on March 31, 1995. As a result of the transactions, the
Company has been relieved of all performance obligations
associated with the Cogen Contracts. Such operating revenues and
associated cost through February 28, 1995 were classified as
Other Natural Gas Marketing Activities-Gross Revenues and
Associated Cost from Associated Companies. The Company will
realize net operating revenues classified as Other Natural Gas
Marketing Activities-Commodity Price Swap Gain, Non-Trading, and
receive corresponding cash payments of approximately $91 million
during the period extending through December 31, 1999 under the
terms of the closed Swap Agreements. The estimated fair value of
the Swap Agreements was approximately $81 million at the date the
Swap Agreements were received in exchange for the Cogen
Contracts. The net effect of this series of transactions will
result in increases in net operating revenues and cash receipts
for the Company during 1995 and 1996 of approximately $13 million
and $7 million, respectively, with offsetting decreases in 1998
and 1999 versus those anticipated under the Cogen Contracts. The
total cash payments receivable under the terms of the Swap
Agreements, approximately $72 million at September 30, 1995, are
presented in the accompanying balance sheet as Accounts
Receivable - Associated Companies for the $30 million current
portion and as Other Assets for the $42 million noncurrent
portion. The corresponding total future revenue is classified as
Deferred Revenue.
5. In March 1995, a subsidiary of the Company issued to an
unrelated third party 19,000 shares of the subsidiary's non-
voting redeemable preferred stock, with a liquidation/redemption
value of $1,000 per share and dividends payable semi-annually at
an annual rate of $70.00 per share, in exchange for certain oil
and gas properties. Such dividends have been classified as
interest expense - other in the accompanying statement of income.
The mandatory redemption date of the preferred stock is March 31,
2005; however, both parties have an option to require the stock
to be exchanged at any time on or subsequent to March 31, 1997
for 633,333 shares of Enron Corp. common stock. In the event of
a tax deconsolidation between Enron Corp. and the Company, the
third party has the option to require the exchange of the
redeemable preferred stock for 950,000 shares of the common stock
of the Company rather than for the Enron Corp. common stock. As
of September 30, 1995, the Company has acquired 633,333 shares of
Enron Corp. common stock at a cost of approximately $19.3 million
to be held in anticipation of the possible future exchange. The
cost of the Enron Corp. common stock is included in Other Assets
in the accompanying balance sheet.
6. Gains on sales of certain oil and gas reserves and related
assets in the amount of $62.5 million and $52.2 million for the
nine-month periods ended September 30, 1995 and 1994,
respectively, are required by current accounting guidelines to be
removed from Net Income in connection with determining Net
Operating Cash Inflows while the related proceeds are classified
as Investing Cash Flows. The Company believes the proceeds from
the sales of reserves and related assets should be considered in
analyzing the elements of operating cash flows. The current
federal income tax impact of these sales transactions was
calculated by the Company to be $24.3 million and $18.7 million
for the nine-month periods ended September 30, 1995 and 1994,
respectively, which entered into the overall calculation of
current federal income tax. The Company believes that this
current federal income tax impact should also be considered in
analyzing the elements of the cash flow statement.
The consolidated statement of cash flows for the first nine
months of 1994 has been revised to reflect the elimination of the
non-cash amortization of deferred revenue from net operating cash
flows rather than investing cash flows as previously reported.
This revision was made following discussion with the Staff of the
Securities and Exchange Commission.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Concluded)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Non-cash investing and financing activities for the nine-
month period ended September 30, 1995 include the issuance by a
subsidiary of the Company of redeemable preferred stock with a
liquidation/redemption value of $19 million in exchange for
certain oil and gas properties (see Note 5). An approximate $7
million step-up in property basis was made relating to deferred
taxes associated with the difference between the tax and book
bases of the acquired properties as required by Statement of
Financial Accounting Standards (SFAS) No. 109 - "Accounting for
Income Taxes" for a nontaxable business combination.
7. Long-Term Debt, Other at September 30, 1995 and December 31,
1994 consisted of the following:
September 30, December 31,
1995 1994
Senior Notes $ 70,000 $ 70,000
Promissory Notes 71,000 56,000
Commercial Paper 50,000 6,700
Uncommitted Bank Lines of Credit 50,000 -
Loan Payable - 25,000
Capitalized Lease Obligation 6,552 7,637
$247,552 $165,337
The commercial paper and uncommitted bank lines of credit
with two banks are used to fund current transactions and are
classified as long-term based on the Company's intent and ability
to replace such obligations with other long-term debt. The
interest rates for commercial paper and the uncommitted bank
lines of credit at September 30, 1995 were 5.88% and 6.85%,
respectively.
8. On November 19, 1992, TransAmerican Natural Gas Corporation
("TransAmerican") filed a petition against the Company alleging
breach of contract, tortious interference with contract,
misappropriation of trade secrets and violation of state
antitrust laws. The petition, as amended, sought actual damages
of at least $100 million plus exemplary damages of $300 million.
The Company filed counterclaims against TransAmerican and a third-
party claim against its sole shareholder, John R. Stanley,
alleging fraud, negligent misrepresentation and breach of state
antitrust laws. On October 16, 1995, the Company, TransAmerican
and Stanley entered into an agreement which resolved all claims.
The settlement terms will not have a materially adverse effect on
the Company's financial condition or results of operations.
9. In March 1995, the Financial Accounting Standards Board
issued SFAS No. 121 - "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" (the
"Standard"). The Standard requires, among other things, that
long-lived assets and certain identifiable intangibles to be held
and used by an entity be reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. The Company is required to
adopt the Standard no later than the first quarter of 1996.
While the Company has not finalized its evaluation of the effect
of adoption of the Standard, its evaluation to date indicates
that application of the Standard to its current portfolio of
assets could result in impairment charges ranging from $5 million
to $60 million before federal income taxes ($3 million to $39 million
after federal income taxes). However, such impairment charges would be
non-cash.
<PAGE>
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 the
nine-month periods ended September 30, 1995 and 1994 should be
read in conjunction with the consolidated financial statements of
the Company and Notes thereto.
Results of Operations
Three Months Ended September 30, 1995
vs. Three Months Ended September 30, 1994
In the third quarter of 1995, Enron Oil & Gas Company (the
"Company") realized net income of $33.0 million compared to net
income of $41.0 million for the same period in 1994. Net
operating revenues for the third quarter of 1995 were $153.0
million as compared to $160.7 million for the same period a year
ago.
Wellhead volume and price statistics are as follows:
1995 1994
Natural Gas Volumes (MMcf/d)(1)
North America (2) 657 606
Trinidad 112 66
Total 769 672
Average Natural Gas Prices ($/Mcf)(3)
North America (4) $ 1.24 $ 1.55
Trinidad 0.97 0.93
Composite 1.20 1.49
Crude/Condensate Volumes (MBbl/d)(1)
North America 12.0 10.1
Trinidad 5.9 2.7
India 2.3 -
Total 20.2 12.8
Average Crude/Condensate Prices ($/Bbl)(3)
North America $16.57 $16.81
Trinidad 15.76 16.28
India 16.10 -
Composite 16.28 16.70
(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, 1995 and 1994 delivered under the
terms of volumetric production payment and exchange
agreements 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
$.62/Mcf and $1.13/Mcf for the three-month periods
ended September 30, 1995 and 1994, respectively, for the
volumes described in note (2), net of transportation
costs.
Third quarter 1995 average wellhead natural gas prices were
down approximately 19% from the same period in 1994 reducing net
operating revenues by approximately $20 million. An increase of
14% in wellhead natural gas volumes from the third quarter of
1994 increased net operating revenues by approximately $13
million. The Company voluntarily curtailed its United States
wellhead natural gas delivered volumes by an average of
approximately 150 MMcf/d during the third quarter of 1995
compared to an average of approximately 140 MMcf/d during the
same period in 1994 due to significantly lower United States
wellhead natural gas prices. The third quarter 1995 North
America increase in natural gas volumes was primarily the result
of acquisitions made during 1995. Offshore Trinidad natural gas
volumes also continued to increase when compared to 1994 as a
result of increased annual takes under the existing contract.
Third quarter 1995 wellhead crude oil and condensate average prices
decreased 3% reducing net operating revenues approximately $1
million from the third quarter of 1994. Crude oil and condensate
wellhead volumes increased 58% adding approximately $11 million
to net operating revenues compared to the same period a year ago
primarily reflecting new volumes on stream offshore India, higher
volumes offshore Trinidad due to increased annual takes under the
existing contract and new well additions related to the 1995
drilling program and a 19% increase in North America volumes.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Continued)
ENRON OIL & GAS COMPANY
Other marketing activities associated with sales and
purchases of natural gas, natural gas price swap transactions,
other commodity price hedging of natural gas and crude oil and
condensate prices utilizing NYMEX-related commodity market
transactions, and margins relating to the volumetric production
payment added approximately $31 million to net operating revenues
during the third quarter of 1995, an increase of approximately
$17 million over the same period in 1994. This increase
primarily results from a gain of $20 million on natural gas
commodity price hedging activities utilizing NYMEX-related
commodity market transactions in the third quarter of 1995
compared to a gain of $4 million in the third quarter of 1994.
The average associated costs of natural gas marketing, price swap
and volumetric production payment transactions, including, where
appropriate, average wellhead value, transportation costs and
exchange differentials, decreased $.67 per Mcf. The average
price received for these transactions decreased $.61 per Mcf.
Related other natural gas marketing volumes decreased 16%. The
reduction in other natural gas marketing volumes and prices
relates primarily to the exchange of the fuel contracts discussed
below and lower wellhead market prices. The reduction in other
natural gas marketing volumes partially offset by the $.06 per
Mcf increased margin reduced net operating revenues by
approximately $.4 million compared to the third quarter of 1994.
The impact of these other marketing activities, a
substantial portion of which serve as hedges of commodity price
risks for a portion of wellhead deliveries, were more than offset
by reductions in revenues associated with market responsive
prices for wellhead deliveries. (See Note 3 to Consolidated
Financial Statements).
In March 1995, the Company exchanged existing fuel supply
and purchase contracts and related price swap agreements
associated with a Texas City cogeneration plant for certain
natural gas price swap agreements of equivalent value issued by
an Enron Corp. affiliated company. As a result of these
transactions, the Company realized a $4 million increase in net
operating revenues in the third quarter of 1995 over the amount
realized from the exchanged fuel supply and purchase contracts in
the same period of 1994. (See also Note 4 to the Consolidated
Financial Statements).
Gains on sales of reserves and related assets during the
third quarter of 1995 decreased $30 million when compared to the
same period in 1994 due to one major sale being made during the
1994 period and no such sales being made during the 1995 period.
During the third quarter of 1995, operating expenses were
approximately $6 million higher than in the third quarter of
1994. Lease and well expenses increased approximately $6 million
primarily due to increased volumes and expanded international
activities. Depreciation, depletion and amortization ("DD&A")
expense increased approximately $2 million to $56 million
reflecting an increase in production volumes partially offset by
a decrease in the average DD&A rate from $.79 per thousand cubic
feet equivalent ("Mcfe") in the third quarter of 1994 to $.68 per
Mcfe in the third quarter of 1995. The decrease in the DD&A rate
is due to an increase in the mix of North America volumes coming
from lower cost fields, the disposition of higher cost properties
and increases in international volumes at lower than average
domestic DD&A rates.
The Company's per unit operating costs for lease and well
expense, DD&A, general and administrative expense, interest
expense, and taxes other than income averaged $1.23 per Mcfe
during the third quarter of 1995 compared to $1.32 per Mcfe
during the same period in 1994.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Continued)
ENRON OIL & GAS COMPANY
Income tax provision decreased $9 million for the third
quarter of 1995 as compared to the same period in 1994 primarily
resulting from lower income before income taxes, lower benefits
associated with tight gas sand federal income tax credits and a
$10 million benefit associated with the successful resolution on
audit of federal income taxes for certain prior years.
Federal income taxes accrued in interim periods are calculated
using the estimated annual effective income tax rate method.
Nine Months Ended September 30, 1995
vs. Nine Months Ended September 30, 1994
In the first nine months of 1995, the Company realized net
income of $110.7 million compared to net income of $105.4 million
for the same period in 1994. Net operating revenues for the
first nine months of 1995 were $492.3 million as compared to
$474.3 million for the same period a year ago.
Wellhead volume and price statistics are as follows:
1995 1994
Natural Gas Volumes (MMcf/d)
North America (1) 609 680
Trinidad 110 63
Total 719 743
Average Natural Gas Prices ($/Mcf)
North America (2) $ 1.28 $ 1.76
Trinidad 0.97 0.93
Composite 1.23 1.69
Crude/Condensate Volumes (MBbl/d)
North America 11.5 9.4
Trinidad 4.8 2.6
India 2.3 -
Total 18.6 12.0
Average Crude/Condensate Prices ($/Bbl)
North America $17.01 $15.25
Trinidad 16.16 15.20
India 16.82 -
Composite 16.77 15.24
(1) Includes 48 MMcf per day for the nine-month periods
ended September 30, 1995 and 1994 delivered under the
terms of volumetric production payment and exchange
agreements effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of
$.76/Mcf and $1.32/Mcf for the nine-month periods
ended September 30, 1995 and 1994, respectively, for the
volumes described in note (1), net of transportation
costs.
Average wellhead natural gas prices for the first nine
months of 1995 were down approximately 27% from the same period
in 1994 reducing net operating revenues by approximately $90
million. A decrease of 3% in wellhead natural gas volumes from
the first nine months of 1994 reduced net operating revenues by
approximately $11 million. The Company voluntarily curtailed its
United States wellhead natural gas delivered volumes by an
average of approximately 140 MMcf/d during the first nine months
of 1995 compared to approximately 110 MMcf/d during the same
period in 1994 due to significantly lower United States wellhead
natural gas prices. In addition, the impact of sales of oil and
gas reserves and related assets net of purchases of similar
assets resulted in a reduction of approximately 40 MMcf per day
in delivered volumes for the first nine months of 1995 as
compared to the first nine months of 1994. The Company's
decision early in the year to curtail drilling activities
primarily related to increasing United States natural gas
deliverability in favor of drilling for reserve additions and the
definition of future opportunities reduced the rate of growth in
producing capacity. Wellhead crude oil and condensate average
prices increased 10% adding approximately $8 million to net
operating revenues over the first nine months of 1994. Crude oil
and condensate wellhead volumes increased 55% adding
approximately $27 million to net operating revenues compared to
the same period a year ago primarily reflecting new volumes on
stream offshore India, higher volumes offshore Trinidad and a 22%
increase in North America volumes.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Continued)
ENRON OIL & GAS COMPANY
Other marketing activities associated with sales and
purchases of natural gas, natural gas price swap transactions,
other commodity price hedging of natural gas and crude oil and
condensate prices utilizing NYMEX-related commodity market
transactions, and margins relating to the volumetric production
payment added approximately $91 million to net operating revenues
during the first nine months of 1995, an increase of
approximately $67 million from the same period in 1994. This
increase primarily results from a gain of $51 million on natural
gas commodity price hedging activities utilizing NYMEX-related
commodity market transactions in the first nine months of 1995
versus a $2 million loss during 1994 and increased margins
associated with other natural gas marketing activities. The
average associated costs of natural gas marketing, price swap and
volumetric production payment transactions, including, where
appropriate, average wellhead value, transportation costs and
exchange differentials, decreased $.64 per Mcf. The average
price received for these transactions decreased $.54 per Mcf.
Related other natural gas marketing volumes decreased 19%. The
reduction in other natural gas marketing volumes and prices
relates primarily to the exchange of the fuel contracts noted
below, lower wellhead market prices and decreased other marketing
activities. The $.10 per Mcf margin increase partially offset by
the reduction in other natural gas marketing volumes increased
net operating revenues by approximately $3 million compared to
the first nine months of 1994. The Company realized an $11
million gain in the first nine months of 1995 related to certain
NYMEX-related commodity market transactions with an Enron Corp.
affiliated company that were designated for trading purposes in
late 1994. The Company had no open trading positions at
September 30, 1995. Subsequently, the Company sold call options
with a notional volume of 50 billion British thermal units per
day ("BBtu/d") at an average price of $2.10 per million British
thermal units ("MMBtu") for the period January through December,
1996.
The impact of these other marketing activities, a
substantial portion of which serve as hedges of commodity price
risks for a portion of wellhead deliveries, were more than offset
by reductions in revenues associated with market responsive
prices for wellhead deliveries. (See Note 3 to Consolidated
Financial Statements).
The Company realized an $8.4 million increase in net
operating revenues in the first nine months of 1995 over the
amount realized in the same period of 1994 from the exchanged
fuel supply and purchase contracts previously mentioned.
Gains on sales of reserves and related assets during the
first nine months of 1995 increased $10 million when compared to
the same period in 1994 which increase was attributable to the
Company's continuing efforts in optimizing the use of its assets.
During the first nine months of 1995, operating expenses of
$338 million were $6 million lower than the $344 million incurred
in the same period in 1994. Lease and well expenses increased
approximately $8 million to $53 million primarily due to expanded
international operations partially offset by reductions in United
States lease and well expenses. Exploration expenses increased
$2 million to $32 million due to increased exploration
activities. Impairment of unproved oil and gas properties for
the first nine months of 1995 increased $3 million from the
comparable period a year ago primarily due to impairments
associated with certain offshore Gulf of Mexico leases. DD&A
expense decreased $24 million to $158 million reflecting primarily
a decrease in the average DD&A rate from $.81 per Mcfe in the
first nine months of 1994 to $.69 per Mcfe in the first nine months
of 1995. The DD&A rate decrease is primarily attributable to
increased production from international operations with lower average DD&A
rates than incurred for North America operations. General and
administrative expenses increased approximately $3 million to $41
million due to expanded international activities and overall
higher costs associated with certain employee related expenses.
Taxes other than income were $4 million higher in the first nine
months of 1995 compared to the same period in 1994 primarily due
to a benefit included in 1994 associated with reductions in state
franchise taxes and higher production related taxes associated
with new production offshore India in the first nine months of 1995
partially offset by decreases in state severance taxes due to
lower taxable North America wellhead volumes and average prices
in 1995.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Continued)
ENRON OIL & GAS COMPANY
The Company reduced its total per unit operating costs for
lease and well expense, DD&A, general and administrative expense,
interest expense, and taxes other than income by $.06 per Mcfe,
averaging $1.25 per Mcfe during the first nine months of 1995
compared to $1.31 per Mcfe during the same period in 1994. This
decrease is primarily attributable to the reduction in the
average DD&A rate as noted above partially offset by increases in
per unit lease and well, general and administrative expenses, and
taxes other than income.
Income tax provision increased $13 million for first nine
months of 1995 as compared to the same period in 1994 primarily
resulting from higher income before income taxes and lower
benefits associated with tight gas sand federal income tax
credits utilized in the first nine months of 1995 as compared to
the same period in 1994 partially offset by a $12 million benefit
associated with the successful resolution on audit of federal
income taxes for certain prior years.
Capital Resources and Liquidity
The Company's primary sources of cash during the nine months
ended September 30, 1995 included funds generated from
operations, proceeds from the sales of selected oil and gas
reserves and related assets and commercial paper and uncommitted
bank lines. Primary cash outflows included funds used in
operations, exploration and development expenditures, dividends
and repayment of debt.
With the objective of enhancing the certainty of future
revenue expectations, the Company has, as of October 23, 1995,
entered into hedging related transactions for approximately 400
BBtu/d (approximately 381 MMcf/d) and 529 BBtu/d (approximately
504 MMcf/d) of its North America natural gas volumes for the last
three months of 1995 and the year 1996, respectively. A
significant portion of the 1995 and substantially all of the 1996
hedge related transactions involve NYMEX-based commodity price
swap agreements totaling 260 BBtu/d at an average price of $1.98
per MMBtu and 447 BBtu/d at an average price of $2.00 per MMBtu
for the last three months of 1995 and the year 1996,
respectively. The remaining hedged transactions of 140 BBtu/d
and 82 BBtu/d for the last three months of 1995 and the year
1996, respectively, include notional and physical transactions
that involve fixed price sales contracts and volumetric
production payment and exchange agreements. Included in the 1996
hedge transactions are commodity price swap agreements totaling
200 BBtu/d of notional volumes at a weighted average NYMEX-based
price of $1.97 per MMBtu which include one-time options
exercisable by the counterparty on or before December 17, 1996
totaling 200 BBtu/d of notional volumes in 1997 and 1998 at the
same weighted average NYMEX-based price of $1.97 per MMBtu. The
Company has also, as of October 16, 1995, hedged approximately
10,100 Bbl per day and 9,600 Bbl per day of its North America
crude oil and condensate volumes using commodity price swap
agreements at NYMEX-based West Texas Intermediate Crude Oil
("WTI") prices averaging $18.77 per Bbl and $18.90 per Bbl for
the last three months of 1995 and the year 1996, respectively.
Included in the 1995 and 1996 hedge transactions are commodity
price swap agreements totaling up to 3,000 Bbl per day at WTI
prices ranging between $18.70 and $18.80 per Bbl each of which
includes a one-time option exercisable by the counterparty at
various times up to and including December 31, 1996 and for
various periods some of which extend through December 31, 2000 at
the same respective NYMEX-based prices as are applicable in the
individual agreements for the 1995 and 1996 periods. The Company
continues to evaluate the potential for entering into and may
enter into, additional hedging transactions related to certain of
the remaining months in 1995, and in future years. In addition,
the Company may close out any portion of the existing or yet to
be entered into hedges as determined appropriate by management of
the Company.
<PAGE>
PART I. FINANCIAL INFORMATION - (Concluded)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Concluded)
ENRON OIL & GAS COMPANY
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 depreciation,
depletion and amortization, 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 and to include proceeds from sales of reserves
and related assets. The Company generated discretionary cash
flow of $387 million during the first nine months of 1995, a 3%
decrease from the $401 million generated for the same period in
1994, primarily reflecting lower net operating revenues, higher
cash expenses and a decrease in benefits associated with tight
gas sand federal income tax credits.
Net operating cash flows of $229 million for the first nine
months of 1995 decreased approximately $72 million as compared to
the same period in 1994 primarily reflecting the same factors
addressed above with regard to discretionary cash flow and higher
working capital requirements. Based upon existing economic and
market conditions, management believes net operating cash flow
and available financing alternatives in 1995 will be sufficient
to fund net investing and other cash requirements of the Company
for the remainder of the year.
Exploration and development expenditures for the first nine
months of 1995 and 1994 are as follows ($ Millions):
1995 1994
North America $ 343 $ 291
International
Trinidad 32 52
India 14 2
Other 16 9
Total $ 405 $ 354
Higher exploration and development expenditures for the
first nine months of 1995 reflect primarily the acquisitions of
certain properties in the United States. Property acquisitions
during the first nine months of 1995 were approximately $114
million as compared to $14 million for the first nine months of
1994. Property acquisitions were completed at an estimated cost
per Mcfe of $.53 during 1995 while sales of reserves and related
assets were completed at $2.45 per Mcfe sold based on the
Company's estimate of reserves.
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>
PART II. OTHER INFORMATION
ENRON OIL & GAS COMPANY
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits - None
(b) Reports on Form 8-K - There were no reports on Form 8-K
filed for the quarterly period ended September 30, 1995.
<PAGE>
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 8, 1995 By /S/ W. C. WILSON
W. C. Wilson
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: November 8, 1995 By /S/ BEN B. BOYD
Ben B. Boyd
Vice President and Controller
(Principal Accounting Officer)
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<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1995
<CASH> 8,456
<SECURITIES> 0
<RECEIVABLES> 162,822
<ALLOWANCES> 0
<INVENTORY> 11,640
<CURRENT-ASSETS> 191,546
<PP&E> 3,266,736
<DEPRECIATION> (1,423,586)
<TOTAL-ASSETS> 2,109,971
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<COMMON> 201,600
0
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<OTHER-SE> 938,695
<TOTAL-LIABILITY-AND-EQUITY> 2,109,971
<SALES> 422,357
<TOTAL-REVENUES> 492,342
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<TOTAL-COSTS> 338,214
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