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, 1997
[ ] 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, 1997.
Common Stock, $.01 Par Value 157,003,955 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 June 30, 1997 and 1996
and Six Months Ended June 30, 1997 and 1996 3
Consolidated Balance Sheets - June 30, 1997 and
December 31, 1996 4
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 1997 and 1996 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 15
ITEM 6. Exhibits and Reports on Form 8-K 15
<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 Six Months Ended
June 30, June 30,
1997 1996 1997 1996
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Associated Companies $ 21,247 $ 54,507 $ 18,648 $ 82,639
Trade 111,689 89,556 252,860 180,051
Crude Oil, Condensate and Natural Gas Liquids
Associated Companies 9,900 8,627 19,581 21,253
Trade 20,499 25,459 51,710 49,683
Gains on Sales of Reserves and
Related Assets 7,286 17,661 7,492 19,521
Other 1,132 1,303 2,113 2,992
Total 171,753 197,113 352,404 356,139
OPERATING EXPENSES
Lease and Well 25,973 19,974 49,442 38,730
Exploration 15,019 11,489 30,502 23,407
Dry Hole 1,586 2,579 2,570 5,090
Impairment of Unproved Oil and Gas Properties 6,900 4,980 12,913 9,843
Depreciation, Depletion and Amortization 69,183 58,965 131,822 122,286
General and Administrative 12,114 14,298 25,721 28,487
Taxes Other Than Income 12,359 11,185 29,645 22,656
Total 143,134 123,470 282,615 250,499
OPERATING INCOME 28,619 73,643 69,789 105,640
OTHER INCOME (EXPENSE), NET 956 (8) 2,212 (523)
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 29,575 73,635 72,001 105,117
INTEREST EXPENSE, NET 5,464 3,303 10,579 7,447
INCOME BEFORE INCOME TAXES 24,111 70,332 61,422 97,670
INCOME TAX PROVISION (BENEFIT) (460) 22,750 13,786 24,165
NET INCOME $ 24,571 $ 47,582 $ 47,636 $ 73,505
EARNINGS PER SHARE OF COMMON STOCK $ .16 $ .30 $ .30 $ .46
AVERAGE NUMBER OF COMMON SHARES 157,489 159,910 158,177 159,922
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In Thousands)
<TABLE>
June 30, December 31,
1997 1996
(Unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 16,531 $ 7,644
Accounts Receivable
Associated Companies 44,141 82,059
Trade 162,911 195,239
Inventories 29,473 20,746
Other 16,951 20,222
Total 270,007 325,910
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 4,016,705 3,753,199
Less: Accumulated Depreciation, Depletion and Amortization (1,779,499) (1,653,610)
Net Oil and Gas Properties 2,237,206 2,099,589
OTHER ASSETS 28,659 32,854
Total Assets $ 2,535,872 $ 2,458,353
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Associated Companies $ 26,561 $ 77,522
Trade 165,639 200,069
Accrued Taxes Payable 9,730 18,554
Dividends Payable 4,765 4,818
Other 12,271 16,397
Total 218,966 317,360
LONG-TERM DEBT 633,604 466,089
OTHER LIABILITIES 38,434 44,483
DEFERRED INCOME TAXES 315,116 308,948
DEFERRED REVENUE 74,753 56,383
SHAREHOLDERS' EQUITY
Preferred Stock, $.01 Par,10,000,000 Shares Authorized and
No Shares Issued and Outstanding - -
Common Stock, $.01 Par, 320,000,000 Shares Authorized and
160,000,000 Shares Issued 201,600 201,600
Additional Paid In Capital 388,153 388,212
Unearned Compensation (5,211) (5,727)
Cumulative Foreign Currency Translation Adjustment (11,665) (10,179)
Retained Earnings 735,734 697,564
Common Stock Held in Treasury, 2,572,583 shares at
June 30, 1997 and 242,882 shares at December 31, 1996 (53,612) (6,380)
Total Shareholders' Equity 1,254,999 1,265,090
Total Liabilities And Shareholders' Equity $ 2,535,872 $ 2,458,353
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
<TABLE>
Six Months Ended
June 30,
1997 1996
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income $ 47,636 $ 73,505
Items Not Requiring Cash
Depreciation, Depletion and Amortization 131,822 122,286
Impairment of Unproved Oil and Gas Properties 12,913 9,843
Deferred Income Taxes 6,372 4,814
Other, Net 983 761
Exploration Expenses 30,502 23,407
Dry Hole Expenses 2,570 5,090
Gains on Sales of Reserves and Related Assets (7,492) (19,521)
Other, Net (4,141) (2,693)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable 73,389 (16,165)
Inventories (8,727) (4,063)
Accounts Payable (42,861) 15,534
Accrued Taxes Payable (8,824) (3,537)
Other Liabilities 1,350 3,809
Other, Net (611) (3,016)
Amortization of Deferred Revenue (21,494) (21,613)
Changes in Components of Working Capital Associated with
Investing and Financing Activities 29,456 (4,093)
NET OPERATING CASH INFLOWS 242,843 184,348
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (297,069) (177,425)
Exploration Expenses (30,502) (23,407)
Dry Hole Expenses (2,570) (5,090)
Proceeds from Sales of Reserves and Related Assets 15,822 60,688
Changes in Components of Working Capital Associated with
Investing Activities (30,187) 4,093
Other, Net (1,971) (5,245)
NET INVESTING CASH OUTFLOWS (346,477) (146,386)
FINANCING CASH FLOWS
Long-Term Debt
Affiliate - (113,520)
Other 168,600 114,000
Dividends Paid (9,519) (9,585)
Treasury Stock Purchased (49,194) (24,486)
Proceeds from Sales of Treasury Stock 1,546 10,652
Other, Net 1,088 -
NET FINANCING CASH INFLOWS (OUTFLOWS) 112,521 (22,939)
INCREASE IN CASH AND CASH EQUIVALENTS 8,887 15,023
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 7,644 23,039
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 16,531 $ 38,062
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
<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, 1996.
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 12 to the consolidated financial
statements included in the Company's 1996 Annual Report on Form 10-K,
the Company engages in price risk management activities primarily for
non-trading and to a lesser extent for trading purposes. Derivatives 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, 1997 and 1996 includes tax benefits of $2.0 million,
$4.9 million, $5.2 million and $6.2 million, respectively, related to tight
gas sand federal income tax credit utilization. Income tax provision
(benefit) for the six-month period 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. Income tax
provision (benefit) for the six-month period ended June 30, 1996 includes a
reduction of $8.5 million primarily associated with a reassessment of
deferred tax requirements and the successful resolution on audit of
Canadian income taxes for certain prior years.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Natural Gas Net Operating Revenues are comprised of the following (in
millions):
Three Months Ended Six Months Ended
June 30, June 30,
1997 1996 1997 1996
Wellhead Natural Gas Revenues
Associated Companies (1)(2) $ 42.5 $ 49.1 $ 95.9 $106.0
Trade 96.4 73.0 225.3 141.6
Total $138.9 $122.1 $321.2 $247.6
Other Natural Gas Marketing Activities
Gross Revenues from:
Associated Companies $ 19.1 $ 17.2 $ 49.0 $ 36.1
Trade (3) 31.5 33.1 67.4 72.6
Total 50.6 50.3 116.4 108.7
Associated Costs from:
Associated Companies (1)(4) 36.6 25.6 85.3 58.6
Trade 16.3 16.6 39.4 34.2
Total 52.9 42.2 124.7 92.8
Net (2.3) 8.1 (8.3) 15.9
Commodity Price Transaction Revenue
(Reductions)
Trading 2.5 - .5 (1.2)
Non-Trading (5) (6.2) 13.8 (41.9) .4
Total (3.7) 13.8 (41.4) (.8)
Total $ (6.0) $ 21.9 $(49.7) $ 15.1
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues
are comprised of the following (in millions):
Three Months Ended Six Months Ended
June 30, June 30,
1997 1996 1997 1996
Wellhead Crude Oil, Condensate
and
Natural Gas Liquids Revenues
Associated Companies $ 10.7 $ 11.5 $ 23.0 $ 25.1
Trade 20.5 25.5 51.7 49.7
Total $ 31.2 $ 37.0 $ 74.7 $ 74.8
Other Crude Oil and Condensate
Marketing Activities
Commodity Price Hedging
Revenue Reductions(5) $ (.8) $ (2.9) $ (3.4) $ (3.9)
1) Wellhead Natural Gas Revenues include $25.1 million, $24.7 million,
$62.1 million and $57.5 million for the three-month and six-month periods
ended June 30, 1997 and 1996, 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 $5.4 million, $3.4 million, $16.2 million and $7.3 million
for the three-month and six-month periods ended June 30, 1997 and 1996,
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.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Concluded)
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3) Includes $10.8 million, $10.8 million, $21.5 million and $21.6 million
for the three-month and six-month periods ended June 30, 1997 and 1996,
respectively, associated with the amortization of deferred revenues under
the terms of a volumetric production payment agreement effective October 1,
1992, as amended.
4) Includes $9.0 million, $7.8 million, $21.7 million and $16.1 million
for the three-month and six-month periods ended June 30, 1997 and 1996,
respectively, for volumes delivered under the terms of a volumetric
production payment agreement effective October 1, 1992, as amended,
including equivalent wellhead value, any applicable transportation costs
and exchange differentials.
5) Represents revenue increases or reductions 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 were originally
entered into as price hedges for a portion of wellhead sales.
4. As reported in the Company's Annual Report on Form 10-K for the year
ended December 31, 1996, 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.
5. In February 1997, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 128 -
"Earnings per Share" effective for interim and annual periods after
December 15, 1997. This statement replaces primary earnings per share
("EPS") with a newly defined basic EPS and modifies the computation of
diluted EPS. The Company does not anticipate that implementation of SFAS
128 will have a material impact on its computation of EPS.
6. In February 1997, the FASB issued SFAS No. 129 - "Disclosures of
Information about Capital Structures" which is applicable to all entities
that issue securities other than ordinary common stock and is effective for
all periods ending after December 15, 1997. There are no additional
disclosures required of the Company at this time relating to the issuance
of SFAS No. 129.
7. In June 1997, the Company canceled an existing revolving credit
agreement and replaced it with two new revolving credit agreements entered
into with a group of banks (the "Credit Agreements"). The Credit
Agreements provide for current aggregate borrowings of up to $400 million,
with provisions for increases up to $800 million at the option of the
Company and subject to lender approval. The Credit Agreements consist of a
$100 million, 364-day credit agreement which matures on June 25, 1998 and
is renewable annually by mutual consent, and a $300 million five-year
agreement that matures on June 27, 2002. Advances under the agreements
bear interest, at the option of the Company, based on a base rate or a
Eurodollar rate. There were no advances outstanding under the agreements
at June 30, 1997.
<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 six-month
periods ended June 30, 1997 and 1996 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, 1997
vs. Three Months Ended June 30, 1996
In the second quarter of 1997, the Company generated net income of $25
million compared to net income of $48 million for the second quarter of
1996. Net operating revenues for the second quarter of 1997 were $172
million as compared to $197 million for the second quarter of 1996.
Wellhead volume and price statistics are as follows:
1997 1996
Natural Gas Volumes (MMcf/d)(1)
United States (2) 689 597
Canada 92 103
North America 781 700
Trinidad 114 140
India 1 -
Total 896 840
Average Natural Gas Prices ($/Mcf)(3)
United States (4) $ 1.87 $ 1.83
Canada 1.25 1.07
North America Composite 1.80 1.72
Trinidad 1.04 1.00
India 2.97 -
Total Composite 1.70 1.60
Crude Oil/Condensate Volumes (MBbl/d)(1)
United States 11.2 8.7
Canada 2.4 2.3
North America 13.6 11.0
Trinidad 3.5 5.4
India - 2.7
Total 17.1 19.1
Average Crude Oil/Condensate Prices ($/Bbl)(3)
United States $19.42 $21.18
Canada 16.49 18.54
North America Composite 18.89 20.62
Trinidad 16.09 19.61
India - 20.56
Total Composite 18.31 20.33
(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, 1997 and 1996 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
$1.24/Mcf and $.76/Mcf for the three-month periods
ended June 30, 1997 and 1996, respectively, for the
volumes described in note (2), net of transportation
costs.
Wellhead revenues increased 7% to $170 million in the second quarter of
1997 compared to $159 million in the second quarter of 1996. This increase
reflects increased North America volumes and increased average wellhead
prices for natural gas which is partially offset by lower volumes in
Trinidad and India and lower overall crude oil and condensate average
wellhead prices.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENRON OIL & GAS COMPANY
Second quarter 1997 wellhead natural gas volumes were up approximately
7% from the comparable period in 1996 increasing net operating revenues by
approximately $8 million. This is primarily attributable to a 12% increase
in North America wellhead natural gas volumes in the second quarter 1997
compared to the second quarter a year ago. The increases in North America
wellhead natural gas volumes in the second quarter of 1997 were partially
offset by a reduction in Trinidad wellhead natural gas volumes. The higher
Trinidad natural gas volumes in the second quarter of 1996 reflected higher
purchaser nominations to meet market requirements which exceeded base
contract levels. Wellhead natural gas prices in the second quarter of 1997
were 6% higher than the comparable period a year ago adding approximately
$9 million to net operating revenues. A 10% decrease in both wellhead
crude oil and condensate volumes and average prices in the second quarter
of 1997 as compared to second quarter of 1996 decreased net operating
revenues by approximately $7 million. A 24% increase in North America
wellhead crude oil and condensate volumes was more than offset by lower
condensate volumes from the Kiskadee field offshore Trinidad associated
with lower natural gas deliveries, a decline in crude oil production from
the Ibis field offshore Trinidad and no crude oil deliveries from the Panna
and Mukta fields offshore India as a result of a planned shut-down to allow
for equipment change out 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
reduced net operating revenue by $7 million during the second quarter of
1997, compared to a $19 million increase in the second quarter of 1996. A
$6 million revenue reduction related to natural gas commodity price hedging
activities utilizing NYMEX-related commodity market transactions in the
second quarter of 1997 compares to a $14 million increase associated with
similar transactions a year ago. A decrease in margins associated with
sales and purchases of natural gas and the volumetric production payment
reduced net operating revenues by approximately $2 million as compared to
an $8 million addition in the second quarter of 1996, primarily resulting
from the higher costs of natural gas delivered in 1997. Deferred revenue
reductions of approximately $15 million related to the early closing of
1997 natural gas price hedging transactions will be recognized during the
remainder of 1997.
During the second quarter of 1997, operating expenses of $143 million
were approximately $20 million higher than in the second quarter of 1996.
Lease and well expenses increased $6 million primarily due to expanded
operations and additional workover expenses in North America in the second
quarter of 1997. Worldwide increases in exploration activities in the
second quarter of 1997 over the second quarter of 1996 increased
exploration expenses by approximately $4 million. Impairment of unproved
oil and gas properties of $7 million was $2 million higher in the second
quarter of 1997 compared to the comparable period in 1996 due to increased
unproved lease acquisitions in North America. Depreciation, depletion and
amortization ("DD&A") expense increased approximately $10 million primarily
reflecting an increase in North America production volumes. The average
DD&A rate in the second quarter of 1997 was $.75 per thousand cubic feet
equivalent ("Mcfe") compared to $.67 per Mcfe in the second quarter of 1996
primarily reflecting the impact of a change in production mix.
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 $1.35 per Mcfe during the second quarter of 1997 compared to $1.22
per Mcfe during the second quarter of 1996. This increase is primarily due
to the increases in lease and well expenses and DD&A expense discussed
above.
Income tax provision decreased $23 million for the second quarter of
1997 as compared to the second quarter of 1996 primarily due to lower
income before income taxes and benefits of $10 million related to the sales
of certain international assets and subsidiaries and the refiling of certain
Canadian tax returns in the second quarter of 1997.
Federal income taxes accrued in interim periods are calculated using the
estimated annual effective income tax rate.
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENRON OIL & GAS COMPANY
Six Months Ended June 30, 1997
vs. Six Months Ended June 30, 1996
In the first half of 1997, the Company generated net income of $48
million compared to net income of $74 million for the first half of 1996.
Net operating revenues for the first half of 1997 were $352 million as
compared to $356 million for the comparable period a year ago.
Wellhead volume and price statistics are as follows:
1997 1996
Natural Gas Volumes (MMcf/d)(1)
United States (2) 666 611
Canada 93 97
North America 759 708
Trinidad 113 136
India 1 -
Total 873 844
Average Natural Gas Prices ($/Mcf)(3)
United States (4) $ 2.28 $ 1.82
Canada 1.48 1.16
North America Composite 2.18 1.73
Trinidad 1.04 1.00
India 2.97 -
Total Composite 2.03 1.61
Crude Oil/Condensate Volumes (MBbl/d)(1)
United States 10.9 8.6
Canada 2.4 2.5
North America 13.3 11.1
Trinidad 3.6 6.2
India 1.4 2.9
Total 18.3 20.2
Average Crude Oil/Condensate Prices ($/Bbl)(3)
United States $20.84 $20.06
Canada 17.25 17.55
North America Composite 20.19 19.50
Trinidad 18.86 18.67
India 22.99 18.88
Total Composite 20.15 19.16
(1) Million cubic feet per day or thousand barrels per
day, as applicable.
(2) Includes 48 MMcf per day for the six-month periods
ended June 30, 1997 and 1996 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
$1.85/Mcf and $.84/Mcf for the six-month periods
ended June 30, 1997 and 1996, respectively, for the
volumes described in note (2), net of transportation
costs.
Wellhead revenues increased 23% to $396 million in the first half of
1997 compared to $322 million in the first half of 1996. This increase
primarily reflects increased North America volumes and increased average
wellhead prices for natural gas, crude oil and condensate and natural gas
liquids.
<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
Average wellhead natural gas prices were up approximately 26% from the
comparable period in 1996 increasing net operating revenues by
approximately $66 million. This is primarily attributable to a 26%
increase in North America wellhead natural gas prices in the first half of
1997 compared to the first half a year ago. The overall 3% increase in
wellhead natural gas volumes in the first half of 1997 compared to the
first half of 1996 added approximately $7 million to net operating
revenues. Increases in North America wellhead natural gas volumes in the
first half of 1997 were partially offset by a reduction in Trinidad
wellhead natural gas volumes from the comparable period a year ago. The
higher Trinidad natural gas volumes in the first half of 1996 reflected
higher purchaser nominations to meet market requirements which exceeded
base contract levels. In the first half of 1997, wellhead crude oil and
condensate volumes were 9% lower than in the first half of 1996 reducing
net operating revenues by approximately $7 million. The reduction in
wellhead crude oil and condensate volumes resulted primarily from lower
condensate volumes from the Kiskadee field offshore Trinidad associated
with lower natural gas deliveries and a decline in crude oil production
from the Ibis field offshore Trinidad. Additionally, there were no second
quarter 1997 crude oil deliveries from the Panna and Mukta fields offshore
India as a result of a planned shut-down to allow for equipment change out
from temporary to permanent production facilities. A 5% increase in
wellhead crude oil and condensate average prices in the first half of 1997
as compared to first half of 1996 increased net operating revenues by
approximately $3 million.
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
reduced net operating revenue by $53 million during the first half of 1997,
compared to an $11 million increase in the first half of 1996. A $42
million revenue reduction related to natural gas commodity price hedging
activities utilizing NYMEX-related commodity market transactions in the
first half of 1997 compares to a $400 thousand increase associated with
similar transactions a year ago. A decrease in margins associated with
sales and purchases of natural gas and the volumetric production payment
reduced net operating revenues by approximately $8 million as compared to a
$16 million addition in the first half of 1996, primarily resulting from
the higher costs of natural gas delivered in 1997.
During the first half of 1997, operating expenses of $283 million were
approximately $32 million higher than in the first half of 1996. Lease and
well expenses increased $11 million primarily due to increased production
activities at higher costs in North America to maximize the volumes
delivered at the higher product prices available in the first quarter of
1997. Worldwide increases in exploration activities in the first half of
1997 over the first half of 1996 increased exploration expenses by
approximately $7 million. Dry hole expenses were approximately $3 million
lower and impairment of unproved oil and gas properties was $3 million
higher in the first half of 1997 as compared to the same period last year.
The increase in impairment of unproved oil and gas properties is primarily
a result of increased unproved lease acquisitions in North America. DD&A
expense increased approximately $10 million in the first half of 1997
compared to the first half of 1996, primarily reflecting an increase in
North America production volumes. The average DD&A rate in the first half
of 1997 was $.73 per Mcfe compared to $.69 per Mcfe which primarily
reflects the impact of a change in production mix. First half 1997 taxes
other than income increased approximately $7 million over the comparable
period in 1996 primarily reflecting increased wellhead revenues in North
America.
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 $1.36 per Mcfe during the first half of 1997 compared to $1.23 per
Mcfe during the first half of 1996. This increase is primarily due to the
increases in lease and well expenses, DD&A expense and taxes other than
income discussed above.
Income tax provision decreased $10 million for the first half of 1997 as
compared to the first half of 1996 primarily due to lower income before
income taxes. A $10 million benefit related to the sales of certain
international assets and subsidiaries and the refiling of certain Canadian
tax returns was recognized in the first half of 1997. A $9 million benefit
was recognized in the first half of 1996 associated with a reassessment of
deferred tax requirements and the successful resolution on audit of
Canadian income taxes for certain prior years.
Federal income taxes accrued in interim periods are calculated using the
estimated annual effective income tax rate.
<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
Capital Resources and Liquidity
The Company's primary sources of cash during the six months ended June
30, 1997 included funds generated from operations 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 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 $237
million during the first six months of 1997 compared to $278 million
generated for the comparable period in 1996 primarily reflecting lower
proceeds from sales of reserves and related assets.
Net operating cash flows of $243 million for the first half of 1997
increased approximately $58 million as compared to the first half of 1996
primarily reflecting changes in working capital requirements resulting from
the higher 1996 end of year operating revenues collected in 1997 partially
offset by the higher level of related end of year 1996 accounts payable
paid in 1997. Based upon existing economic and market conditions,
management believes net operating cash flow and available financing
alternatives in 1997 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
1997 and 1996 are as follows (in millions):
1997 1996
North America $ 271 $ 167
Outside North America
India 44 29
Other 15 10
Total $ 330 $ 206
Exploration and development expenditures for the first six months of
1997 were higher than expenditures in the first six months of 1996
primarily due to increased acquisitions in North America and increased
developmental drilling activities in North America and offshore India.
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 I. FINANCIAL INFORMATION - (Concluded)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Concluded)
ENRON OIL & GAS COMPANY
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 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>
PART II. OTHER INFORMATION
ENRON OIL & GAS COMPANY
ITEM 1. Legal Proceedings
See Part I, Item 1, Note 4 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
quarterly period ended June 30, 1997.
<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: August 14, 1997 By /S/ W. C. WILSON
W. C. Wilson
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 14, 1997 By /S/ BEN B. BOYD
Ben B. Boyd
Vice President and Controller
(Principal Accounting Officer)
<PAGE>
Exhibit 12
Enron Oil & Gas Company
Computation of Ratio of Earnings to Fixed Charges
(In Thousands)
(Unaudited)
<TABLE>
Six Months
Ended Year Ended December 31
6/30/97 1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR
FIXED CHARGES:
Net Income $ 47,636 $140,008 $142,118 $147,998 $138,025 $ 97,580
Less: Capitalized
Interest Expense (7,043) (9,136) (6,490) (6,124) (5,457) (3,580)
Add: Fixed Charges 17,622 21,997 18,414 14,613 15,378 25,869
Income Tax Provision(Benefit) 13,786 50,954 41,936 5,937 (25,752) (17,736)
Earnings Available $ 72,001 $203,823 $195,978 $162,424 $122,194 $102,133
FIXED CHARGES:
Interest Expense 10,386 12,370 11,310 8,135 9,921 22,289
Capitalized Interest 7,043 9,136 6,490 6,124 5,457 3,580
Rental Expense Representative
of Interest Factor 193 491 614 354 - -
Total Fixed Charges $ 17,622 $ 21,997 $ 18,414 $ 14,613 $ 15,378 $ 25,869
RATIO OF EARNINGS
TO FIXED CHARGES 4.09 9.27 10.64 11.12 7.95 3.95
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> JUN-30-1997
<CASH> 16,531
<SECURITIES> 0
<RECEIVABLES> 207,052
<ALLOWANCES> 0
<INVENTORY> 29,473
<CURRENT-ASSETS> 270,007
<PP&E> 4,016,705
<DEPRECIATION> (1,779,499)
<TOTAL-ASSETS> 2,535,872
<CURRENT-LIABILITIES> 218,966
<BONDS> 0
0
0
<COMMON> 201,600
<OTHER-SE> 1,053,399
<TOTAL-LIABILITY-AND-EQUITY> 2,535,872
<SALES> 342,799
<TOTAL-REVENUES> 352,404
<CGS> 0
<TOTAL-COSTS> 282,615
<OTHER-EXPENSES> (2,212)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,579
<INCOME-PRETAX> 61,422
<INCOME-TAX> 13,786
<INCOME-CONTINUING> 47,636
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 47,636
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
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