Enron-1997-10-K-n.htm

Enron-1997-10-K-n.htm

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(1) Includes 48 MMcf per day in 1997, 1996 and 1995
delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as
amended.
(2) Includes an average equivalent wellhead value of $1.73
per Mcf in 1997, $1.17 per Mcf in 1996, and $.80 per
Mcf in 1995 for the volumes described in note (1), net
of transportation costs.
(3) Includes certain non-recurring startup costs.



(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy Services.



* Includes acquisition of additional interests in
certain wells in which EOG previously held an interest.



(a) Tax affected at 35%, except where a specific tax rate
applied.



(a) For 1997, the conversion of preferred shares to common
shares for purposes of the diluted earnings per share
calculation was anti-dilutive by $0.03 per share. However, in
order to present comparable results, per share amounts for
each earnings component were calculated using 295 million
shares, which assumes the conversion of preferred shares to
common shares.



(a) Million cubic feet per day or thousand barrels per day, as
applicable.
(b) Includes an annual average of 48 MMcf/d in 1997, 1996 and
1995 delivered under the terms of a volumetric production
payment agreement effective October 1, 1992, as amended.
(c) Includes an average equivalent wellhead value of $1.73 per
Mcf in 1997, $1.17 per Mcf in 1996 and $0.80 per Mcf in 1995
for the volumes detailed in Note (b) above, net of
transportation costs.



(a) Thousand megawatt-hours.
(b) Mills (1/10 cent) per kilowatt-hour.



(a) Billion British thermal units equivalent per day.
(b) Includes third-party transactions by Enron Energy Services.



(a) Excludes exploration expenses of $75 million (estimate),
$75 million, $68 million and $55 million for 1998, 1997, 1996
and 1995, respectively.



(a) Includes only the risk related to the financial
instruments that serve as hedges and does not include the
related underlying hedged production.



The accompanying notes are an integral part of these consolidated
financial statements.



The accompanying notes are an integral part of these
consolidated financial statements.



The accompanying notes are an integral part of these
consolidated financial statements.



The accompanying notes are an integral part of these consolidated financial
statements.



The accompanying notes are an integral part of these consolidated financial
statements.



(a) The interest rate fixed price receiver includes the net
notional dollar value of the interest rate sensitive component
of the combined commodity portfolio. The remaining interest
rate fixed price receiver and the entire interest rate fixed
price payor represent the notional contract amount of a
portfolio of various financial instruments used to hedge the
net present value of the commodity portfolio. For a given
unit of price protection, different financial instruments
require different notional amounts.



(a) Computed using the ending balance at each month end.



(a) "Investment Grade" is primarily determined using publicly
available credit ratings along with consideration of
collateral, which encompass standby letters of credit, parent
company guarantees and property interests, including oil and
gas reserves. Included in "Investment Grade" are
counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively.
(b) One and two customers' exposures at December 31, 1997 and
1996, respectively, comprise greater than 5% of Assets From
Price Risk Management Activities. All are included above as
Investment Grade.



(a) Includes $216 million and $128 million in other current
liabilities for 1997 and 1996, respectively.



(a) Included in the Transportation and Distribution segment.
(b) Included in the Wholesale Energy Operations and Services
segment.
(c) Included in the Corporate and Other segment.
(d) JEDI accounts for its investments at fair value.
(e) Net of minority interests, the ownership is 31%.



(a) Redeemable under certain circumstances after specified
dates.
(b) Mature in 2046.
(c) Mandatorily redeemable in 2006.



(a) For 1997, the dividends and conversion of preferred stock
have been excluded from the computation because it is
antidilutive.



(a) Includes 1,768,074 shares issued in connection with business
acquisitions discussed in Note 2.
(b) Includes up to 12,246,040 shares, 5,232,218 shares and
5,209,620 shares as of December 31, 1997, 1996 and 1995,
respectively, which may be issued either as restricted stock
or pursuant to stock options.



(a) Includes plan assets of the ESOP of $135 million and $137
million for the years 1997 and 1996, respectively.
(b) Long-term rate of return on assets is assumed to be 10.5%
for the Enron Plan and 9.0% for the Portland General Plan.
(c) Rate of increase in wages is assumed to be 4.0% for the
Enron Plan and 4.0% to 9.5% for the Portland General Plan.



(a) Long-term rate of return on assets, before taxes, is
assumed to be 7.5% for the Enron assets and 9.5% for the
Portland General assets.
(b) Health care cost trend rate is assumed to be 8.0% for
Enron and 7.5% for Portland General. These rates are assumed
to decrease to 5.0% by 2003.



(a) The sum of earnings per share for the four quarters may not
equal earnings per share for the total year due to changes in
the average number of common shares outstanding.
Additionally, certain items in the diluted earnings per share
computation were antidilutive in the second quarter and total
year 1997.



(a) Unaffiliated revenues include sales to unconsolidated subsidiaries.
(b) Intersegment sales are made at prices comparable to those received
from unaffiliated customers and in some instances are affected by
regulatory considerations.
(c) Includes consolidating eliminations.



(a) Costs have been categorized on the basis of Financial
Accounting Standards Board definitions which include costs of
oil and gas producing activities whether capitalized or
charged to expense as incurred.



(a) Excludes net revenues associated with other marketing
activities, interest charges, general corporate expenses and
certain gathering and handling fees, which are not part of
required disclosures about oil and gas producing activities.



(a) Based on year-end market prices determined at the point
of delivery from the producing unit.
(b) Excludes $18 million, $75 million and $36 million at
December 31, 1997, 1996 and 1995, respectively, associated
with a volumetric production payment sold effective October 1,
1992, as amended, to be delivered over a 78 month period
beginning October 1, 1992.



(a) Includes approximately $86 million, $344 million and $77
million related to the reserves in the Big Piney deep
Paleozoic formations at December 31, 1997, 1996 and 1995,
respectively.



(a) Excludes approximately 21 Bcf, 38 Bcf, 54 Bcf and 71 Bcf
at December 31, 1997, 1996, 1995 and 1994, respectively,
associated with a volumetric production payment sold effective
October 1, 1992, as amended, to be delivered over a 78 month
period beginning October 1, 1992.
(b) Includes 1,180 Bcf related to net proved deep Paleozoic
natural gas reserves.
(c) Includes crude oil, condensate and natural gas liquids.



(a) Amounts exclude costs incurred on sales of accounts receivable.