AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 7, 1995
REGISTRATION NO. 33-64057
==============================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
AMENDMENT NO. 1
TO
FORM S-3
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
------------------------
ENRON CORP.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 47-0255140
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER
OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
1400 SMITH STREET, HOUSTON, TEXAS 77002
TELEPHONE NO. (713) 853-6161
(ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF
REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)
------------------------
JAMES V. DERRICK, JR., ESQ.
SENIOR VICE PRESIDENT AND GENERAL COUNSEL
ENRON CORP.
1400 SMITH STREET
HOUSTON, TEXAS 77002
(713) 853-6161
(NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE,
OF AGENT FOR SERVICE)
------------------------
COPIES TO:
GARY W. ORLOFF, ESQ. REX R. ROGERS, ESQ.
BRACEWELL & PATTERSON, L.L.P. ASSISTANT GENERAL COUNSEL
SOUTH TOWER PENNZOIL PLACE ENRON CORP.
711 LOUISIANA STREET, SUITE 2900 1400 SMITH STREET, ROOM 4842
HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon
as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered
on a delayed or continuous basis pursuant to Rule 415 under the Securities Act
of 1933, check the following box.
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering.
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering.
If delivery of the prospectus is expected to be made pursuant to Rule
434, please check the following box.
------------------------
CALCULATION OF REGISTRATION FEE
==============================================================================
PROPOSED
MAXIMUM
TITLE OF EACH AGGREGATE
CLASS OF SECURITIES OFFERING AMOUNT OF
TO BE REGISTERED PRICE(1) REGISTRATION FEE
- ------------------------------------------------------------------------------
Exchangeable Notes...................... $218,625,000 $75,388(2)
==============================================================================
>
(1) Estimated pursuant to Rule 457 solely for the purpose of calculating the
registration fee.
(2) Previously paid.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS
REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH
SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION
STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING
PURSUANT TO SAID SECTION 8(A), MAY DETERMINE.
==============================================================================
<PAGE>
******************************************************************************
* INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR *
* AMENDMENT. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES *
* HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE *
* SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED *
* PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. *
* THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE *
* SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF *
* THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION *
* OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION *
* UNDER THE SECURITIES LAWS OF ANY SUCH STATE. *
******************************************************************************
SUBJECT TO COMPLETION, DATED DECEMBER 7, 1995
10,000,000 EXCHANGEABLE NOTES
ENRON CORP.
% EXCHANGEABLE NOTES DUE , 1998
(SUBJECT TO EXCHANGE INTO SHARES OF COMMON STOCK,
PAR VALUE $.01 PER SHARE, OF ENRON OIL & GAS COMPANY)
------------------------
The principal amount of each of the % Exchangeable Notes due
, 1998 (the "Exchangeable Notes") of Enron Corp. ("Enron")
being offered hereby (the "Exchangeable Notes Offering") will be $ (the
closing sale price of the common stock, par value $.01 per share (the "Common
Stock"), of Enron Oil & Gas Company ("EOG") on 1995, as
reported on the New York Stock Exchange Composite Tape) (the "Initial Price").
The Exchangeable Notes will mature on , 1998. Interest on
the Exchangeable Notes, at the rate of % of the principal amount per annum,
is payable quarterly in arrears on , , and , beginning
, 1996. The Exchangeable Notes are not subject to redemption, defeasance or
any sinking fund prior to maturity.
At maturity, including as a result of acceleration or otherwise
("Maturity"), each Exchangeable Note will be mandatorily exchanged by Enron
into a number of shares of EOG Common Stock (or, at Enron's option, which may
be exercised with respect to all, but not less than all, outstanding
Exchangeable Notes, cash with an equal value) at the Exchange Rate. The
Exchange Rate is equal to, subject to certain adjustments, (a) if the Maturity
Price is greater than or equal to $ per share of EOG Common Stock (the
"Threshold Appreciation Price"), shares of EOG Common Stock per
Exchangeable Note, (b) if the Maturity Price is less than the Threshold
Appreciation Price but is greater than the Initial Price, a fractional share
of EOG Common Stock per Exchangeable Note so that the value thereof,
determined at the Maturity Price, equals the Initial Price and (c) if the
Maturity Price is less than or equal to the Initial Price, one share of EOG
Common Stock per Exchangeable Note. The "Maturity Price" means the average
Closing Price (as defined herein) per share of EOG Common Stock for the 20
Trading Days (as defined herein) immediately prior to Maturity. Accordingly,
the amount received upon exchange may be less than the principal amount of the
Exchangeable Note, in which case an investment in the Exchangeable Notes will
result in a loss. The Exchangeable Notes will be unsecured obligations of
Enron ranking PARI PASSU with all of its other unsecured and unsubordinated
indebtedness. At September 30, 1995, Enron had $2.32 billion of outstanding
debt which is PARI PASSU to the Exchangeable Notes and its subsidiaries had
$755 million of outstanding debt ($246 million of the subsidiaries'
outstanding debt is guaranteed by Enron). The right of Enron, and hence the
right of creditors of Enron (including the holders of the Exchangeable Notes),
to participate in any distribution of assets of any subsidiary of Enron upon
its liquidation or reorganization will be subject to the prior claims of
creditors of such subsidiary, except to the extent that the claims of Enron
itself as a creditor of such subsidiary may be recognized. See
"Capitalization". Enron may only exercise its option to pay outstanding
Exchangeable Notes in cash from the proceeds of its sale of Enron common
stock. EOG will have no obligations with respect to the Exchangeable Notes.
See "Description of the Exchangeable Notes".
Concurrently with the Exchangeable Notes Offering, Enron is offering
27,000,000 shares of EOG Common Stock (31,050,000 shares if the Underwriters'
over-allotment options are exercised in full in such offerings) in concurrent
U.S. and international offerings (collectively, the "Stock Offerings"). The
consummation of the Exchangeable Notes Offering is not contingent upon the
consummation of the Stock Offerings or vice versa. Assuming the Underwriters'
over-allotment options in the Exchangeable Notes Offering and the Stock
Offerings are exercised in full and the maximum number of shares of EOG Common
Stock is delivered upon mandatory exchange of the Exchangeable Notes at
Maturity, Enron, which currently owns 80% of the outstanding shares of EOG
Common Stock, would own approximately 54% of the outstanding EOG Common Stock.
Attached hereto as Appendix A and included as part of this Prospectus is a
prospectus of EOG covering the shares of EOG Common Stock which may be
received by a holder of Exchangeable Notes at Maturity. The EOG prospectus
relates to an aggregate of 11,000,000 shares of EOG Common Stock.
For a discussion of certain United States federal income tax consequences
for holders of Exchangeable Notes, see "Certain United States Federal Income
Tax Considerations".
The Exchangeable Notes have been approved for listing on the New York Stock
Exchange ("NYSE") under the symbol "EXG", subject to official notice of
issuance. EOG Common Stock (including the shares which may be received by a
holder of Exchangeable Notes at Maturity) is listed on the NYSE under the symbol
"EOG".
PROSPECTIVE INVESTORS ARE ADVISED TO CONSIDER CAREFULLY THE INFORMATION
CONTAINED UNDER "RISK FACTORS RELATING TO EXCHANGEABLE NOTES" BEGINNING ON
PAGE 5.
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
------------------------
INITIAL PUBLIC UNDERWRITING PROCEEDS TO
OFFERING PRICE(1) DISCOUNT(2) ENRON(1)(3)
------------------ ------------ -----------
Per Exchangeable Note..... $ $ $
Total (4)................. $ $ $
- ------------
(1) Plus accrued interest, if any, from , 1995.
(2) Enron and EOG have agreed to indemnify the Underwriters against
certain liabilities, including liabilities under the Securities Act of
1933.
(3) Before deducting expenses payable by Enron, estimated to be $ .
(4) Enron has granted the Underwriters an option for 30 days to purchase
up to an additional 1,000,000 Exchangeable Notes at the initial public
offering price, less the underwriting discount, solely to cover
over-allotments. If such over-allotment option is exercised in full,
the total initial public offering price, underwriting discount and
proceeds to Enron will be $ , $ and $ , respectively. See
"Underwriting".
------------------------
The Exchangeable Notes offered hereby are offered severally by the
Underwriters, as specified herein, subject to receipt and acceptance by them,
and subject to their right to reject any order in whole or in part. It is
expected that the Exchangeable Notes will be ready for delivery in New York,
New York, on or about , 1995.
GOLDMAN, SACHS & CO.
MERRILL LYNCH & CO.
SALOMON BROTHERS INC
------------------------
The date of this Prospectus is , 1995.
AVAILABLE INFORMATION
<PAGE>
Enron, a Delaware corporation, is subject to the informational
requirements of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), and in accordance therewith files reports, proxy statements and other
information with the Securities and Exchange Commission (the "Commission").
Such reports, proxy statements and other information can be inspected and
copied at the public reference facilities maintained by the Commission at Room
1024, 450 Fifth Street, N.W., Washington, D.C. 20549; and at the following
Regional Offices of the Commission: Midwest Regional Office, Citicorp Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511; and
Northeast Regional Office, Seven World Trade Center, Suite 1300, New York, New
York 10048. Copies of such material can also be obtained from the Public
Reference Section of the Commission at 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549, at prescribed rates. Enron's Common Stock and
Cumulative Second Preferred Convertible Stock are listed on the New York and
Midwest Stock Exchanges, and Enron's Common Stock is also listed on the
Pacific Stock Exchange. Reports, proxy statements and other information
concerning Enron can be inspected and copied at the respective offices of
these exchanges at 20 Broad Street, New York, New York 10005; 120 South
LaSalle Street, Chicago, Illinois 60603; and 301 Pine Street, San Francisco,
California 94014.
This Prospectus constitutes a part of a Registration Statement on Form
S-3 (together with all amendments and exhibits thereto, the "Registration
Statement") filed with the Commission under the Securities Act of 1933, as
amended (the "Securities Act"), with respect to the Exchangeable Notes. This
Prospectus does not contain all of the information set forth in such
Registration Statement, certain parts of which are omitted in accordance with
the rules and regulations of the Commission. Reference is made to such
Registration Statement and to the exhibits relating thereto for further
information with respect to Enron and the Exchangeable Notes. Any statements
contained herein concerning the provisions of any document filed as an exhibit
to the Registration Statement or otherwise filed with the Commission or
incorporated by reference herein are not necessarily complete, and in each
instance reference is made to the copy of such document so filed for a more
complete description of the matter involved. Each such statement is qualified
in its entirety by such reference.
------------------------
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The following documents filed with the Commission by Enron (File No.
1-3423) pursuant to Section 13(a) of the Exchange Act are incorporated herein
by reference:
(a) Annual Report on Form 10-K for the year ended December 31, 1994;
(b) Quarterly Report on Form 10-Q for the quarter ended March 31,
1995;
(c) Quarterly Report on Form 10-Q for the quarter ended June 30,
1995; and
(d) Quarterly Report on Form 10-Q for the quarter ended September
30, 1995
Each document filed by Enron pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior
to the termination of the offering of the Exchangeable Notes pursuant hereto
shall be deemed to be incorporated herein by reference and to be a part hereof
from the date of filing of such document. Any statement contained herein or in
a document all or a portion of which is incorporated or deemed to be
incorporated by reference herein shall be deemed to be modified or superseded
for purposes of this Prospectus to the extent that a statement contained
herein or in any other subsequently filed document which also is or is deemed
to be incorporated by reference herein modifies or supersedes such statement.
Any statement so modified or superseded shall not be deemed, except as so
modified or superseded, to constitute a part of this Prospectus.
Enron will provide without charge to each person to whom a copy of this
Prospectus is delivered, on the request of any such person, a copy of any or
all of the foregoing documents incorporated herein by reference other than
exhibits to such documents (unless such exhibits are specifically incorporated
by reference into the documents that this Prospectus incorporates). Requests
should be directed to Secretary Division, Enron Corp., at its principal
executive offices, 1400 Smith Street, Houston, Texas 77002 (telephone:
713-853-6161).
------------------------
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE EXCHANGEABLE
NOTES OR THE EOG COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE
PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK
STOCK EXCHANGE, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING,
IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
2
PROSPECTUS SUMMARY
THE FOLLOWING IS A SUMMARY OF CERTAIN INFORMATION CONTAINED IN THIS
PROSPECTUS. IT IS NOT INTENDED TO BE COMPLETE AND IS QUALIFIED IN ITS ENTIRETY
BY THE MORE DETAILED INFORMATION CONTAINED ELSEWHERE IN THIS PROSPECTUS.
CAPITALIZED TERMS WHICH ARE NOT DEFINED IN THIS SUMMARY ARE USED AS DEFINED
ELSEWHERE IN THIS PROSPECTUS.
ENRON CORP.
Enron, organized in 1930, is an integrated natural gas company with
headquarters in Houston, Texas. Essentially all of Enron's operations are
conducted through its subsidiaries and affiliates which are principally
engaged in the gathering, transportation and wholesale marketing of natural
gas to markets throughout the United States and internationally through
approximately 44,000 miles of natural gas pipelines; the exploration for and
production of natural gas and crude oil in the United States and
internationally; the production, purchase, transportation and worldwide
marketing of natural gas liquids and refined petroleum products; the
independent (i.e., non-utility) development, promotion, construction and
operation of power plants, natural gas liquids facilities and pipelines in the
United States and internationally; and the non-price regulated purchasing and
marketing of energy related commitments.
ENRON OIL & GAS COMPANY
EOG, together with its subsidiaries, is one of the largest independent
(non-integrated) oil and gas companies in the United States in terms of
domestic proved reserves. It is engaged, directly and through its
subsidiaries, in the exploration for, and the development, production and
marketing of, natural gas and crude oil primarily in major producing basins in
the United States, as well as in Canada, Trinidad and India, and to a lesser
extent, selected other international areas.
THE EXCHANGEABLE NOTES OFFERING
EXCHANGEABLE NOTES OFFERED.... 10,000,000 Exchangeable Notes.
PRINCIPAL AMOUNT.............. $ per Exchangeable Note.
STATED MATURITY............... , 1998.
INTEREST RATE................. % per annum, or $ per Exchangeable Note
per quarter, payable quarterly in arrears.
INTEREST PAYMENT DATES........ , , , and ,
beginning , 1996.
EXCHANGE AT MATURITY.......... At Maturity, the principal amount of each
Exchangeable Note will be mandatorily exchanged
by Enron into a number of shares of EOG Common
Stock (or, at Enron's option, which may be
exercised with respect to all, but not less than
all, of the outstanding Exchangeable Notes, cash
with an equal value) at the Exchange Rate. The
Exchange Rate is equal to, subject to certain
adjustments, (a) if the Maturity Price is
greater than or equal to the Threshold Appre-
ciation Price, shares of EOG Common Stock
per Exchangeable Note, (b) if the Maturity Price
is less than the Threshold Appreciation Price
but is greater than the Initial Price, a
fractional share of EOG Common Stock per
Exchangeable Note so that the value thereof
(determined at the Maturity Price) equals the
Initial Price and (c) if the Maturity Price is
less than or equal to the Initial Price, one
share of EOG Common Stock per Exchangeable Note.
The "Maturity Price" means the average Closing
Price per share of EOG Common Stock for the 20
Trading Days immediately prior to Maturity.
Accordingly, holders of the Exchangeable Notes
will not necessarily receive an amount equal to
the principal
3
amount thereof. The Exchangeable Notes are not
exchangeable for EOG Common Stock at the option
of the holder. Enron may only exercise its
option to pay outstanding Exchangeable Notes in
cash from the proceeds of its sale of Enron
common stock. See "Description of the
Exchangeable Notes-- General."
NO REDEMPTION OR SINKING FUND. The Exchangeable Notes are not subject to
redemption, defeasance or any sinking fund prior
to Maturity.
RANKING........................ The Exchangeable Notes will be unsecured
obligations of Enron ranking PARI PASSU with all
of its other unsecured and unsubordinated
indebtedness.
RELATIONSHIP OF EXCHANGEABLE
NOTES TO EOG COMMON STOCK... The Exchangeable Notes will bear interest at %
per annum, a yield substantially in excess of
the % anticipated dividend yield of EOG Common
Stock based on the Initial Price of $ and the
current quarterly dividend payable on EOG Common
Stock. However, the opportunity for equity
appreciation afforded by an investment in the
Exchangeable Notes is less than the opportunity
for equity appreciation afforded by an
investment in EOG Common Stock because the
amount receivable by a holder of an Exchangeable
Note upon exchange at Maturity will only exceed
the principal amount of such Exchangeable Note
if the Maturity Price exceeds the Threshold
Appreciation Price (which represents an
appreciation of % over the Initial Price).
Moreover, holders of the Exchangeable Notes will
only be entitled to receive upon exchange at
Maturity % (the percentage equal to the Ini-
tial Price divided by the Threshold Appreciation
Price) of any appreciation of the value of EOG
Common Stock in excess of the Threshold
Appreciation Price. Holders of the Exchangeable
Notes will not be entitled to any rights with
respect to EOG Common Stock (including, without
limitation, voting rights and rights to receive
any dividends or other distributions in respect
thereof) until such time, if any, as Enron shall
have exchanged shares of EOG Common Stock for
Exchangeable Notes at Maturity thereof and
unless the applicable record date, if any, for
the exercise of such rights occurs after such
exchange.
USE OF PROCEEDS............... The net proceeds will be added to Enron's
general funds and are expected to be used to
retire existing indebtedness and for general
corporate purposes. See "Use of Proceeds."
RELATIONSHIP BETWEEN ENRON
AND EOG..................... Enron currently owns 80% of the outstanding
shares of EOG Common Stock. Assuming the
Underwriters' over-allotment options in this
offering and the concurrent Stock Offerings are
exercised in full and the maximum number of
shares of EOG Common Stock is delivered upon the
mandatory exchange of the Exchangeable Notes at
Maturity, Enron would own approximately 54% of
the outstanding shares of EOG Common Stock. See
"Relationship Between Enron and EOG."
4
RISK FACTORS RELATING TO EXCHANGEABLE NOTES
As described in more detail below, the trading price of the Exchangeable
Notes may vary considerably prior to Maturity due to, among other things,
fluctuations in the price of EOG Common Stock and other events that are
difficult to predict and beyond Enron's control.
COMPARISON TO OTHER DEBT SECURITIES; RELATIONSHIP OF EXCHANGEABLE NOTES TO EOG
COMMON STOCK
The terms of the Exchangeable Notes differ from those of ordinary debt
securities in that the amount that a holder of the Exchangeable Notes will
receive upon mandatory exchange at Maturity is not fixed, but is based on the
price of the EOG Common Stock as specified in the Exchange Rate. There can be
no assurance that the amount received by such holder upon exchange at Maturity
(whether in stock or cash) will be equal to or greater than the principal
amount of an Exchangeable Note because the price of the EOG Common Stock is
subject to market fluctuations, and the value of the EOG Common Stock (or, at
the option of Enron, the amount of cash) received by a holder of an
Exchangeable Note upon exchange at Maturity, determined as described herein,
may be more or less than the principal amount of the Exchangeable Note. For
example, if the Maturity Price of the EOG Common Stock is less than the
Initial Price, the amount received upon exchange will be less than the
principal amount paid for the Exchangeable Note, in which case an investment
in Exchangeable Notes will result in a loss.
In addition, the opportunity for equity appreciation afforded by an
investment in the Exchangeable Notes is less than the opportunity for equity
appreciation afforded by an investment in the EOG Common Stock because the
amount received by a holder of an Exchangeable Note upon exchange at Maturity
will only exceed the principal amount of such Exchangeable Note if the
Maturity Price exceeds the Threshold Appreciation Price (which represents an
appreciation of % over the Initial Price). Holders of the Exchangeable Notes
will only be entitled to receive upon exchange at Maturity % of any
appreciation of the value of EOG Common Stock in excess of the Threshold
Appreciation Price.
It is impossible to predict whether the price of EOG Common Stock will
rise or fall. Trading prices of EOG Common Stock will be influenced by EOG's
operational results and by complex and interrelated political, economic,
financial and other factors that can affect natural gas and crude oil
commodity markets generally. See the prospectus relating to EOG and to EOG
Common Stock attached hereto as Appendix A and included as part of this
Prospectus.
In addition, in the event Enron does not exercise its option to deliver
cash, holders of the Exchangeable Notes will not be entitled to any rights
with respect to the EOG Common Stock (including, without limitation, voting
rights and rights to receive any dividends or other distributions in respect
thereof) until such time as Enron shall have exchanged shares of EOG Common
Stock for Exchangeable Notes at Maturity thereof and unless the applicable
record date, if any, for the exercise of such rights occurs after such
exchange.
The Exchangeable Notes will be unsecured obligations of Enron ranking
PARI PASSU with all of its other unsecured and unsubordinated indebtedness.
The terms of the Exchangeable Notes do not limit the amount of indebtedness
which may be incurred by Enron.
DILUTION OF EOG COMMON STOCK
The amount that holders of the Exchangeable Notes are entitled to receive
upon the mandatory exchange at Maturity is subject to adjustment for certain
events arising from stock splits and combinations, stock dividends and certain
other actions of EOG that modify its capital structure. See "Description of
the Exchangeable Notes -- Dilution Adjustments." The amount to be received by
holders of Exchangeable Notes upon mandatory exchange at Maturity may not be
adjusted for other events, such as offerings of EOG Common Stock for cash or
in connection with acquisitions, that
5
may adversely affect the price of the EOG Common Stock and, because of the
relationship of such amount to be received upon exchange to the price of EOG
Common Stock, such other events may adversely affect the trading price of the
Exchangeable Notes. There can be no assurance that EOG will not make offerings
of EOG Common Stock or take other action in the future.
POSSIBLE ILLIQUIDITY OF THE SECONDARY MARKET
It is not possible to predict how the Exchangeable Notes will trade in
the secondary market or whether such market will be liquid or illiquid.
Exchangeable Notes are novel securities and there is currently no secondary
market for the Exchangeable Notes. The Underwriters currently intend, but are
not obligated, to make a market in the Exchangeable Notes. There can be no
assurance that a secondary market will develop or, if a secondary market does
develop, that it will provide the holders of the Exchangeable Notes with
liquidity of investment or that it will continue for the life of the
Exchangeable Notes.
The Exchangeable Notes have been approved for listing on the NYSE, subject
to official notice of issuance. However, there can be no assurance that the
Exchangeable Notes will not later be delisted or that trading in the
Exchangeable Notes on the NYSE will not be suspended. If the Exchangeable Notes
are not listed or traded on any securities exchange or trading market, or if
trading of the Exchangeable Notes is suspended, pricing information for the
Exchangeable Notes may be more difficult to obtain, and the liquidity of the
Exchangeable Notes may be adversely affected.
NO OBLIGATION ON THE PART OF EOG WITH RESPECT TO THE EXCHANGEABLE NOTES
EOG has no obligations with respect to the Exchangeable Notes or amounts
to be paid to holders thereof, including any obligation to take the needs of
holders of the Exchangeable Notes into consideration for any reason. EOG will
not receive any of the proceeds of the offering of the Exchangeable Notes made
hereby and is not responsible for the determination of the timing of, prices
for or quantities of the Exchangeable Notes to be issued or the determination
or calculation of the amount to be paid upon mandatory exchange at Maturity.
TAX UNCERTAINTIES
The Indenture (as defined herein) requires that any holder subject to
U.S. federal income tax include currently in income, for U.S. federal income
tax purposes, payments denominated as interest that are made with respect to
the Exchangeable Notes, in accordance with such holder's method of accounting,
and the amount of original issue discount ("OID"), if any, attributable to the
Exchangeable Notes as it accrues. The Indenture also requires holders to treat
the Exchangeable Notes as a unit consisting of (i) an exchange note, which is
a debt obligation with a fixed principal amount unconditionally payable at
Maturity equal to the principal amount of the Exchangeable Notes, and (ii) a
forward purchase contract pursuant to which the holder agrees to use the
principal payment due on the Exchangeable Notes to purchase at Maturity the
EOG Common Stock that the holder is entitled to receive at that time (subject
to Enron's right to deliver cash in lieu of the EOG Common Stock). It is
contemplated that, upon a holder's sale or other disposition of the
Exchangeable Notes prior to Maturity, the amount realized will be allocated
between these two components of the Exchangeable Notes on the basis of their
then relative fair market values. Because of an absence of authority as to the
proper characterization of the Exchangeable Notes for tax purposes, these tax
characterizations and results are uncertain. This uncertainty extends to
characterization of any gain or loss recognized with respect to the
Exchangeable Notes at Maturity as capital gain or loss or ordinary income or
loss and, in the event Enron delivers EOG Common Stock at Maturity, as to
whether any gain or loss can be deferred until a sale or disposition of such
stock. As a result of these uncertainties, Enron has not received an opinion
of counsel with respect to the specific tax consequences of owning or
disposing of the Exchangeable Notes. See "Certain United States Federal Income
Tax Considerations."
6
ENRON CORP.
Enron, a Delaware corporation organized in 1930, is an integrated natural
gas company with headquarters in Houston, Texas. Essentially all of Enron's
operations are conducted through its subsidiaries and affiliates which are
principally engaged in the gathering, transportation and wholesale marketing
of natural gas to markets throughout the United States and internationally
through approximately 44,000 miles of natural gas pipelines; the exploration
for and development and production of natural gas and crude oil in the United
States and internationally; the production, purchase, transportation and
worldwide marketing of natural gas liquids and refined petroleum products; the
independent (i.e., non-utility) development, promotion, construction and
operation of power plants, natural gas liquids facilities and pipelines in the
United States and internationally; and the non-price regulated purchasing and
marketing of energy related commitments.
TRANSPORTATION AND OPERATION. Enron's operations include the interstate
and intrastate transmission of natural gas, construction, management and
operation of natural gas and natural gas liquids pipelines, liquids plants,
clean fuel plants and power facilities. Enron and its subsidiaries operate
domestic interstate pipelines extending from Texas to the Canadian border and
across the southern United States from Florida to California. Included in
Enron's domestic interstate natural gas pipeline operations are Northern
Natural Gas Company ("Northern"), Transwestern Pipeline Company
("Transwestern"), and Florida Gas Transmission Company ("Florida Gas")
(indirectly 50% owned by Enron), and all such pipelines are subject to the
regulatory jurisdiction of the Federal Energy Regulatory Commission. Each
pipeline serves customers in a specific geographical area: Northern, the upper
Midwest; Florida Gas, the State of Florida; and Transwestern, principally the
California market. In addition, Enron holds a 13% interest in Northern Border
Partners, L.P., which owns a 70% interest in the Northern Border Pipeline
system. An Enron subsidiary operates the Northern Border Pipeline system,
which transports gas from western Canada to delivery points in the midwestern
United States. Also, Enron has an approximate 15% interest in Enron Liquids
Pipeline, L.P., which is engaged in pipeline transportation of natural gas
liquids, refined petroleum products and carbon dioxide, operates coal
terminalling, gas processing and natural gas liquids fractionation facilities,
and is operated by a wholly owned subsidiary of Enron.
DOMESTIC GAS AND POWER SERVICES. Enron Capital & Trade Resources Corp.
and its affiliated companies ("ECT") purchase natural gas, natural gas liquids
and power through a variety of contractual arrangements, including both short-
and long-term contracts, the arrangement of production payment and other
financing transactions, and other contractual arrangements. ECT markets these
energy products to local distribution companies, electric utilities,
cogenerators, and both commercial and industrial end-users. ECT also provides
price risk management services in connection with natural gas, gas liquids and
power transactions through both physical delivery and financial arrangements.
ECT offers a broad range of non-price regulated natural gas merchant
services by tailoring a variety of supply and marketing options to its
customers' specific needs. ECT's strategy is to provide predictable pricing,
reliable delivery and low cost capital to its customers. ECT provides these
services through a variety of instruments, including forward contracts, swap
agreements and other contractual commitments.
Certain Enron subsidiaries are engaged domestically in the extraction of
natural gas liquids (ethane, propane, normal butane, isobutane and natural
gasoline), which are typically extracted from natural gas in liquid form under
low temperature and high pressure conditions. Ethane, propane, normal butane,
isobutane and natural gasoline are used as feedstocks for petrochemical plants
in the production of plastics, synthetic rubber and other products. Normal
butane and natural gasoline are used by refineries in the blending of motor
gasoline. Isobutane is used in the alkylation process to enhance the octane
content of motor gasoline and is also used in the production of MTBE, which is
used to produce cleaner burning motor gasoline. Propane is used as fuel for
home heating and
7
cooking, crop drying and industrial facilities and as an engine fuel for
vehicles, and ethane is used as a feedstock for synthetic fuels production.
INTERNATIONAL GAS AND POWER SERVICES. Enron's international activities
principally involve the independent (non-utility) development, acquisition,
promotion and operation of natural gas and power projects and the marketing of
natural gas liquids. As is the case in the United States, Enron's emphasis is
on businesses in which natural gas or its components play a significant role.
Development projects are focused on power plants, gas processing and
terminalling facilities, and gas pipelines, while marketing activities center
on fuels used by or transported through such facilities. Enron's international
activities include management of direct and indirect ownership interests in
and operation of power plants in England, Germany, Guatemala and the
Philippines; a pipeline system in southern Argentina; retail gas and propane
sales in the Caribbean basin; processing of natural gas liquids at Teesside,
England; and marketing of natural gas liquids worldwide. Enron is also
involved in power and pipeline projects in varying stages of development in
China, the Dominican Republic, Colombia, Turkey, Bolivia and Brazil, Indonesia
and elsewhere.
Enron Global Power & Pipelines L.L.C., a Delaware limited liability
company ("EPP"), was formed in November 1994 by Enron to own and manage
Enron's operating power plant and natural gas pipeline business conducted
outside the United States, Canada and Western Europe, and to expand such
business through acquisitions. EPP's initial assets consist of interests
contributed by Enron in two power plants in the Philippines (with 226
megawatts of aggregate net generating capacity), a power plant in Guatemala
(with 110 megawatts of net generating capacity) and a 6,548 kilometer (4,069
mile) natural gas pipeline system in Argentina. The public offering of common
shares of EPP was completed in November 1994. Enron owns approximately 52% of
the common shares of EPP. Enron formed EPP to attract public equity capital to
emerging market infrastructure projects, to enable public investors to better
evaluate and participate directly in the growth of Enron's operating power
plant and natural gas pipeline activities in emerging markets and to generate
additional capital for Enron to reinvest in future development efforts and for
other corporate purposes.
EXPLORATION AND PRODUCTION. Substantially all of Enron's natural gas and
crude oil exploration and production operations are conducted by its
subsidiary EOG. EOG is engaged in the exploration for, and development,
production and marketing of, natural gas and crude oil primarily in major
producing basins in the United States, as well as in Canada, Trinidad, India
and to a lesser extent, selected other international areas. At December 31,
1994, EOG had estimated net proved natural gas reserves of 1,910 billion cubic
feet and estimated net proved crude oil, condensate and natural gas liquids
reserves of 37 million barrels, and at such date, approximately 70% of EOG's
reserves (on a natural gas equivalent basis) was located in the United States,
16% in Canada, 11% in Trinidad and 3% in India. A limited partnership in which
ECT owns a 50% general partner interest has entered into an agreement to
acquire a controlling interest in Coda Energy, Inc. ("Coda"). Coda is engaged
in the exploration for, and the development, production and marketing of,
natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil
accounts for approximately 86% of Coda's proved reserves. At December 31,
1994, Coda reported estimated proved natural gas reserves of 39,808 million
cubic feet ("MMcf") and estimated proved crude oil, condensate and natural gas
liquids reserves of 39,207 thousand barrels ("MBbls"). See "Relationship
Between Enron and EOG -- Conflicts of Interest."
RECENT EVENTS
In connection with a Power Purchase Agreement dated December 8, 1993, as
amended, between Dabhol Power Company, Enron's 80%-owned subsidiary, and the
Maharashtra State Electricity Board (the "MSEB"), Dabhol Power Company has
been developing Phase I (approximately 695 megawatts) of a 2,015 megawatt
electricity generating power plant south of Bombay, State of Maharashtra,
India (the "Project"). Financial closing occurred and Project construction
8
began on March 1, 1995. After construction had begun, and following elections
to the Maharashtra Legislative Assembly, a new coalition government took
office in the State of Maharashtra. The new coalition government appointed a
review committee to study the Project, and on August 3, 1995, announced the
State government's intention to terminate the Project. Work on the Project was
ordered stopped by the MSEB, and construction ceased on August 8, 1995. Enron
believes that such actions were in clear violation of the contract and in
response to these actions, Dabhol Power Company is pursuing two courses of
action. First, pursuant to Dabhol Power Company's remedies in the agreements
with the State government, arbitration has commenced in London against the
State government for the actions it has taken to terminate the Project. Dabhol
Power Company seeks to recover all of its construction and other expenses, in
addition to lost profits. The arbitration tribunal has been appointed and one
arbitration hearing has occurred in London. Second, Dabhol Power Company has
both orally and in writing communicated to the Maharashtra State government
its desire to go forward with construction of the Project and its willingness
to resolve any outstanding issues, and discussions to resolve outstanding
issues have begun. Although the outcome of neither the arbitration nor the
renegotiation process can be predicted with certainty, based on currently
available information, Enron believes that the ultimate outcome of the Project
will not have a materially adverse effect on its financial position.
In March 1993, Enron entered into long-term gas contracts with Phillips
Petroleum Company United Kingdom Limited, British Gas Exploration and
Production Limited and Agip (U.K.) Limited to purchase all of the future gas
production from the J-Block field which is located in the North Sea offshore
the United Kingdom (the "J-Block Contracts"). Such agreements provide for
Enron to take or pay for the gas at a fixed price (with possible escalations
throughout the contract period). Gas paid for, but not taken, may be recovered
in later contract years. The J-Block Contracts provide for a first delivery
date of not later than October 1, 1996. The contract price for such natural
gas is in excess of current spot market prices in the United Kingdom. In
September 1995, Enron announced that, in accordance with its contractual
rights, it had notified the J-Block sellers that Enron's nominations for gas
from the J-Block field were estimated to be zero from the first delivery date
through September 30, 1997. In addition, in accordance with its contractual
rights, Enron has made no estimated nominations for J-Block gas to date under
the J-Block Contracts for the contract year ending September 30, 1998. Enron
continues its good faith efforts to develop mutually beneficial solutions
regarding pricing terms so that production from J-Block can begin as soon as
possible. Enron believes that there are many commercial reasons for the
parties to resolve any contract issues, but efforts have not been successful
to date. Enron has advised the J-Block sellers that it intends to assert all
legal rights, exercise all available commercial flexibility and pursue all
available commercial and legal remedies under the J-Block Contracts, and
stands ready and able to perform all legal obligations under the J-Block
Contracts, including potential prepayments for gas to be taken in later years.
The long-term market demand for J-Block gas supply remains favorable and Enron
anticipates being able to meet all of its various short- and long-term market
commitments. Although no assurances can be given, based upon the foregoing and
other information currently available, Enron does not at this time anticipate
that the J-Block Contracts will have a materially adverse effect on Enron's
financial position.
9
<PAGE>
SELECTED FINANCIAL DATA OF ENRON
The financial information set forth below has been derived from the
audited and unaudited consolidated financial statements of Enron. The
information should be read in connection with, and is qualified in its
entirety by reference to, Enron's financial statements and notes thereto
incorporated by reference herein. See "Incorporation of Certain Documents by
Reference." The interim data reflects all adjustments which, in the opinion of
the management of Enron, are necessary to present fairly such information for
the interim periods. The results of operations for the nine-month periods are
not necessarily indicative of the results expected for a full year or any
other interim period.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
----------------------------------------------------- --------------------
1990 1991 1992 1993 1994 1994 1995
--------- --------- --------- --------- --------- --------- ---------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues............................. $ 5,460 $ 5,698 $ 6,415 $ 7,985 $ 8,984 $ 6,397 $ 6,639
Costs and expenses
Cost of gas and other products
sold........................... 3,528 3,646 4,222 5,567 6,517 4,631 4,726
Operating expenses............... 861 914 936 1,057 1,033 714 751
Amortization of deferred contract
reformation costs.............. 102 125 101 89 91 65 19
Oil and gas exploration costs.... 68 59 59 76 84 58 61
Depreciation, depletion and
amortization................... 356 366 376 458 441 328 321
Taxes, other than income taxes... 82 75 101 108 102 78 85
--------- --------- --------- --------- --------- --------- ---------
4,997 5,185 5,795 7,355 8,268 5,874 5,963
--------- --------- --------- --------- --------- --------- ---------
Operating income..................... 463 513 620 630 716 523 676
Other income and deductions
Equity in earnings of unconsolidated
subsidiaries....................... 56 55 56 73 112 74 49
Other, net........................... 143 147 91 95 116 112 116
--------- --------- --------- --------- --------- --------- ---------
Income before interest, minority
interest and income taxes.......... 662 715 767 798 944 709 841
Interest and related charges, net.... 395 373 330 300 273 202 214
Dividends on preferred stock of
subsidiary company................. -- -- -- 2 20 14 24
Minority interest.................... 7 7 18 28 31 21 34
Income taxes......................... 58 103 90 135 167 127 180
--------- --------- --------- --------- --------- --------- ---------
Income before extraordinary items.... 202 232 329 333 453 345 389
Extraordinary items.................. -- -- (23) -- -- -- --
--------- --------- --------- --------- --------- --------- ---------
Net income(1)........................ 202 232 306 333 453 345 389
Preferred stock dividends............ 25 25 22 17 15 11 11
--------- --------- --------- --------- --------- --------- ---------
Earnings on Common Stock............. $ 177 $ 207 $ 284 $ 316 $ 438 $ 334 $ 378
========= ========= ========= ========= ========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------------- SEPTEMBER 30,
1990 1991 1992 1993 1994 1995
--------- --------- --------- --------- --------- ---------------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Total assets......................... $ 9,849 $ 10,070 $ 10,312 $ 11,504 $ 11,966 $ 13,029
Short-term debt...................... -- -- -- -- -- --
Long-term debt (including amounts
reclassified from short-term
debt).............................. 2,983 3,109 2,459 2,661 2,805 3,425
Preferred stock of subsidiary
company............................ -- -- -- 214 377 396
Minority interest.................... 97 101 179 196 290 316
Shareholders' equity................. 1,838 1,901 2,518 2,623 2,880 3,107
</TABLE>
- ------------
(1) Net income for the year ended December 31, 1993 includes a primarily
non-cash charge of $54 million to adjust for the increase in the corporate
federal income tax rate from 34 percent to 35 percent.
10
CAPITALIZATION
<PAGE>
The following table sets forth the capitalization of Enron and its
consolidated subsidiaries as of September 30, 1995, and as adjusted to give
effect to the issuance on October 11, 1995 of $100 million aggregate principal
amount of 6 7/8% Notes due 2007, and the issuance of the Exchangeable Notes
offered hereby and, in each case, the use of the proceeds therefrom.
ACTUAL AS ADJUSTED
------------- ------------
(IN THOUSANDS)
Short-term debt
Notes payable................... $ -- $ --
Current maturities of long-term
debt............................ -- --
------------- ------------
Total short-term debt...... -- --
------------- ------------
Long-term debt
Enron:
Amount reclassified from
short-term debt............... 587,032
Notes due 1996-2023 (6 3/4% to
10.75%)....................... 1,753,139 1,753,139
Exchangeable Notes due 1998
( %)......................... --
Notes due 2007 (6 7/8%)......... -- 100,000
Subsidiary companies:
Notes due 1998-2005 (4.52% to
9.2%)......................... 636,000 636,000
Notes due 1998-1999 (floating
rates)........................ 55,000 55,000
Other........................... 53,674 53,674
Enron:
Senior subordinated debentures
due 2005-2012 (6.75%-8.25%)... 350,000 350,000
Unamortized debt discount and
premium......................... (9,641)
------------- ------------
Total long-term debt....... 3,425,204
------------- ------------
Minority interests................... 315,821 315,821
------------- ------------
Preferred stock of subsidiary
companies.......................... 395,750 395,750
------------- ------------
Shareholders' equity
Convertible preferred stock..... 138,605 138,605
Common stock.................... 25,373 25,373
Additional paid-in capital...... 1,792,544 1,792,544
Retained earnings............... 1,574,335 1,574,335
Cumulative foreign currency
translation adjustment........ (149,570) (149,570)
Common stock held in treasury... (62,827) (62,827)
Other, including Flexible Equity
Trust......................... (210,969) (210,969)
------------- ------------
Total shareholders'
equity................... 3,107,491 3,107,491
------------- ------------
Total capitalization.. $ 7,244,266 $
============= ============
11
RELATIONSHIP BETWEEN ENRON AND EOG
OWNERSHIP OF COMMON STOCK
Through its ability to elect all directors of EOG, Enron has the ability to
control all matters relating to the management of EOG, including any
determination with respect to acquisition or disposition of EOG assets, future
issuance of Common Stock or other securities of EOG and any dividends payable on
the Common Stock. Enron also has the ability to control EOG's exploration,
development, acquisition and operating expenditure plans. The sale by Enron of
EOG Common Stock pursuant to the Stock Offerings will cause Enron's ownership
interest in EOG to fall below 80% with the result that EOG will cease to be
included in the consolidated federal income tax return filed by Enron. There is
no agreement between Enron and EOG that would prevent Enron from acquiring
additional shares of Common Stock of EOG.
CONTRACTUAL ARRANGEMENTS
EOG entered into a Services Agreement (the "Services Agreement") with
Enron effective January 1994, pursuant to which Enron provides various
services, such as maintenance of certain employee benefit plans, provision of
telecommunications and computer services, lease of office space and the
provision of purchasing and operating services and certain other corporate
staff and support services. Such services historically have been supplied to
EOG by Enron, and the Services Agreement provides for the further delivery of
such services substantially identical in nature and quality to those services
previously provided. EOG has agreed to a fixed rate for the rental of office
space and to reimburse Enron for all other direct costs incurred in rendering
services to EOG under the contract and to pay Enron for allocated indirect
costs incurred in rendering such services up to a maximum of $6.7 million for
1994, such cap to be increased in subsequent years for inflation and certain
changes in EOG's allocation bases with any increase not to exceed 7.5% per
year. Approximately $6.6 million was paid under the Services Agreement by EOG
to Enron in 1994. The Services Agreement is for an initial term of five years
through December 1998 and will continue thereafter until terminated by either
party.
In March 1995, in a series of transactions with Enron and an affiliate of
Enron, EOG exchanged all of its fuel supply and purchase contracts and related
price swap agreements associated with the Texas City cogeneration plant (the
"Cogen Contracts") for certain natural gas price swap agreements (the "Swap
Agreements") of equivalent value. As a result of the transactions, EOG has
been relieved of all performance obligations associated with the Cogen
Contracts. EOG will realize net operating revenues and receive corresponding
cash payments of approximately $91 million during the period extending through
December 31, 1999 under the terms of the Swap Agreements. The estimated fair
value of the Swap Agreements was approximately $81 million at the date the
Swap Agreements were received. The net of this series of transactions will
result in increases in net operating revenues and cash receipts for EOG during
1995 and 1996 of approximately $13 million and $7 million, respectively, with
offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen
Contracts.
EOG has been included in the consolidated federal income tax return filed
by Enron as the common parent for itself and its subsidiaries and affiliated
companies, excluding any foreign subsidiaries. Consistent therewith and
pursuant to a Tax Allocation Agreement between EOG, EOG's subsidiaries and
Enron, either Enron has paid to EOG and each subsidiary an amount equal to the
tax benefit realized in the Enron consolidated federal income tax return
resulting from the utilization of EOG's or the subsidiary's net operating
losses and/or tax credits, or EOG and each subsidiary has paid to Enron an
amount equal to the federal income tax computed on its separate taxable income
less the tax benefits associated with any net operating losses and/or tax
credits generated by EOG or the subsidiary which were utilized in the Enron
consolidated return. Enron has paid EOG and each subsidiary for the tax
benefits associated with their net operating losses and tax credits utilized
in the Enron consolidated return, provided that a tax benefit was realized
except as discussed below, even if such benefits could not have been used by
EOG or the subsidiary on a separately filed tax return. EOG entered into an
agreement with Enron providing for EOG to be paid for all realizable benefits
associated with tight gas sand federal income tax credits concurrent with tax
reporting and settlement for the periods in which they were generated. The Tax
Allocation
12
Agreement applies to EOG and each of its subsidiaries for all years in which EOG
or any of its subsidiaries are or were included in the Enron consolidated
return. To the extent a state or other taxing jurisdiction requires or permits a
consolidated, combined, or unitary tax return to be filed and such return
includes EOG or any of its subsidiaries, the principles expressed with respect
to consolidated federal income tax allocation shall apply. The Tax Allocation
Agreement will cease to be effective from the time at which deconsolidation
occurs. EOG and Enron have entered into a new tax agreement pursuant to which,
among other things, Enron has agreed (in exchange for the payment of $8.0
million by EOG) to be liable for, and to indemnify EOG against, all federal
income taxes and state taxes measured by net income imposed on EOG for periods
through the date Enron reduces its ownership in EOG to less than 80%. Enron
and EOG do not believe that the cessation of consolidated tax reporting and
effectiveness of the Tax Allocation Agreement concurrently with deconsolidation
or the terms of the new tax agreement will have a material adverse effect on the
financial condition or results of operations of either Enron or EOG.
CONFLICTS OF INTEREST
The nature of the respective businesses of EOG and Enron and its
affiliates is such as to potentially give rise to conflicts of interest
between the two companies. Conflicts could arise, for example, with respect to
transactions involving purchases, sales and transportation of natural gas and
other business dealings between EOG and Enron and its affiliates, potential
acquisitions of businesses or oil and gas properties, the issuance of
additional shares of voting securities, the election of directors or the
payment of dividends by EOG.
Circumstances may also arise that would cause Enron to engage in the
exploration for and/or development and production of natural gas and crude oil
in competition with EOG. For example, opportunities might arise which would
require financial resources greater than those available to EOG, which are
located in areas or countries in which EOG does not intend to operate or which
involve properties that EOG would be unwilling to acquire. Also, Enron might
acquire a competing oil and gas business as part of a larger acquisition. In
addition, as part of Enron's strategy of securing supplies of natural gas or
capital, Enron may from time to time acquire producing properties or interests
in entities owning producing properties, and thereafter engage in exploration,
development and production activities with respect to such properties or
indirectly engage in such activities through such companies. Enron subsidiaries
provide or arrange financing, including debt or equity financing, for
exploration and production companies that compete with EOG. In connection with
such activities, Enron affiliates may make investments in the debt or equity of
such companies. There are currently no such transactions under consideration
that would result in voting control by Enron or any of its affiliates, other
than the transaction described in the next paragraph. In its financing
activities Enron or any entity in which it has an interest may also make loans
secured by oil and gas properties or securities of oil and gas companies, may
acquire production payments or may receive interests in oil and gas properties
as equity components of lending transactions. As a result of its lending
activities, Enron may also acquire oil and gas properties or companies upon
foreclosure of secured loans or as part of a borrower's rearrangement of its
obligations. Such acquisition, exploration, development and production
activities may directly or indirectly compete with EOG's business. There can be
no assurance that Enron will not engage, directly or indirectly through entities
other than EOG, in the natural gas and crude oil exploration, development and
production business in competition with EOG.
Joint Energy Development Investments Limited Partnership ("JEDI"), a
limited partnership in which ECT owns a 50% general partner interest, has
entered into an agreement to acquire a controlling interest in Coda. Coda is
engaged in the exploration for, and the development, production and marketing
of, natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil
accounts for approximately 86% of Coda's proved reserves. At December 31,
1994, Coda reported estimated proved natural gas reserves of 39,808 MMcf and
estimated proved crude oil, condensates and natural gas liquids reserves of
39,207 MBbls. Enron anticipates that the transaction will be consummated in
early 1996, subject to Coda stockholder approval and other conditions.
Conflicts may arise between Coda and EOG, and if the acquisition of Coda
occurs Enron will be required to resolve such conflicts in a manner that is
consistent with its fiduciary and contractual duties to other
13
investors in Coda and JEDI and its fiduciary duties to EOG. ECT has entered
into an agreement with JEDI and other investors in Coda designed to minimize
certain conflicts of interest that may arise and providing, among other
things, that EOG has no obligation to offer any business opportunities to
Coda.
EOG and Enron and its affiliates have in the past entered into
significant intercompany transactions and agreements incident to their
respective businesses, and EOG and Enron and its affiliates may be expected to
enter into material transactions and agreements from time to time in the
future. Such transactions and agreements have related to, among other things,
the purchase and sale of natural gas and crude oil, the financing of
exploration and development efforts by EOG, and the provision of certain
corporate services. Enron believes that its existing transactions and
agreements with EOG have been at least as favorable to Enron as could be
obtained from third parties, and Enron intends that the terms of any future
transactions and agreements between Enron and EOG and its affiliates will be
at least as favorable to Enron as could be obtained from third parties.
USE OF PROCEEDS
The net proceeds from the sale of the Exchangeable Notes will be added to
Enron's general funds and are expected to be used to retire existing
indebtedness and for general corporate purposes. At December 6, 1995 the
weighted average interest rate on such indebtedness was approximately 6.0%.
RATIO OF ENRON'S EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS
----------------------------------------------------- ENDED
1990 1991 1992 1993 1994 SEPTEMBER, 1995
--------- --------- --------- --------- --------- -------------------
<S> <C> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges... 1.58 1.66 1.74 1.98 2.40 2.87
</TABLE>
The ratio of earnings to fixed charges is based on continuing operations.
"Earnings" represent the aggregate of (a) the pre-tax income of Enron and its
majority owned subsidiaries, (b) Enron's share of pre-tax income of its 50%
owned companies, (c) any income actually received from less than 50% owned
companies, and (d) fixed charges, net of interest capitalized. "Fixed Charges"
represent interest (whether expensed or capitalized), amortization of debt
discount and expense and that portion of rentals considered to be
representative of the interest factor.
PRICE RANGE OF EOG COMMON STOCK AND CASH DIVIDENDS
The following table sets forth, for the periods indicated, the high and
low sale prices per share for the EOG Common Stock, as reported on the New
York Stock Exchange Composite Tape, and the amount of cash dividends paid per
share. The 1993 and First and Second Quarter 1994 sales prices and cash
dividends per share have been restated to reflect the two-for-one stock split
on May 31, 1994.
PRICE RANGE
-------------------- CASH
HIGH LOW DIVIDENDS
--------- --------- ----------
1993
First Quarter................... $ 20.31 $ 13.38 $.03
Second Quarter.................. 22.50 17.88 .03
Third Quarter................... 26.81 19.88 .03
Fourth Quarter.................. 27.00 17.06 .03
1994
First Quarter................... $ 23.75 $ 19.31 $.03
Second Quarter.................. 24.63 22.38 .03
Third Quarter................... 23.00 18.50 .03
Fourth Quarter.................. 22.75 17.38 .03
1995
First Quarter................... $ 24.88 $ 17.12 $.03
Second Quarter.................. 24.75 20.25 .03
Third Quarter................... 25.38 20.00 .03
Fourth Quarter (through
December 6, 1995)............. 22.75 18.75
The last reported sale price of the EOG Common Stock on December 6, 1995
as reported on the New York Stock Exchange Composite Tape was $21 3/4.
14
As of November 1, 1995, there were approximately 270 record holders of
EOG's Common Stock, including individual participants in security position
listings. There are an estimated 5,100 beneficial owners of EOG's Common
Stock, including shares held in street name.
Following the initial public offering and sale of its Common Stock in
October 1989, EOG paid quarterly dividends of $0.025 per share beginning with
an initial dividend paid in January 1990 with respect to the fourth quarter of
1989. Beginning in January 1993 with respect to the fourth quarter of 1992,
EOG has paid quarterly dividends of $0.03 per share. The determination of the
amount of future cash dividends, if any, to be declared and paid will depend
upon, among other things, the financial condition, funds from operations,
level of exploration and development expenditure opportunities and future
business prospects of EOG.
Enron makes no representation as to the amount of dividends, if any, that
EOG will pay in the future. In any event, holders of the Exchangeable Notes
will not be entitled to receive any dividends that may be payable on the EOG
Common Stock until such time as Enron, if it so elects, delivers EOG Common
Stock at Maturity of the Exchangeable Notes and the record date for such
dividend occurs after such exchange. See "Description of the Exchangeable
Notes."
DESCRIPTION OF THE EXCHANGEABLE NOTES
The Exchangeable Notes are one series of debt securities to be issued
under an Indenture dated as of November 1, 1985, between Enron and Harris
Trust and Savings Bank, as trustee, as supplemented by a First Supplemental
Indenture dated as of December 1, 1995, between Enron and Harris Trust and
Savings Bank, as trustee (the "Trustee") (the Indenture dated as of November
1, 1985, as supplemented from time to time, the "Indenture"). All references
herein to "Indenture Securities" shall refer to debt securities issued under
the Indenture. The following summary of certain provisions of the Indenture
does not purport to be complete and is qualified in its entirety by reference
to the Indenture, a copy of which is filed as an exhibit to the Registration
Statement of which this Prospectus is a part. All capitalized terms have the
meanings specified in the Indenture.
GENERAL
The aggregate number of Exchangeable Notes to be issued will be
10,000,000, plus such additional number of Exchangeable Notes as may be issued
pursuant to the over-allotment option granted by Enron to the Underwriters
(see "Underwriting"). The Stated Maturity of the Exchangeable Notes is
, 1998. The Indenture does not limit the amount of Indenture
Securities which may be issued thereunder. The Exchangeable Notes will be
unsecured and will rank on a parity with all other unsecured and
unsubordinated indebtedness of Enron. The right of Enron, and hence the right
of creditors of Enron (including the holders of the Exchangeable Notes), to
participate in any distribution of assets of any subsidiary of Enron upon its
liquidation or reorganization will be subject to the prior claims of creditors
of such subsidiary, except to the extent that the claims of Enron itself as a
creditor of such subsidiary may be recognized.
Each Exchangeable Note, which will be issued with a principal amount of
$ , will bear interest at the rate of % of the principal amount per
annum (or $ per annum) from , or from the most recent
Interest Payment Date (as defined below) to which interest has been paid or
provided for until the principal amount thereof is exchanged at Maturity
pursuant to the terms of the Exchangeable Notes. Interest on the Exchangeable
Notes will be payable quarterly in arrears on ,
, and , commencing
, 1996, (each, an "Interest Payment Date"), to the persons in whose
names the Exchangeable Notes are registered at the close of business on the
, , , and
immediately preceding such Interest Payment Date; provided
that interest payable at Maturity is payable to the person to whom the
principal is payable. Interest on the Exchangeable Notes will be computed on
the basis of a 360-day year of twelve 30-day months. If an Interest Payment
Date falls on a day that is not a Business Day (as defined below) the interest
payment to be made on such Interest Payment Date will be made on the next
succeeding Business Day with the same force and effect as if made on such
Interest Payment Date, and no additional interest will accrue as a result of
such delayed payment.
15
At Maturity, the principal amount of each Exchangeable Note will be
mandatorily exchanged by Enron into a number of shares of EOG Common Stock at
the Exchange Rate (as defined below) or, at Enron's option with respect to
all, but not less than all, of the Exchangeable Notes, cash with an equal
value. Accordingly, Holders of the Exchangeable Notes will not necessarily
receive an amount equal to the principal amount thereof. The "Exchange Rate"
is equal to, subject to adjustment as a result of certain dilution events (see
"Dilution Adjustments" below), (a) if the Maturity Price (as defined below) of
EOG Common Stock is greater than or equal to $ per share of EOG Common
Stock (the "Threshold Appreciation Price"), shares of EOG Common Stock
per Exchangeable Note, (b) if the Maturity Price is less than the Threshold
Appreciation Price but is greater than the Initial Price, a fractional share
of EOG Common Stock per Exchangeable Note so that the value thereof
(determined at the Maturity Price) is equal to the Initial Price and (c) if
the Maturity Price is less than or equal to the Initial Price, one share of
EOG Common Stock per Exchangeable Note. No fractional shares of EOG Common
Stock will be issued at Maturity as provided under "Fractional Shares" below.
Notwithstanding the foregoing, Enron may, at its option, deliver cash at
Maturity in lieu of delivering shares of EOG Common Stock, in an amount equal
to the value of such number of shares of EOG Common Stock at the Maturity
Price. Such option, if exercised, must be exercised with respect to all of the
outstanding Exchangeable Notes. If Enron elects to deliver cash in lieu of
shares of EOG Common Stock upon the mandatory exchange of the Exchangeable
Notes, on or prior to seven Business Days preceding the Stated Maturity, Enron
will so notify the Trustee and publish a notice to that effect in a daily
newspaper of national circulation. If Enron elects to deliver shares of EOG
Common Stock, Holders of the Exchangeable Notes will be responsible for the
payment of any and all brokerage costs upon the Holder's subsequent sale of
such stock.
The "Maturity Price" is defined as the average Closing Price per share of
EOG Common Stock for the 20 Trading Days immediately prior to (but not
including) Maturity. The "Closing Price" of any security on any date of
determination means the closing sale price (or, if no closing price is
reported, the last reported sale price) of such security on the NYSE on such
date or, if such security is not listed for trading on the NYSE on any such
date, as reported in the composite transactions for the principal United
States securities exchange on which such security is so listed, or if such
security is not so listed on a United States national or regional securities
exchange, as reported by the National Association of Securities Dealers, Inc.
Automated Quotation System, or, if such security is not so reported, the last
quoted bid price for such security in the over-the-counter market as reported
by the National Quotation Bureau or similar organization, or, if such bid
price is not available, the market value of such security on such date as
determined by a nationally recognized independent investment banking firm
retained for this purpose by Enron. A "Trading Day" is defined as a Business
Day on which the security the Closing Price of which is being determined (A)
is not suspended from trading on any national or regional securities exchange
or association or over-the-counter market at the close of business and (B) has
traded at least once on the national or regional securities exchange or
association or over-the-counter market that is the primary market for the
trading of such security. "Business Day" means any day that is not a Saturday
or Sunday or a day on which the NYSE, banking institutions or trust companies
in The City of New York are authorized or obligated by law or executive order
to close.
The Indenture pursuant to which the Exchangeable Notes are issued
contains a covenant by Enron to the effect that should Enron exercise its
option to pay all outstanding Exchangeable Notes in cash, such cash must be
provided by the proceeds from a sale by Enron of its common stock. Such sale
of common stock by Enron must have occurred not more than 540 days prior to
the notice by Enron to Holders of Exchangeable Notes of its election to
deliver cash in lieu of EOG Common Stock.
16
For illustrative purposes only, the following chart shows the number of
shares of EOG Common Stock or the amount of cash that a Holder of Exchangeable
Notes would receive for each Exchangeable Note at various Maturity Prices. The
table assumes that there will be no adjustments to the Exchange Rate described
under "-- Dilution Adjustments" below. There can be no assurance that the
Maturity Price will be within the range set forth below. Given the Initial
Price of $ per Exchangeable Note and the Threshold Appreciation Price of
$ , a Holder of an Exchangeable Note would receive at Maturity the
following number of shares of EOG Common Stock or amount of cash (if Enron
elects to pay the Exchangeable Notes in cash):
MATURITY
PRICE NUMBER OF
OF EOG SHARES OF EOG
COMMON STOCK COMMON STOCK AMOUNT OF CASH
------------- ------------- ---------------
Interest on the Exchangeable Notes will be payable, and delivery of EOG
Common Stock (or, at the option of Enron, its cash equivalent) in exchange for
the Exchangeable Notes at Maturity will be made upon surrender of such
Exchangeable Notes, at the office or agency of Enron maintained for such
purposes, which will initially be the principal corporate trust office of the
Trustee, currently 311 West Monroe, 12th Floor, Chicago, Illinois 60609 or at
the Trustee's office maintained for such purpose in New York, New York,
provided that payment of interest may be made at the option of Enron by check
mailed to the persons in whose names the Exchangeable Notes are registered at
the close of business on each , ,
and .
The Exchangeable Notes will be transferable on the books of Enron at any
time and from time to time. No service charge will be made to the Holder for
any such transfer except for any tax or governmental charge incidental
thereto.
The Indenture does not contain any restriction on the ability of Enron to
sell, pledge or otherwise convey all or any portion of the EOG Common Stock
held by it, and no such shares of EOG Common Stock will be pledged or
otherwise held in escrow for use at Maturity of the Exchangeable Notes.
Consequently, in the event of a bankruptcy, insolvency or liquidation of
Enron, the EOG Common Stock, if any, owned by Enron will be subject to the
claims of the creditors of Enron. In addition, as described herein, Enron will
have the option, exercisable in its sole discretion, to satisfy its
obligations pursuant to the mandatory exchange for the principal amount of
each Exchangeable Note at Maturity by delivering to Holders of the
Exchangeable Notes either the specified number of shares of EOG Common Stock
or cash in an amount equal to the value of such number of shares at the
Maturity Price. In the event that Enron does sell, pledge or convey all or a
portion of the EOG Common Stock held by it, Enron may be more likely to
deliver cash in lieu of EOG Common Stock. As a result, there can be no
assurance that Enron will elect at Maturity to deliver EOG Common Stock or, if
it so elects, that it will use all or a portion of its current holdings of EOG
Common Stock to make such delivery. Holders of the Exchangeable Notes will not
be entitled to any rights with respect to the EOG Common Stock (including
without limitation voting rights and rights to receive any dividends or other
distributions in respect thereof) until such time, if any, as Enron shall have
delivered shares of EOG Common Stock to holders of the Exchangeable Notes at
Maturity thereof and the applicable record date, if any, for the exercise of
such rights occurs after such date.
DILUTION ADJUSTMENTS
The Exchange Rate is subject to adjustment if EOG shall (i) pay a stock
dividend or make a distribution with respect to EOG Common Stock in shares of
such stock, (ii) subdivide or split the outstanding shares of EOG Common
Stock, (iii) combine the outstanding shares of EOG Common Stock into a smaller
number of shares, (iv) issue by reclassification of shares of EOG Common Stock
any shares of common stock of EOG, (v) issue rights or warrants to all holders
of EOG Common Stock entitling them to subscribe for or purchase shares of EOG
Common Stock at a price
17
per share less than the market price of the EOG Common Stock (other than
rights to purchase EOG Common Stock pursuant to a plan for the reinvestment of
dividends or interest); or (vi) pay a dividend or make a distribution to all
holders of EOG Common Stock of evidences of indebtedness or other assets
(excluding any dividends or distributions referred to in clause (i) above or
any cash dividends other than any Extraordinary Cash Dividends (as defined
below) or issue to all holders of EOG Common Stock rights or warrants to
subscribe for or purchase any of its securities (other than those referred to
in clause (v) above). In the case of the events referred to in clauses (i),
(ii), (iii) and (iv) above, the Exchange Rate in effect immediately prior to
such event shall be adjusted so that the holder of any Exchangeable Note shall
thereafter be entitled to receive, upon mandatory exchange of the principal
amount of the Exchangeable Note at Maturity, the number of shares of EOG
Common Stock that such holder would have owned or been entitled to receive
immediately following any event described above had such Exchangeable Note
been exchanged immediately prior to such event on any record date with respect
thereto. In the case of the event referred to in clause (v) above, the
Exchange Rate shall be adjusted by multiplying the Exchange Rate in effect
immediately prior to the date of issuance of the rights or warrants referred
to in clause (v) above, by a fraction, the numerator of which shall be the
number of shares of EOG Common Stock outstanding on the date of issuance of
such rights or warrants, immediately prior to such issuance, plus the number
of additional shares of EOG Common Stock offered for subscription or purchase
pursuant to such rights or warrants, and the denominator of which shall be the
number of shares of EOG Common Stock outstanding on the date of issuance of
such rights or warrants, immediately prior to such issuance, plus the number
of additional shares of EOG Common Stock that the aggregate offering price of
the total number of shares of EOG Common Stock so offered for subscription or
purchase pursuant to such rights or warrants would purchase at the market
price (determined as the average Closing Price per share of EOG Common Stock
for the 20 Trading Days immediately prior to the date such rights or warrants
are issued), which shall be determined by multiplying such total number of
shares by the exercise price of such rights or warrants and dividing the
product so obtained by such market price. To the extent that shares of EOG
Common Stock are not delivered after the expiration of such rights or
warrants, the Exchange Rate shall be readjusted to the Exchange Rate which
would then be in effect had such adjustments for the issuance of such rights
or warrants been made upon the basis of delivery of only the number of shares
of EOG Common Stock actually delivered. In the case of the event referred to
in clause (vi) above, the Exchange Rate shall be adjusted by multiplying the
Exchange Rate in effect on the record date by a fraction, the numerator of
which shall be the market price per share of the EOG Common Stock on the
record date for the determination of stockholders entitled to receive the
dividend or distribution referred to in clause (vi) above (such market price
being determined as the average Closing Price per share of EOG Common Stock
for the 20 Trading Days immediately prior to such record date), and the
denominator of which shall be such market price per share of EOG Common Stock
less the fair market value (as determined by the Board of Directors of Enron,
whose determination shall be conclusive, and described in a resolution adopted
with respect thereto) as of such record date of the portion of the assets or
evidences of indebtedness so distributed or of such subscription rights or
warrants applicable to one share of EOG Common Stock. An "Extraordinary Cash
Dividend" means, with respect to any 365-day period, all cash dividends on the
EOG Common Stock during such period to the extent such dividends exceed on a
per share basis 10% of the average Closing Price of the EOG Common Stock over
such period (less any such dividends for which a prior adjustment to the
Exchange Rate was previously made). All adjustments to the Exchange Rate will
be calculated to the nearest 1/10,000th of a share of EOG Common Stock (or if
there is not a nearest 1/10,000th of a share to the next lower 1/10,000th of a
share). No adjustment in the Exchange Rate shall be required unless such
adjustment would require an increase or decrease of at least one percent
therein; PROVIDED, HOWEVER, that any adjustments which by reason of the
foregoing are not required to be made shall be carried forward and taken into
account in any subsequent adjustment.
In the event of (i) any consolidation or merger of EOG, or any surviving
entity or subsequent surviving entity of EOG (an "EOG Successor"), with or
into another entity (other than a merger or consolidation in which EOG is the
continuing corporation and in which the EOG Common Stock outstanding
immediately prior to the merger or consolidation is not exchanged for cash,
securities or
18
other property of EOG or another Person), (ii) any sale, transfer, lease or
conveyance to another Person of the property of EOG or any EOG Successor as an
entirety or substantially as an entirety, (iii) any statutory exchange of
securities of EOG, or any EOG Successor with another Person (other than in
connection with a merger or acquisition); or (iv) any liquidation, dissolution
or winding up of EOG or any EOG Successor (any such event being a
"Reorganization Event"), the Exchange Rate used to determine the amount
payable upon exchange at Maturity for each Exchangeable Note will be adjusted
to provide that each Holder of Exchangeable Notes will receive at Maturity
cash in an amount equal to (a) if the Transaction Value (as defined below) is
greater than or equal to the Threshold Appreciation Price, multiplied by
the Transaction Value, (b) if the Transaction Value is less than the Threshold
Appreciation Price but greater than the Initial Price, the Initial Price and
(c) if the Transaction Value is less than or equal to the Initial Price, the
Transaction Value. "Transaction Value" means (i) for any cash received in any
such Reorganization Event, the amount of cash received per share of EOG Common
Stock, (ii) for any property other than cash or securities received in any
such Reorganization Event, an amount equal to the market value at Maturity of
such property received per share of EOG Common Stock as determined by a
nationally recognized independent investment banking firm retained for this
purpose by Enron and (iii) for any securities received in any such
Reorganization Event, an amount equal to the average Closing Price per share
of such securities for the 20 Trading Days immediately prior to Maturity
multiplied by the number of such securities received for each share of EOG
Common Stock.
Notwithstanding the foregoing, in lieu of delivering cash as provided
above, Enron may at its option deliver an equivalent value of securities or
other property received in such Reorganization Event, determined in accordance
with clause (ii) or (iii) above, as applicable. If Enron elects to deliver
securities or other property, holders of the Exchangeable Notes will be
responsible for the payment of any and all brokerage and other transaction
costs upon the sale of such securities or other property. The kind and amount
of securities into which the Exchangeable Notes shall be exchangeable after
consummation of such transaction shall be subject to adjustment as described
in the immediately preceding paragraph following the date of consummation of
such transaction.
Enron is required, within ten Business Days following the occurrence of
an event that requires an adjustment to the Exchange Rate (or if Enron is not
aware of such occurrence, as soon as practicable after becoming so aware), to
provide written notice to the Trustee for distribution to all Holders of
Exchangeable Notes of the occurrence of such event and a statement in
reasonable detail setting forth the method by which the adjustment to the
Exchange Rate was determined and setting forth the revised Exchange Rate.
FRACTIONAL SHARES
No fractional shares of EOG Common Stock will be issued if Enron
exchanges the Exchangeable Notes for shares of EOG Common Stock. If more than
one Exchangeable Note shall be surrendered for exchange at one time by the
same holder, the number of full shares of EOG Common Stock which shall be
delivered upon exchange shall be computed on the basis of the aggregate number
of Exchangeable Notes so surrendered at Maturity. In lieu of any fractional
share otherwise issuable in respect of all Exchangeable Notes of any Holder
which are exchanged at Maturity, such Holder shall be entitled to receive an
amount in cash equal to the value of such fractional share at the Maturity
Price.
REDEMPTION AND DEFEASANCE
The Exchangeable Notes are not subject to redemption or defeasance prior
to Maturity and do not contain any sinking fund or other mandatory redemption
provisions.
LIMITATIONS ON MORTGAGES AND LIENS
The Indenture provides that so long as any of the Indenture Securities
issued under the Indenture (including the Exchangeable Notes) are outstanding,
Enron will not, and will not permit any Subsidiary (as defined in the
Indenture and herein) to, pledge, mortgage or hypothecate, or permit to exist,
except in favor of Enron or any Subsidiary, any mortgage, pledge or other lien
upon, any Principal Property (as defined in the Indenture and herein) at any
time owned by it, to secure any
19
indebtedness (as defined in the Indenture), unless effective provision is made
whereby outstanding Indenture Securities (including the Exchangeable Notes)
will be equally and ratably secured with any and all such indebtedness and
with any other indebtedness similarly entitled to be equally and ratably
secured. This restriction does not apply to prevent the creation or existence
of: (a) mortgages, pledges, liens or encumbrances on any property held or used
by Enron or a Subsidiary in connection with the exploration for, development
of or production of, oil, gas, natural gas (including liquefied gas and
storage gas), other hydrocarbons, helium, coal, metals, minerals, steam,
timber, geothermal or other natural resources or synthetic fuels, such
properties to include, but not be limited to, Enron's or a Subsidiary's
interest in any mineral fee interests, oil, gas or other mineral leases,
royalty, overriding royalty or net profits interests, production payments and
other similar interests, wellhead production equipment, tanks, field gathering
lines, leasehold or field separation and processing facilities, compression
facilities and other similar personal property and fixtures; (b) mortgages,
pledges, liens or encumbrances on oil, gas, natural gas (including liquefied
gas and storage gas), other hydrocarbons, helium, coal, metals, minerals,
steam, timber, geothermal or other natural resources or synthetic fuels
produced or recovered from any property, an interest in which is owned or
leased by Enron or a Subsidiary; (c) mortgages, pledges, liens or encumbrances
(or certain extensions, renewals or refundings thereof) upon any property
acquired before or after the date of the Indenture, created at the time of
acquisition or within one year thereafter to secure all or a portion of the
purchase price thereof, or existing thereon at the date of acquisition,
whether or not assumed by Enron or a Subsidiary, provided that every such
mortgage, pledge, lien or encumbrance applies only to the property so acquired
and fixed improvements thereon; (d) mortgages, pledges, liens or encumbrances
upon any property acquired before or after the date of the Indenture by any
corporation that is or becomes a Subsidiary after the date of the Indenture
("Acquired Entity"), provided that every such mortgage, pledge, lien or
encumbrance (1) shall either (i) exist prior to the time the Acquired Entity
becomes a Subsidiary or (ii) be created at the time the Acquired Entity
becomes a Subsidiary or within one year thereafter to secure all or a portion
of the acquisition price thereof and (2) shall only apply to those properties
owned by the Acquired Entity at the time it becomes a Subsidiary or thereafter
acquired by it from sources other than Enron or any other Subsidiary; (e)
pledges of current assets, in the ordinary course of business, to secure
current liabilities; (f) deposits to secure public or statutory obligations;
(g) liens to secure indebtedness other than Funded Debt (as defined in the
Indenture and herein); (h) mortgages, pledges, liens or encumbrances upon any
office, data processing or transportation equipment; (i) mortgages, pledges,
liens or encumbrances created or assumed by Enron or a Subsidiary in
connection with the issuance of debt securities the interest on which is
excludable from gross income of the holder of such security pursuant to the
Internal Revenue Code of 1986, as amended, for the purpose of financing the
acquisition or construction of property to be used by Enron or a Subsidiary;
(j) pledges or assignments of accounts receivable or conditional sales
contracts or chattel mortgages and evidences of indebtedness secured thereby
received in connection with the sale by Enron or a Subsidiary of goods or
merchandise to customers; or (k) certain other liens or encumbrances.
Notwithstanding the foregoing, Enron or a Subsidiary may issue, assume or
guarantee indebtedness secured by a mortgage which would otherwise be subject
to the foregoing restrictions in an aggregate amount which, together with all
other indebtedness of Enron or a Subsidiary secured by a mortgage which (if
originally issued, assumed or guaranteed at such time) would otherwise be
subject to the foregoing restrictions (not including secured indebtedness
permitted under the foregoing exceptions), does not at the time exceed 10% of
the Consolidated Net Tangible Assets (total assets less (a) total current
liabilities, excluding indebtedness due within 12 months, and (b) goodwill,
patents and trademarks) of Enron, as shown on the audited consolidated
financial statements of Enron as of the end of the fiscal year preceding the
date of determination.
The holders of at least 50% in principal amount of the outstanding
Indenture Securities under the Indenture (including the Exchangeable Notes)
may waive compliance by Enron with the covenant described above (and certain
other covenants of Enron).
The Indenture defines the term "Subsidiary" to mean a corporation all of
the voting shares (that is, shares entitled to vote for the election of
directors, but excluding shares entitled so to vote only
20
upon the happening of some contingency unless such contingency shall have
occurred) of which shall be owned by Enron or by one or more Subsidiaries or
by Enron and one or more Subsidiaries. The term "Principal Property" is
defined to mean any oil or gas pipeline, gas processing plant or chemical
plant located in the United States, except any such property, pipeline or
plant that in the opinion of the Board of Directors of Enron is not of
material importance to the total business conducted by Enron and its
Subsidiaries. "Principal Property" does not include any oil or gas property or
the production or any proceeds of production from an oil or gas producing
property or the production or any proceeds of production of gas processing
plants or oil or gas or petroleum products in any pipeline.
The term "indebtedness", as applied to Enron or any Subsidiary, is
defined to mean bonds, debentures, notes and other instruments representing
obligations created or assumed by any such corporation for the repayment of
money borrowed (other than unamortized debt discount or premium). All
indebtedness secured by a lien upon property owned by Enron or any Subsidiary
and upon which indebtedness any such corporation customarily pays interest,
even though such corporation has not assumed or become liable for the payment
of such indebtedness, is also deemed to be indebtedness of any such
corporation. All indebtedness for money borrowed incurred by other persons
which is directly guaranteed as to payment of principal by Enron or any
Subsidiary is for all purposes of the Indenture deemed to be indebtedness of
any such corporation, but no other contingent obligation of any such
corporation in respect to indebtedness incurred by other persons is for any
purpose deemed indebtedness of such corporation. Indebtedness of Enron or any
Subsidiary does not include (i) amounts which are payable only out of all or a
portion of the oil, gas, natural gas, helium, coal, metals, minerals, steam,
timber or other natural resources produced, derived or extracted from
properties owned or developed by such corporation; (ii) any amount
representing capitalized lease obligations; (iii) any indebtedness incurred to
finance oil, gas, natural gas, helium, coal, metals, minerals, steam, timber,
hydrocarbons or geothermal or other natural resources or synthetic fuel
exploration or development, payable, with respect to principal and interest,
solely out of the proceeds of oil, gas, natural gas, helium, coal, metals,
minerals, steam, timber, hydrocarbons or geothermal or other natural resources
or synthetic fuel to be produced, sold and/or delivered by Enron or any
Subsidiary; (iv) indirect guarantees or other contingent obligations in
connection with the indebtedness of others, including agreements, contingent
or otherwise, with such other persons or with third persons with respect to,
or to permit or ensure the payment of, obligations of such other persons,
including without limitation, agreements to purchase or repurchase obligations
of such other persons, agreements to advance or supply funds to or to invest
in such other persons or agreements to pay for property, products or services
of such other persons (whether or not conferred, delivered or rendered) and
any demand charge, throughput, take-or-pay, keep-well, make-whole, cash
deficiency, maintenance of working capital or earnings or similar agreements;
and (v) any guarantees with respect to lease or other similar periodic
payments to be made by other persons.
The term "Funded Debt" as applied to any corporation means all
indebtedness incurred, created, assumed or guaranteed by such corporation, or
upon which it customarily pays interest charges, which matures, or is
renewable by such corporation to a date, more than one year after the date as
of which Funded Debt is being determined; provided, however, that the term
"Funded Debt" shall not include (i) indebtedness incurred in the ordinary
course of business representing borrowings, regardless of when payable, of
such corporation from time to time against, but not in excess of the face
amount of, its installment accounts receivable for the sale of appliances and
equipment sold in the regular course of business or (ii) advances for
construction and security deposits received by such corporation in the
ordinary course of business.
The foregoing limitations on mortgages, pledges and liens are intended to
limit other creditors of Enron from obtaining preference or priority over
holders of the Indenture Securities issued under the Indenture, but are not
intended to prevent other creditors from sharing equally and ratably and
without preference ("pari passu") over the holders of such Indenture
Securities. While such limitations on mortgages and liens do provide
protection to the holders of the Indenture Securities, there are a number of
exceptions to such restrictions which could result in certain assets of Enron
21
and its Subsidiaries being encumbered without equally and ratably securing the
Indenture Securities issued under the Indenture. Specifically, the
restrictions apply only to pledges, mortgages or liens upon "Principal
Property" (as defined in the Indenture and herein) to secure any
"indebtedness" (as defined in the Indenture and herein), unless effective
provision is made whereby outstanding Securities will be equally and ratably
secured with any such indebtedness and with any other indebtedness similarly
entitled to be equally and ratably secured. There are certain exceptions to
the definition of "indebtedness," which are enumerated in the Indenture and
herein. In addition, the restrictions do not apply to prevent the creation or
existence of mortgages, pledges, liens or encumbrances on certain types of
properties or pursuant to certain types of transactions, all as enumerated in
the Indenture and above. Also, up to 10% of Consolidated Net Tangible Assets
(as defined in the Indenture and herein) is not subject to the mortgage and
lien limitations contained in the Indenture.
MODIFICATION OF THE INDENTURE
With certain exceptions, the Indenture provides that, with the consent of
the holders of not less than 50% in principal amount of all outstanding
Indenture Securities (including, where applicable, the Exchangeable Notes)
affected thereby, Enron and the Trustee may enter into a supplemental
indenture for the purpose of adding to, changing or eliminating any of the
provisions of the Indenture or of modifying in any manner the rights of the
holders of Indenture Securities under the Indenture. Notwithstanding the
foregoing, the consent of the holder of each outstanding Indenture Security
affected thereby will be required to: (a) change the Stated Maturity (as
defined in the Indenture) of the principal of, or any installment of principal
of or interest on, any Indenture Security, or reduce the principal amount
thereof or the rate of interest thereon or any premium payable upon the
redemption thereof, or change any Place of Payment (as defined in the
Indenture) where, or change the coin or currency in which, any Indenture
Security or any premium or the interest thereon is payable, or impair the
right to institute suit for the enforcement of any such payment on or after
the Stated Maturity thereof (or, in the case of redemption, on or after the
Redemption Date, as defined in the Indenture) or change the terms under which
any Exchangeable Notes are exchangeable; (b) reduce the percentage in
principal amount of the outstanding Indenture Securities of any series, the
consent of whose holders is required for any supplemental indenture or for any
waiver provided for in the Indenture; or (c) with certain exceptions, modify
any of the provisions of the sections of the Indenture which concern waivers
of past defaults, waivers of certain covenants or consent to supplemental
indentures, except to increase the percentage of principal amount of Indenture
Securities of any series, the holders of which are required to effect such
waiver or consent, or to provide that certain other provisions of the
Indenture cannot be modified or waived without the consent of the holder of
each outstanding Indenture Security affected thereby. The Indenture provides
that a supplemental indenture which changes or eliminates any covenant or
other provision of the Indenture which has expressly been included solely for
the benefit of one or more particular series of Indenture Securities, or which
modifies the rights of the holders of Indenture Securities of such series with
respect to such covenant or other provision, shall be deemed not to affect the
rights under the Indenture of the holders of Indenture Securities of any other
series.
EVENTS OF DEFAULT AND RIGHTS UPON DEFAULT
Under the Indenture, the term "Event of Default" with respect to any
series of Indenture Securities, means any one of the following events which
shall have occurred and is continuing: (a) default in the payment of any
interest upon any Indenture Security of that series when it becomes due and
payable or default in the payment of any mandatory sinking fund payment
provided for by the terms of any series of Indenture Securities, and
continuance of such default for a period of 30 days; (b) default in the
payment of the principal of (or premium, if any, on) any Indenture Security of
that series at its maturity; (c) default in the performance, or breach, of any
covenant or warranty of Enron in the Indenture (other than a covenant or
warranty a default in the performance of which or the breach of which is
otherwise specifically dealt with in the Indenture or which has been expressly
included in the Indenture solely for the benefit of one or more series of
Indenture Securities other than that series), and continuance of such default
or breach for 60 days after there has been given to
22
Enron by the Trustee, or to Enron and the Trustee by the holders of at least
25% in principal amount of all outstanding Indenture Securities, a written
notice specifying such default or breach and requiring it to be remedied and
stating that such notice is a "Notice of Default" under the Indenture; or (d)
certain events involving Enron in bankruptcy, receivership or other insolvency
proceedings or an assignment for the benefit of creditors.
If an Event of Default described in clause (a) or (b) in the foregoing
paragraph has occurred and is continuing with respect to Indenture Securities
of any series, the Indenture provides that the Trustee or the holders of not
less than 25% in principal amount of the outstanding Indenture Securities of
that series may declare the principal amount of all of the Indenture
Securities of that series to be due and payable immediately, and upon any such
declaration such principal amount shall become immediately due and payable. If
an Event of Default described in clause (c) or (d) of the foregoing paragraph
occurs and is continuing, the Trustee or the holders of not less than 25% in
principal amount of all of the Indenture Securities then outstanding may
declare the principal amount of all of the Indenture Securities to be due and
payable immediately, and upon any such declaration such principal amount shall
become immediately due and payable.
A default under other indebtedness of Enron is not an Event of Default
under the Indenture, and an Event of Default under one series of Indenture
Securities will not necessarily be an Event of Default under another series.
At any time after such a declaration of acceleration with respect to
Indenture Securities of any series (or of all series, as the case may be) has
been made and before judgment or decree for payment of the money due has been
obtained by the Trustee, the holders of a majority in principal amount of the
outstanding Indenture Securities of that series (or of all series, as the case
may be) may rescind and annul such declaration and its consequences, if,
subject to certain conditions, all Events of Default with respect to Indenture
Securities of that series (or of all series, as the case may be), other than
the non-payment of the principal of the Indenture Securities due solely by such
declaration of acceleration, have been cured or waived and all payments due
(other than by acceleration) have been paid or deposited with the Trustee.
With certain exceptions, the holders of not less than a majority in principal
amount of the outstanding Indenture Securities of any series, on behalf of the
holders of all the Indenture Securities of such series, may waive any past
default described in clause (a) or (b) of the first paragraph of this heading
"Events of Default and Rights Upon Default" (or, in the case of a default
described in clause (c) or (d) of such paragraph, the holders of a majority in
principal amount of all outstanding Indenture Securities may waive any such
past default), and its consequences, except a default (a) in the payment of
the principal of (or premium, if any) or interest on any Indenture Security,
or (b) in respect of a covenant or provision of the Indenture which under the
Indenture cannot be modified or amended without the consent of the holder of
each outstanding Indenture Security of such series affected.
The holders of not less than a majority in principal amount of the
Indenture Securities of any series at the time outstanding are empowered under
the terms of the Indenture, subject to certain limitations, to direct the
time, method and place of conducting any proceeding for any remedy available
to the Trustee or exercising any trust or power conferred on the Trustee.
The Indenture further provides that no holder of an Indenture Security of
any series may enforce the Indenture except in the case of failure by the
Trustee to act for 60 days after notice of a continuing Event of Default with
respect to the Indenture Securities of that series and after request by the
holders of not less than 25% in principal amount of the outstanding Indenture
Securities of such series and the offer to the Trustee of reasonable
indemnity, but this provision will not prevent a holder of any Indenture
Security from enforcing the payment of the principal of, and interest on, such
holder's Indenture Security.
The Indenture requires that Enron deliver to the Trustee, within 120 days
after the end of each fiscal year, an Officer's Certificate, stating whether
to the best knowledge of the signers thereof, Enron is in default in the
performance and observance of certain of the terms of the Indenture and, if
so, specifying each such default and the nature and status thereof of which
the signers may have knowledge.
23
CONCERNING THE TRUSTEE
Harris Trust and Savings Bank is the Trustee under the Indenture. Such
bank also acts as a depository of funds for, makes loans to, and performs
other services for, Enron in the normal course of business, including acting
as trustee under other indentures of Enron.
The Indenture contains the provisions required by the Trust Indenture Act
of 1939 with reference to the disqualification of the Trustee if it shall have
or acquire any "conflicting interest", as therein defined. The Indenture also
contains certain limitations on the right of the Trustee, as a creditor of
Enron, to obtain payment of claims in certain cases, or to realize on certain
property received by it in respect of any such claims, as security or
otherwise.
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following is a summary of certain U.S. federal income tax
consequences that may be relevant to a citizen or resident of the United
States, a corporation, partnership or other entity created or organized under
the laws of the United States, or an estate or trust the income of which is
subject to U.S. federal income taxation regardless of its source (any of the
foregoing, a "U.S. Person") who is the beneficial owner of Exchangeable Notes
(a "U.S. Holder"). All references to "holders" (including U.S. Holders) are to
beneficial owners of the Exchangeable Notes. This summary, which was prepared
by Vinson & Elkins L.L.P., is based on current U.S. federal income tax law and
is for general information only.
This summary deals only with holders who are initial holders of the
Exchangeable Notes and who will hold the Exchangeable Notes as capital assets.
It does not address tax considerations applicable to investors that may be
subject to special U.S. federal income tax treatment, such as dealers in
securities or persons holding the Exchangeable Notes as a position in a
"straddle" for U.S. federal income tax purposes or as part of a "synthetic
security" or other integrated investment, and does not address the
consequences under state, local or foreign law.
No statutory, judicial or administrative authority directly addresses the
characterization of the Exchangeable Notes or instruments similar to the
Exchangeable Notes for U.S. federal income tax purposes. As a result,
significant aspects of the U.S. federal income tax consequences of an
investment in the Exchangeable Notes are not certain. No ruling is being
requested from the Internal Revenue Service (the "IRS") with respect to the
Exchangeable Notes and no assurance can be given that the IRS will agree with
the characterization and tax treatment of the Exchangeable Notes described
herein. ACCORDINGLY, A PROSPECTIVE INVESTOR (INCLUDING A TAX-EXEMPT INVESTOR)
IN THE EXCHANGEABLE NOTES SHOULD CONSULT ITS TAX ADVISOR IN DETERMINING THE
TAX CONSEQUENCES OF AN INVESTMENT IN THE EXCHANGEABLE NOTES, INCLUDING THE
APPLICATION OF STATE, LOCAL OR OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF
CHANGES IN FEDERAL OR OTHER TAX LAWS.
Pursuant to the terms of the Indenture, Enron and all holders of the
Exchangeable Notes will agree to treat an Exchangeable Note as a unit (the
"Unit") consisting of (i) an exchange note ("Exchange Note") which is a debt
obligation with a fixed principal amount unconditionally payable at Maturity
equal to the principal amount of the Exchangeable Note, bearing interest at
the stated interest rate on the Exchangeable Note, and (ii) a forward purchase
contract (the "Purchase Contract") pursuant to which the holder agrees to use
the principal payment due on the Exchange Note to purchase at Maturity the EOG
Common Stock which the holder is entitled to receive at that time (subject to
Enron's right to deliver cash in lieu of EOG Common Stock). The Indenture will
require that a U.S. Holder include currently in income payments denominated as
interest that are made with respect to the Exchangeable Notes, in accordance
with such holder's method of accounting, and the amount of OID, if any,
attributable to the Exchangeable Notes.
Pursuant to the agreement to treat the Exchangeable Notes as a Unit, a
holder will be required to allocate the purchase price of the Exchangeable
Note between the two components of the Unit (the Exchange Note and the
Purchase Contract) on the basis of their relative fair market values. The
purchase price so allocated will generally constitute the tax basis for each
component. Pursuant to the terms of the Indenture, Enron and the holders agree
to allocate the entire purchase price of an
24
Exchangeable Note to the Exchange Note unless the stated interest on the
Exchangeable Note represents a yield that is lower than Enron's normal cost of
issuing debt with a similar term to the Exchangeable Note ("Enron's Mid-Term
Borrowing Rate"). If the stated interest on the Exchangeable Note represents a
yield that is lower than Enron's Mid-Term Borrowing Rate of percent,
Enron and the holders agree to allocate to the Exchange Note an amount, less
than the principal amount of the Exchange Note, calculated by discounting the
cash flows relating to the Exchange Note at a rate equal to Enron's Mid-Term
Borrowing Rate, and to allocate to the Purchase Contract the remainder of the
purchase price of the Exchangeable Note.
If the amount allocated to the Exchange Note (its deemed issue price) is
less than the stated principal amount of the Exchangeable Note, the Exchange
Note will be treated as having OID. In that event, a U.S. Holder will be
required to include in income OID as it accrues, in accordance with a
constant-yield method, in an aggregate amount equal to the difference between
the stated principal amount of the Exchangeable Note and the deemed issue
price of the Exchange Note. However, if the amount of OID relating to an
Exchange Note is less than three-fourths of one percent of the stated
principal amount of the Exchangeable Note, no amount of OID will be deemed to
exist with respect to the Exchange Note. A U.S. Holder's tax basis in the
Exchange Note will increase over its term by the amount of OID included in
such holder's income with respect to the Exchangeable Note.
Upon the sale or other disposition of an Exchangeable Note, a U.S. Holder
generally will be required to allocate the amount realized between the two
components of the Exchangeable Note on the basis of their then relative fair
market values. A U.S. Holder will recognize gain or loss with respect to each
component equal to the difference between the amount realized on the sale or
other disposition for each such component and the U.S. Holder's tax basis in
such component. Such gain or loss generally will be long-term capital gain or
loss if the U.S. Holder has held the Exchangeable Note for more than a year at
the time of disposition.
At Maturity, pursuant to the agreement to treat the Exchangeable Note as
a Unit, on the repayment of the Exchange Note a U.S. Holder will recognize
capital gain or loss which will be long-term capital gain or loss unless
Maturity occurs within one year of issuance of the Exchangeable Note (as a
result of acceleration or otherwise) equal to any difference between its tax
basis and the principal amount of the Exchange Note. If Enron delivers EOG
Common Stock at Maturity, a U.S. Holder will recognize no additional gain or
loss on the exchange, pursuant to the Purchase Contract, of the principal
payment due on the Exchange Note for the EOG Common Stock. However, a U.S.
Holder will recognize additional capital gain or loss, which should be
short-term capital gain or loss, equal to the difference between the cash
received in lieu of fractional shares and the portion of the principal amount
of the Exchange Note allocable to fractional shares. A U.S. Holder will have a
tax basis in such shares of EOG Common Stock equal to the principal amount of
the Exchange Note less the amount of the portion of the principal amount of
the Exchange Note allocable to any fractional shares. The U.S. Holder will
have a holding period for the EOG Common Stock that begins on the day after
the Maturity date, and will realize short- or long-term capital gain or loss
upon the subsequent sale or disposition of such stock. Alternatively, at
Maturity, if Enron pays the Exchangeable Note in cash, a U.S. Holder will have
additional gain or loss (which might be ordinary income or loss rather than
capital gain or loss) equal to the difference between the principal amount of
the Exchangeable Note and the amount of cash received from Enron.
Due to the absence of authority as to the proper characterization of the
Exchangeable Note, no assurance can be given that the IRS will accept or that
a court will uphold the characterization agreed to in the Indenture or the tax
treatment described above. Proposed Treasury regulations with respect to
"contingent payment" debt instruments (the "Proposed Regulations") would
provide for a different tax result under some circumstances for instruments
having characteristics similar to the Exchangeable Notes, but the Proposed
Regulations would be effective only for instruments issued 60 days or more
after their publication as final regulations. Under the Proposed Regulations,
the amount of interest included in a holder's taxable income for any year
would generally be determined by projecting the amounts of contingent payments
(which might include the value of the EOG Common Stock to be delivered at
Maturity) and the yield on the instrument. Taxable interest income would be
measured with reference to the projected yield, which might be less than or
greater than
25
the stated interest rate under the instrument. In the event that the amount of
an actual contingent payment differed from the projected amount of that
payment, the difference would generally increase or reduce taxable interest
income, or create a loss. Because of their prospective effective date, the
Proposed Regulations, if finalized in their current form, would not apply to
the Exchangeable Notes.
Even in the absence of regulations applicable to the Exchangeable Notes,
the Exchangeable Notes may be characterized under current law in a manner that
results in tax consequences different from those reflected in the agreement
pursuant to the Indenture and as described above. Under alternative
characterizations of the Exchangeable Notes, it is possible, for example, that
(i) a U.S. Holder may be taxed upon the receipt of EOG Common Stock with a
value in excess of the principal amount of the Exchange Note, rather than upon
the sale of such stock, (ii) any gain recognized at Maturity (whether a U.S.
Holder received EOG Common Stock or cash) may be treated as ordinary income
rather than capital gain, (iii) all or part of the interest income on the
Exchange Note may be treated as nontaxable, increasing the gain (or decreasing
the loss) at Maturity or upon disposition of the Exchangeable Note (or
disposition of the EOG Common Stock) or (iv) if the stated interest rate
exceeds Enron's Mid-Term Borrowing Rate, the Exchange Notes could be
considered as issued at a premium which, if amortized, would reduce the amount
of interest income currently includible in income by a holder and increase the
taxable gain (or decrease the loss) realized at Maturity or upon disposition
of the Exchangeable Notes (or disposition of the EOG Common Stock).
The Revenue Reconciliation Act of 1993 added Section 1258 to the Code,
which may require certain holders of the Exchangeable Notes who have entered
into hedging transactions or offsetting positions with respect to the
Exchangeable Notes to recognize ordinary income rather than capital gain upon
the disposition of the Exchangeable Notes. Holders should consult their tax
advisors regarding the applicability of this provision to an investment in the
Exchangeable Notes.
NON-UNITED STATES PERSON
In the case of a holder of the Exchangeable Notes that is not a U.S.
Person, payments made with respect to the Exchangeable Notes should not be
subject to U.S. withholding tax; PROVIDED that such holder complies with
applicable certification requirements. Any capital gain realized upon the sale
or other disposition of the Exchangeable Notes by a holder that is not a U.S.
Person will generally not be subject to U.S. federal income tax if (i) such
gain is not effectively connected with a U.S. trade or business of such holder
and (ii) in the case of an individual, such individual is not present in the
United States for 183 days or more in the taxable year of the sale or other
disposition and either such individual does not have a "tax home" in the
United States or the gain is not attributable to a fixed place of business
maintained by such individual in the United States.
BACKUP WITHHOLDING AND INFORMATION REPORTING
A holder of the Exchangeable Notes may be subject to information
reporting requirements and to backup withholding at a rate of 31 percent of
certain amounts paid to the holder unless such holder provides proof of an
applicable exemption or a correct taxpayer identification number, and
otherwise complies with applicable requirements of the backup withholding
rules.
26
UNDERWRITING
Subject to the terms and conditions of the Underwriting Agreement, Enron
has agreed to sell to each of the Underwriters named below (the
"Underwriters"), and each of such Underwriters, for whom Goldman, Sachs & Co.
are acting as representatives, has severally agreed to purchase from Enron,
the respective number of Exchangeable Notes set forth opposite its name below:
NUMBER OF
EXCHANGEABLE
UNDERWRITER NOTES
- ------------------------------------- ------------
Goldman, Sachs & Co. ................
Merrill Lynch, Pierce, Fenner & Smith
Incorporated ............
Salomon Brothers Inc ................
------------
Total ..................... 10,000,000
============
Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of the Exchangeable Notes
offered hereby, if any are taken.
The Underwriters propose to offer the Exchangeable Notes in part directly
to the public at the initial public offering price set forth on the cover page
of this Prospectus, and in part to certain securities dealers at such price
less a concession of $ per Exchangeable Note. The Underwriters may allow,
and each of such dealers may reallow, a concession not exceeding $ per
Exchangeable Note to certain dealers and brokers. After the Exchangeable Notes
are released for sale to the public, the offering price and the other selling
terms may from time to time be varied by the representatives.
Enron has granted the Underwriters an option exercisable for 30 days
after the date of this Prospectus to purchase up to 1,000,000 additional
Exchangeable Notes solely to cover over-allotments, if any. If the
Underwriters exercise their over-allotment option, the Underwriters have
severally agreed, subject to certain conditions, to purchase approximately the
same percentage thereof that the number of Exchangeable Notes to be purchased
by each of them, as shown in the foregoing table, bears to the 10,000,000
Exchangeable Notes offered.
Enron, EOG and EOG's Chief Executive Officer have agreed that during the
period beginning from the date of this Prospectus and continuing to and
including the date 270 days after the date of this Prospectus, subject to
certain exceptions set forth in the Underwriting Agreement, they will not
offer, sell, contract to sell or otherwise dispose of any EOG Common Stock,
any securities of EOG which are substantially similar to shares of EOG Common
Stock or any securities which are convertible into or exchangeable for EOG
Common Stock or such substantially similar securities without the prior
written consent of Goldman, Sachs & Co., except for the shares of EOG Common
Stock offered in connection with the concurrent Stock Offering.
The Exchangeable Notes have been approved for listing on the NYSE, subject
to official notice of issuance. The EOG Common Stock (including the shares of
EOG Common Stock which may be received by a holder of Exchangeable Notes at
Maturity) is listed on the NYSE.
The Underwriters and/or their affiliates have provided investment banking
and financial advisory services to Enron, its subsidiaries or affiliates in
the past, for which they have received customary compensation and expense
reimbursement, and may do so again in the future.
Enron and EOG have agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act, or to
contribute to payments the Underwriters may be required to make in respect
thereof.
27
VALIDITY OF THE EXCHANGEABLE NOTES
The validity of the Exchangeable Notes will be passed upon for Enron by
James V. Derrick, Jr., Senior Vice President and General Counsel of Enron. Mr.
Derrick owns substantially less than 1% of the outstanding shares of Common
Stock of Enron. Certain matters will be passed upon for Enron by Vinson &
Elkins L.L.P. The validity of the Exchangeable Notes will be passed upon for
the Underwriters by Bracewell & Patterson, L.L.P. Bracewell & Patterson,
L.L.P. currently provides services to Enron and certain of its subsidiaries
and affiliates as outside counsel on matters unrelated to the issuance of the
Exchangeable Notes.
EXPERTS
The consolidated financial statements and schedules included in Enron's
Annual Report on Form 10-K for the year ended December 31, 1994, incorporated
by reference in this Prospectus, have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their reports with respect
thereto and are incorporated by reference herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
reports.
The letter report of DeGolyer and MacNaughton, independent petroleum
consultants, included as an exhibit to Enron's Annual Report on Form 10-K for
the year ended December 31, 1994, and the estimates from the reports of that
firm appearing in such Annual Report, are incorporated by reference herein on
the authority of said firm as experts in petroleum engineering and in giving
such reports.
28
******************************************************************************
* INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR *
* AMENDMENT. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES *
* HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE *
* SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED *
* PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. *
* THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE *
* SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF *
* THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION *
* OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION *
* UNDER THE SECURITIES LAWS OF ANY SUCH STATE. *
******************************************************************************
SUBJECT TO COMPLETION, DATED DECEMBER 7, 1995
APPENDIX A
ENRON OIL & GAS COMPANY
COMMON STOCK
(PAR VALUE $.01 PER SHARE)
------------------------
This Prospectus relates to up to 11,000,000 shares of common stock, par
value $.01 per share (the "Common Stock"), of Enron Oil & Gas Company (the
"Company"), which may be delivered by Enron Corp. upon mandatory exchange of
the % Exchangeable Notes due , 1998 (the "Exchangeable Notes")
of Enron Corp., subject to Enron Corp.'s right to deliver cash in lieu of such
shares. This Prospectus is Appendix A to a prospectus of Enron Corp. covering
the sale of the Exchangeable Notes (the "Exchangeable Notes Prospectus"). The
Company will not receive any of the proceeds from the sale of the Exchangeable
Notes or the delivery of shares of Common Stock upon mandatory exchange of the
Exchangeable Notes at maturity.
Enron Corp. has granted the underwriters of the Exchangeable Notes a
30-day option to purchase up to an additional 1,000,000 Exchangeable Notes at
the initial offering price per Exchangeable Note, less the underwriting
discount, which may be exchangeable at their maturity for additional shares of
Common Stock. Such option has been granted solely to cover over-allotments, if
any.
Concurrently with the offering of the Exchangeable Notes made by the
Exchangeable Notes Prospectus (the "Exchangeable Notes Offering"), Enron Corp.
is offering for sale 27,000,000 shares of Common Stock (31,050,000 shares if
the underwriters' over-allotment options in such offerings are exercised in
full) in concurrent U.S. and international offerings (collectively, the "Stock
Offerings"). The consummation of the Exchangeable Notes Offering is not
contingent upon the consummation of the Stock Offerings, or vice versa.
On December 6, 1995, the last reported sale price of Common Stock on the
New York Stock Exchange Composite Tape was $21 3/4 per share. See "Price Range
of Common Stock and Cash Dividends".
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
-------------------------
The date of this Prospectus is , 1995.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in
accordance therewith files reports, proxy statements and other information
with the Securities and Exchange Commission (the "Commission"). Such reports,
proxy statements and other information can be inspected and copied at the
public reference facilities maintained by the Commission at Room 1024, 450
Fifth Street, N.W., Washington, D.C. 20549; and at the following Regional
Offices of the Commission: Midwest Regional Office, 500 West Madison Street,
Suite 1400, Chicago, Illinois 60661; and Northeast Regional Office, Seven
World Trade Center, Suite 1300, New York, New York 10048. Copies of such
material can also be obtained from the Public Reference Section of the
Commission at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549, at
prescribed rates. The Company's Common Stock is listed on the New York Stock
Exchange, Inc. ("NYSE"), and reports, proxy statements and other information
concerning the Company can be inspected and copied at the offices of the New
York Exchange at 20 Broad Street, New York, New York 10005.
This Prospectus constitutes a part of a Registration Statement on Form
S-3 (together with all amendments and exhibits thereto, the "Registration
Statement") filed by the Company with the Commission under the Securities Act
of 1933, as amended (the "Securities Act"), with respect to the shares of
Common Stock offered hereby. This Prospectus does not contain all of the
information set forth in such Registration Statement, certain parts of which
are omitted in accordance with the rules and regulations of the Commission.
Reference is made to such Registration Statement and to the exhibits relating
thereto for further information with respect to the Company and the shares of
Common Stock offered hereby. Any statements contained herein concerning the
provisions of any document filed as an exhibit to the Registration Statement
or otherwise filed with the Commission or incorporated by reference herein are
not necessarily complete, and in each instance reference is made to the copy
of such document so filed for a more complete description of the matter
involved. Each such statement is qualified in its entirety by such reference.
------------------------
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Company's Annual Report on Form 10-K for the year ended December 31,
1994, Quarterly Reports on Form 10-Q for the quarters ended March 31, 1995,
June 30, 1995 and September 30, 1995 and the description of the Common Stock
contained in the Registration Statement on Form 8-A declared effective on
October 3, 1989, are incorporated herein by reference.
Each document filed by the Company pursuant to Section 13(a), 13(c), 14
or 15(d) of the Exchange Act subsequent to the date of this Prospectus and
prior to the termination of the offering of the shares of Common Stock
pursuant hereto shall be deemed to be incorporated herein by reference and to
be a part hereof from the date of filing of such document. Any statement
contained herein or in a document all or a portion of which is incorporated or
deemed to be incorporated by reference herein shall be deemed to be modified
or superseded for purposes of this Prospectus to the extent that a statement
contained herein or in any other subsequently filed document which also is or
is deemed to be incorporated by reference herein modifies or supersedes such
statement. Any statement so modified or superseded shall not be deemed, except
as so modified or superseded, to constitute a part of this Prospectus.
The Company will provide without charge to each person to whom a copy of
this Prospectus is delivered, on the request of any such person, a copy of any
or all of the foregoing documents incorporated herein by reference, other than
exhibits to such documents (unless such exhibits are specifically incorporated
by reference into the documents that this Prospectus incorporates). Requests
should be directed to Secretary Division, Enron Oil & Gas Company, at its
principal executive offices, 1400 Smith Street, Houston, Texas 77002
(telephone: 713-853-6161).
------------------------
IN CONNECTION WITH THE OFFERING OF THE EXCHANGEABLE NOTES AND COMMON
STOCK OF THE COMPANY BY ENRON CORP., THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE EXCHANGEABLE
NOTES OR THE COMMON STOCK OF THE COMPANY AT A LEVEL ABOVE THAT WHICH MIGHT
OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE
NEW YORK STOCK EXCHANGE, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH
STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
2
PROSPECTUS SUMMARY
THE FOLLOWING IS A SUMMARY OF CERTAIN INFORMATION CONTAINED IN THIS
PROSPECTUS. IT IS NOT INTENDED TO BE COMPLETE AND IS QUALIFIED IN ITS ENTIRETY
BY THE MORE DETAILED INFORMATION CONTAINED ELSEWHERE IN THIS PROSPECTUS.
CERTAIN TERMS ARE DEFINED IN THIS SUMMARY UNDER "CERTAIN DEFINITIONS."
CAPITALIZED TERMS WHICH ARE NOT DEFINED IN THIS SUMMARY ARE USED AS DEFINED
ELSEWHERE IN THIS PROSPECTUS.
THE COMPANY
Enron Oil & Gas Company (together with its subsidiaries, "the Company")
is one of the largest independent (non-integrated) oil and gas companies in
the United States in terms of domestic proved reserves. It is engaged,
directly and through its subsidiaries, in the exploration for, and the
development, production and marketing of, natural gas and crude oil primarily
in major producing basins in the United States, as well as in Canada, Trinidad
and India and to a lesser extent, selected other international areas. At
December 31, 1994, the Company's estimated net proved natural gas reserves
were 1,910 Bcf and estimated net proved crude oil, condensate and natural gas
liquids reserves were 37 MMBbl, a net increase of 8% and 78%, respectively,
over year end 1993. The Company has increased its reserves for six consecutive
years. At December 31, 1994, approximately 70% of the Company's reserves (on a
natural gas equivalent basis) was located in the United States, 16% in Canada,
11% in Trinidad and 3% in India. At such date, approximately 90% of the
Company's total proved reserves was classified as developed.
While year end reserve evaluations will not be available for some time,
based on the results of the Company's drilling program for the first nine
months of 1995, it is expected that extensions, discoveries and other
additions to reserves for the year will exceed production for both North
America and Trinidad, as well as in total. Additionally, reserves acquired are
expected to substantially exceed those sold, with the resulting replacement of
production from all sources expected to exceed 150%.
BUSINESS STRATEGY. The Company's strategy is to maximize the rate of
return on investment of capital by controlling both operating and capital
costs and enhancing the certainty of future revenues through the use of
various marketing mechanisms. This strategy enhances the generation of both
income and cash flow from each unit of production and allows for the growth of
production on a cost-effective basis by optimizing the reinvestment of cash
flow. Through this strategy, the Company has increased its net income in each
of the last five years, despite the volatile natural gas price environment,
and achieved a return on equity ranging from 8% in 1990 to 15% in 1994. For
the first nine months of 1995, net income increased 5% compared to the same
period for 1994.
The Company refocused its 1995 drilling activity away from natural gas
deliverability and toward natural gas reserve enhancement and crude oil
exploitation in the United States in response to the decline in United States
natural gas prices in recent periods. The Company also is focusing on the
cost-effective utilization of advances in technology associated with
gathering, processing and interpretation of 3-D seismic data, developing
reservoir simulation models and drilling operations through the use of new
and/or improved drill bits, mud motors, mud additives, formation logging
techniques and reservoir fracturing methods. These advanced technologies are
used, as appropriate, throughout the Company to reduce the risks associated
with all aspects of oil and gas reserve exploration, exploitation and
development.
The Company implements its strategy by emphasizing the drilling of
internally generated prospects in order to find and develop low cost reserves.
By following this strategy, the Company
3
has increased production in each of the last four years with a compound annual
growth rate of 13.1%, while increasing proved reserves approximately 32%, both
on a natural gas equivalent basis. For 1994, net equivalent production reached a
new high of 307 Bcfe, an increase of 9% over 1993. Natural gas delivered in 1994
averaged approximately 749 MMcf per day, which represents an increase of 6% over
1993. Crude oil and condensate production averaged 12.6 MBbl per day in 1994
which represents an increase of 42% over 1993. Natural gas production for the
first nine months of 1995 averaged 719 MMcf per day, down 24 MMcf per day from
the first nine months of 1994. Lower volumes in 1995 reflect the voluntary
curtailment by the Company of United States production at a higher rate than in
1994 because United States natural gas prices were down by 26% period to period,
the impact of the sale of reserves and related assets and the effect of the
reduction and redirection of natural gas drilling activities early in 1995.
Crude oil and condensate volumes for the first nine months of 1995 averaged 18.6
MBbl per day, an increase of 55% over the first nine months of 1994.
Achieving and maintaining the lowest possible cost structure are also
important goals in the implementation of the Company's strategy. Over the last
five years, the Company has reduced total cash operating expenses, including
lease and well, general and administrative, taxes other than income, and
interest expenses from $.95/Mcfe in 1989 to $.49/Mcfe in 1994, a reduction of
48%. At the same time non-cash expenses (depreciation, depletion and
amortization) have been reduced from $.93/Mcfe in 1989 to $.80/Mcfe in 1994, a
reduction of 14%. For the first nine months of 1995, cash operating expenses
averaged $.56/Mcfe compared to $.50/Mcfe for the first nine months of 1994 and
non-cash expenses averaged $.69/Mcfe and $.81/Mcfe for the two periods,
respectively.
Consistent with the Company's desire to optimize the use of its assets,
the Company also maintains a strategy of selling select oil and gas properties
that for various reasons no longer fit into future operating plans, or which
are not assessed to have sufficient future growth potential and when the
economic value to be obtained by selling the properties and reserves in the
ground is evaluated to be greater than what would be obtained by holding the
properties and producing the reserves over time. As a result, the Company
typically receives each year a varying but substantial level of proceeds
related to such sales which proceeds are available for general corporate use.
Proceeds from property sales in 1994 were $91 million ($71 million after tax)
and in the first nine months of 1995 were $101 million ($77 million after
tax).
NORTH AMERICAN OPERATIONS. The Company's seven principal United States
producing areas are the Big Piney area of Wyoming, South Texas area, East
Texas area, Offshore Gulf of Mexico area, Canyon Trend area of West Texas,
Pitchfork Ranch area of New Mexico and Vernal area of Utah. Properties in
these areas comprised approximately 76% of the Company's United States
reserves (on a natural gas equivalent basis) and 85% of the Company's United
States net natural gas deliverability as of December 31, 1994 and are
substantially all operated by the Company. The Company's other United States
natural gas and crude oil producing properties are located primarily in other
areas of Texas, Utah, New Mexico and in Oklahoma.
At December 31, 1994, 93% of the Company's proved United States reserves
(on a natural gas equivalent basis) was natural gas and 7% was crude oil,
condensate and natural gas liquids.
A substantial portion of the Company's United States natural gas reserves is
in long-lived fields with well-established production histories. The Company
believes that opportunities exist to increase production in many of these
fields through continued infill and other development drilling.
The Company also has natural gas and crude oil producing properties
located in Western Canada, primarily in the provinces of Alberta, Saskatchewan
and Manitoba. The Company produces natural gas from seven major areas and
crude oil from three major areas. The Sandhills area in
4
Southern Saskatchewan is the largest single producing area, contributing 51%
of Canadian deliverability at September 30, 1995. Canadian natural gas
deliverability net to the Company at September 30, 1995 was approximately 70
MMcf per day and the Company held approximately 350,000 net undeveloped acres
in Canada.
OUTSIDE NORTH AMERICA OPERATIONS. The Company has operations offshore
Trinidad and India and is conducting exploration in selected other
international areas. Properties offshore Trinidad and India comprise 100% of
the Company's current reserves and production outside of North America. The
Company's reserves at December 31, 1994 included 236 Bcf of natural gas and 12
MMBbl of liquids in these two areas. The Company's net production from
offshore Trinidad was approximately 100 MMcf per day of natural gas and 6.2
MBbl per day of crude oil and condensate at September 30, 1995. The Company's
net production from offshore India was approximately 3.5 MBbl per day of crude
oil net to the Company at September 30, 1995. In addition, the Company is
pursuing other exploitation opportunities in countries, including China,
Mozambique and Qatar, where indigenous natural gas reserves have been
identified, particularly where synergies in natural gas transportation,
processing and power cogeneration can be optimized with other Enron Corp.
affiliated companies.
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
All of the shares of Common Stock offered hereby and in the Stock
Offerings are being sold by Enron Corp., and the Company will receive no
proceeds from such sales. Concurrently with the offering of the Exchangeable
Notes, Enron Corp. is offering for sale 27,000,000 shares of Common Stock
(31,050,000 shares if the Underwriters' over-allotment options in such Stock
Offerings are exercised in full). Following the consummation of the Stock
Offerings, Enron Corp. will own an aggregate of 101,000,000 shares of Common
Stock or approximately 63% of the outstanding shares (or, assuming that the
Underwriters' over-allotment options in the Stock Offerings are exercised in
full, 96,950,000 shares of Common Stock or approximately 61% of the
outstanding shares). At maturity, the Exchangeable Notes may be exchanged for
no more than 10,000,000 shares of Common Stock (no more than 11,000,000 shares
if the over-allotment option of the underwriters in the Exchangeable Notes
Offering is exercised in full), subject to adjustment under certain
circumstances and to Enron Corp.'s option to pay an amount of cash in lieu of
such mandatory exchange. Assuming the underwriters' over-allotment options in
the Stock Offerings and the Exchangeable Notes Offering are exercised in full
and the maximum number of shares is mandatorily exchanged at maturity of the
Exchangeable Notes, Enron Corp.'s remaining ownership of Common Stock would be
approximately 54% of the outstanding shares. Any market that develops in the
Exchangeable Notes is likely to influence, and be influenced by, the market
for the Common Stock. For example, the price of the Common Stock could become
more volatile and could be depressed by possible sales of Common Stock by
investors who view the Exchangeable Notes as a more attractive means of equity
participation in the Company and by hedging and arbitrage activity that may
develop involving the Exchangeable Notes and the Common Stock.
Neither the Stock Offerings nor the delivery of shares of Common Stock
pursuant to the terms of the Exchangeable Notes will affect the existing
agreements between the Company and Enron Corp. and their respective
affiliates, except for the Tax Allocation Agreement which will cease to be
effective from the time at which deconsolidation occurs (when Enron Corp.
ceases to own 80% of the outstanding shares of Common Stock). The Company and
Enron Corp. have entered into a new tax agreement pursuant to which, among
other things, Enron Corp. has agreed (in exchange for the payment of $8.0
million by the Company) to be liable for, and to indemnify the Company against,
all federal income taxes and state taxes measured by net income imposed on
the Company for
5
periods through the date Enron Corp. reduces its ownership in the Company to
less than 80%. The Company does not believe that the cessation of consolidated
tax reporting with Enron Corp. and effectiveness of the Tax Allocation Agreement
concurrently with deconsolidation or the terms of the new agreement will have a
material adverse effect on its financial condition or results of operations. See
"Relationship Between the Company and Enron Corp."
The nature of the respective businesses of the Company and Enron Corp.
and its affiliates is such as to potentially give rise to conflicts of
interest between the two companies. The Company's operations account for
substantially all of Enron Corp.'s natural gas and crude oil exploration and
production operations. An affiliate of Enron Corp. has entered into an
agreement to acquire a controlling interest in Coda Energy, Inc. ("Coda"), a
company engaged in domestic oil and gas exploration, development and
production. Crude oil accounts for approximately 86% of Coda's proved
reserves. At December 31, 1994, Coda reported estimated proved natural gas
reserves of 39,808 MMcf and estimated proved crude oil, condensate and natural
gas liquids reserves of 39,207 MBbls. If the transaction is consummated,
conflicts of interest could arise between the Company and Coda. See
"Relationship Between the Company and Enron Corp. -- Conflicts of Interest."
6
<PAGE>
SUMMARY FINANCIAL AND OPERATING INFORMATION
The following table sets forth a summary of selected consolidated
financial and operating data for the Company for each of the five years in the
period ended December 31, 1994 and for the nine-month periods ended September
30, 1994 and 1995. This information should be read in conjunction with the
consolidated financial statements of the Company and related notes thereto
incorporated by reference herein (see "Incorporation of Certain Documents by
Reference") and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" included elsewhere in this Prospectus. Financial
information for each of the five years in the period ended December 31, 1994
has been derived from audited financial statements. Financial information for
the nine-month periods ended September 30, 1994 and 1995 has been derived from
unaudited financial statements. The interim data reflects all adjustments
which, in the opinion of the management of the Company, are necessary to
present fairly such information for the interim periods. Results of the
nine-month periods are not necessarily indicative of the results expected for
a full year or any other interim period.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
--------------------------------------------------------------- ------------------------
1990 1991 1992 1993 1994 1994 1995
----------- ----------- ----------- ----------- ----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF INCOME DATA:
Net operating revenues(1)............ $ 403,137 $ 402,588 $ 459,026 $ 581,020 $ 625,823 $ 474,340 $ 492,342
Income before income taxes........... 34,614 45,669 79,844 112,273 153,935 126,166 144,175
Net income........................... 45,468 47,916 97,580 138,025 147,998 105,438 110,731
Earnings per share of common
stock(2)........................... $.30 $.32 $.63 $.86 $.93 $.66 $.69
Average number of common shares(2)... 151,800 151,800 154,533 159,966 159,845 159,826 159,951
BALANCE SHEET DATA (AT PERIOD END):
Net oil and gas properties........... $ 1,305,136 $ 1,339,666 $ 1,468,011 $ 1,546,045 $ 1,684,811 $ 1,637,762 $ 1,843,150
Total assets......................... 1,417,939 1,455,608 1,731,012 1,811,162 1,861,867 1,855,819 2,109,971
Long-term debt
Affiliate........................ 277,918 132,836 --(3) -- 25,000 25,000 16,320
Other............................ 140,442 289,556 150,000(3) 153,000 165,337 158,862 247,552
Deferred revenue..................... -- -- 301,395 227,528 184,183 195,109 224,085
Shareholders' equity................. 610,042 643,185 826,986(3) 933,073 1,043,419 1,019,712 1,140,295
OPERATING DATA:
Wellhead Volumes and Prices
Natural Gas Volumes (MMcf per
day)(4)............................ 455 491 564 709 749 743 719
Average Natural Gas Prices
($/Mcf)(5)......................... $1.51 $1.37 $1.58 $1.92 $1.62 $1.69 $1.23
Crude/Condensate Volumes (MBbl per
day)............................... 8.2 8.2 8.5 8.9 12.6 12.0 18.6
Average Crude/Condensate Prices
($/Bbl)............................ $21.67 $18.78 $17.90 $16.37 $15.62 $15.24 $16.77
</TABLE>
- ------------
(1) Net operating revenues for the years 1990 and 1991 and for the first nine
months of 1994 have been revised to include gains from sales of reserves
and related assets for consistency with current year reporting.
(2) In May 1994, the Board of Directors declared a two-for-one split of the
Company's Common Stock to be effected as a non-taxable dividend of one
share for each share outstanding on May 31, 1994. All share and per share
amounts presented herein are reflected on a post-split basis.
(3) In August 1992, the Company completed the sale of 8.2 million shares of
Common Stock resulting in aggregate net proceeds to the Company of
approximately $112 million used primarily to repay long-term debt. In
September 1992, the Company completed the sale of a volumetric production
payment, resulting in net proceeds of approximately $327 million used to
repay long-term debt and for other general corporate purposes.
(4) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per
day in 1994 and in the nine-month periods ended September 30, 1994 and
1995 delivered under the terms of a volumetric production payment
agreement effective October 1, 1992, as amended.
(5) Includes an average equivalent wellhead value of $1.70 per Mcf in 1992,
$1.57 per Mcf in 1993, $1.27 per Mcf in 1994 and $1.32 per Mcf and $.76
per Mcf in the nine-month periods ended September 30, 1994 and 1995,
respectively, for the volumes described in note (4), net of transportation
costs.
7
<PAGE>
SUMMARY OIL AND GAS RESERVE INFORMATION
The following table sets forth summary information with respect to the
Company's estimates of its net proved natural gas, crude oil, condensate and
natural gas liquids reserves at December 31, 1994. For additional information
relating to reserves, see "Business -- Oil and Gas Exploration and Production
Properties and Reserves."
<TABLE>
<CAPTION>
NATURAL GAS
NATURAL EQUIVALENTS (BCFE)
GAS LIQUIDS ------------------------
(BCF) (MBBL)(1) DEVELOPED UNDEVELOPED
-------- ----------- --------- -----------
<S> <C> <C> <C> <C>
Net proved reserves at December 31, 1994:
United States.......................................... 1,307 17,787 1,229 185
Canada................................................. 297 7,237 330 10
Trinidad............................................... 206 4,429 233 --
India.................................................. 29 7,585 46 29
-------- ----------- --------- -----------
Total............................................. 1,839 37,038 1,838 224
======== =========== ========= ===========
</TABLE>
Reserve amounts set out above have been revised to exclude volumes
attributable to a volumetric production payment from owned reserves.
The Company's estimates of its net proved natural gas, crude oil,
condensate and natural gas liquids reserves at December 31, 1994, including
amounts attributable to a volumetric production payment, are shown below. This
disclosure is presented as additional information and is not intended to
represent required disclosure pursuant to Statement of Financial Accounting
Standards ("SFAS") No. 69 -- "Disclosures about Oil and Gas Producing
Activities."
<TABLE>
<CAPTION>
NATURAL GAS
NATURAL EQUIVALENTS (BCFE)
GAS LIQUIDS ------------------------
(BCF) (MBBL)(1) DEVELOPED UNDEVELOPED
-------- ----------- --------- -----------
<S> <C> <C> <C> <C>
Net proved reserves at December 31, 1994, including
amounts attributable to volumetric production
payment:
United States.......................................... 1,378 17,787 1,300 185
Canada................................................. 297 7,237 330 10
Trinidad............................................... 206 4,429 233 --
India.................................................. 29 7,585 46 29
-------- ----------- --------- -----------
Total............................................. 1,910 37,038 1,909 224
======== =========== ========= ===========
</TABLE>
- ------------
(1) Includes crude oil, condensate and natural gas liquids.
8
CERTAIN DEFINITIONS
Unless otherwise indicated in this Prospectus, natural gas volumes are
stated at the legal pressure base of the state, area or country in which the
reserves are located and at 60 Fahrenheit. Natural gas equivalents are
determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude
oil, condensate or natural gas liquids.
As used herein, the following terms have the specific meanings set out:
"Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means
billion cubic feet, "Bbl" means barrel, "MBbl" means thousand barrels, "MMBbl"
means million barrels, "Mcfe" means thousand cubic feet equivalent, "MMcfe"
means million cubic feet equivalent, "Bcfe" means billion cubic feet
equivalent, "MMBtu" means million British thermal units, "BBtu" means billion
British thermal units and "TBtu" means trillion British thermal units.
With respect to information on the Company's working interest in wells or
acreage, "net" oil and gas wells or acreage are determined by multiplying
"gross" oil and gas wells or acreage by the Company's working interest in the
wells or acreage.
"Exploration and development expenditures" include costs associated with
exploratory and development drilling (including exploratory dry holes),
leasehold acquisitions, seismic data acquisitions, geological and land related
overhead expenditures, delay rentals, producing property acquisitions,
capitalized interest and other miscellaneous capital expenditures. "Total
finding costs" is the ratio of total exploration and development expenditures
to reserves added as a result of the drilling and acquisition program.
Reserves added include the total net natural gas equivalent volume of all
natural gas, crude oil, condensate and natural gas liquids added from
extensions, discoveries and other additions, purchases in place and revisions
of previous estimates.
"Infill drilling" means drilling for the development and production of
net proved undeveloped reserves.
9
USE OF PROCEEDS
The shares of Common Stock of the Company being offered hereby and the
Exchangeable Notes are being sold by Enron Corp. Accordingly, the Company will
not receive any of the proceeds from the Stock Offerings or the sale of the
Exchangeable Notes or delivery of shares of Common Stock pursuant thereto.
PRICE RANGE OF COMMON STOCK AND CASH DIVIDENDS
The following table sets forth, for the periods indicated, the high and
low sale prices per share for the Common Stock, as reported on the New York
Stock Exchange Composite Tape, and the amount of cash dividends paid per
share. The 1993 and First and Second Quarter 1994 sales prices and cash
dividends per share have been restated to reflect the two-for-one stock split
on May 31, 1994.
PRICE RANGE
-------------------- CASH
HIGH LOW DIVIDENDS
--------- --------- ---------
1993
First Quarter................... $ 20.31 $ 13.38 $ .03
Second Quarter.................. 22.50 17.88 .03
Third Quarter................... 26.81 19.88 .03
Fourth Quarter.................. 27.00 17.06 .03
1994
First Quarter................... $ 23.75 $ 19.31 $ .03
Second Quarter.................. 24.63 22.38 .03
Third Quarter................... 23.00 18.50 .03
Fourth Quarter.................. 22.75 17.38 .03
1995
First Quarter................... $ 24.88 $ 17.12 $ .03
Second Quarter.................. 24.75 20.25 .03
Third Quarter................... 25.38 20.00 .03
Fourth Quarter (through December
6, 1995)........................ 22.75 18.75
See the cover page of this Prospectus for the last reported sale price of
the Common Stock on the NYSE as of a recent date.
As of November 1, 1995, there were approximately 270 record holders of
the Company's Common Stock, including individual participants in security
position listings. There are an estimated 5,100 beneficial owners of the
Company's Common Stock, including shares held in street name.
Following the initial public offering and sale of its Common Stock in
October 1989, the Company paid quarterly dividends of $0.025 per share
beginning with an initial dividend paid in January 1990 with respect to the
fourth quarter of 1989. Beginning in January 1993 with respect to the fourth
quarter of 1992, the Company has paid quarterly dividends of $0.03 per share.
The Company currently intends to continue to pay quarterly cash dividends on
its outstanding shares of Common Stock. However, the determination of the
amount of future cash dividends, if any, to be declared and paid will depend
upon, among other things, the financial condition, funds from operations,
level of exploration and development expenditure opportunities and future
business prospects of the Company.
10
BUSINESS
GENERAL
The Company, a Delaware corporation organized in 1985, is engaged, either
directly or through a marketing subsidiary with regard to domestic operations
or through various subsidiaries with regard to international operations, in
the exploration for, and the development, production and marketing of, natural
gas and crude oil primarily in major producing basins in the United States, as
well as in Canada, Trinidad and India and to a lesser extent, selected other
international areas. At December 31, 1994, the Company's estimated net proved
natural gas reserves were 1,910 Bcf and estimated net proved crude oil,
condensate and natural gas liquids reserves were 37 MMBbl. At such date,
approximately 70% of the Company's reserves (on a natural gas equivalent
basis) was located in the United States, 16% in Canada, 11% in Trinidad and 3%
in India.
The Company pursues its oil and gas exploration and development
operations primarily by the acquisition, through various means including but
not limited to leasing, purchasing and farming-in of acreage that is either
undeveloped or lightly developed, and drilling of internally generated
prospects. The Company also maintains a strategy of selling selected oil and
gas properties that, for various reasons, no longer fit into future operating
plans or which are not assessed to have sufficient future growth potential and
when the economic value to be obtained by selling the properties and reserves
in the ground is evaluated to be greater than what would be obtained by
holding the properties and producing the reserves over time. As a result, the
Company typically receives each year a varying but substantial level of
proceeds related to such sales which proceeds are available for general
corporate use.
EXPLORATION AND PRODUCTION
NORTH AMERICAN OPERATIONS
The Company's seven principal United States producing areas are the Big
Piney area, South Texas area, East Texas area, Offshore Gulf of Mexico area,
Canyon Trend area, Pitchfork Ranch area and Vernal area. Properties in these
areas comprised approximately 76% of the Company's United States reserves (on
a natural gas equivalent basis) and 85% of the Company's United States net
natural gas deliverability as of December 31, 1994 and are substantially all
operated by the Company. At September 30, 1995, properties in these areas
comprised approximately 87% of the Company's United States net natural gas
deliverability. The Company's other United States natural gas and crude oil
producing properties are located primarily in other areas of Texas, Utah, New
Mexico and in Oklahoma.
At December 31, 1994, 93% of the Company's proved United States reserves
(on a natural gas equivalent basis) was natural gas and 7% was crude oil,
condensate and natural gas liquids. A substantial portion of the Company's
United States natural gas reserves is in long-lived fields with
well-established production histories. The Company believes that opportunities
exist to increase production in many of these fields through continued infill
and other development drilling.
The Company also has natural gas and crude oil producing properties
located in Western Canada, primarily in the provinces of Alberta, Saskatchewan
and Manitoba.
BIG PINEY AREA. The Company's largest reserve accumulation is located in
the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming.
The Company is the holder of the largest productive acreage base in this area,
with approximately 219,000 net acres under lease directly within field limits.
The Company operates approximately 650 natural gas wells in this area in which
it owns a 91% average working interest. Deliveries from the area net to the
Company averaged 124 MMcf per day of natural gas and 1.5 MBbl per day of crude
oil, condensate, and natural gas liquids in 1994. At September 30, 1995,
natural gas deliverability net to the Company was approximately 138 MMcf per
day.
The current principal producing intervals are the Frontier and Mesaverde
formations. The Frontier formation, which occurs at 6,500-10,000 feet,
contains approximately 66% of the Company's current Big Piney reserves. The
Company drilled 67 wells in the Big Piney area in 1994. Although natural gas
drilling has been curtailed in this area during 1995 in response to market
conditions, numerous drilling opportunities will be available for several
years.
11
During the fourth quarter of 1995, the Company anticipates recording as
proved undeveloped reserves approximately 1,100 Bcf of methane contained,
along with high concentrations of carbon dioxide and nitrogen as well as small
amounts of other gaseous substances, in the deep Wyoming Paleozoic formation
located under acreage leased by the Company and held by production in the Big
Piney area. The Company is actively pursuing the consummation of a market or
markets from several different potential sources to facilitate realizing the
value of these reserves.
SOUTH TEXAS AREA. The Company's activities in South Texas are focused in
the Wilcox, Expanded Wilcox, Frio and Lobo producing horizons. The principal
area of activity is in the Lobo Trend which occurs primarily in Webb and
Zapata counties.
The Company operates approximately 470 wells in the South Texas area.
Production is primarily from the Lobo sand of the Wilcox formation at depths
ranging from 7,000 to 11,000 feet. The Company has approximately 250,000 net
acres under lease in this area. Natural gas deliveries net to the Company
averaged 181 MMcf per day in 1994. At September 30, 1995, natural gas
deliverability from this area net to the Company was approximately 150 MMcf
per day which was impacted during 1995 by the sale of selected properties. The
Company drilled 56 wells in the South Texas area in 1994 and anticipates an
active drilling program will continue for several years.
EAST TEXAS AREA. The Company's activities in the East Texas area are
primarily in the Carthage field, located in Panola County, and the North
Milton field, located in northern Harris County.
The Carthage field is the Company's newest area of concentration. This
field is one of the most prolific fields in east Texas with production
primarily from the Cotton Valley, Travis Peak and Pettit formations. In 1995,
properties were acquired that doubled the Company's acreage position to 17,000
acres. An active drilling program is planned for the remainder of 1995 and for
several years. The Company has an average 71% working interest in its
holdings. The Company has continued its activity in the North Milton field
where it now operates 19 wells and holds a 100% working interest in the
acreage. Further drilling is planned for 1996. At September 30, 1995,
deliverability from the East Texas area was approximately 35 MMcf per day of
natural gas with almost 1.0 MBbl per day of condensate, both net to the
Company.
OFFSHORE GULF OF MEXICO AREA. At September 30, 1995, the Company held an
interest in 191 blocks in the Offshore Gulf of Mexico area totaling 561,000
net acres. Of the 191 blocks, 133 are operated by the Company. These interests
are located predominantly in federal waters offshore Texas and Louisiana.
During 1995, the Company acquired a 50% interest in operations previously
owned by Santa Fe Minerals complementing previously owned interests and adding
significantly to the Company's offshore operations. Natural gas deliveries
from this area averaged 83 MMcf per day during 1994 and 118 MMcf per day
during the first nine months of 1995, both net to the Company. A substantial
portion of such deliveries was from interests in the Matagorda trend with
significant volumes also coming from the Mustang Island area. Deliverability
from this area at September 30, 1995 was 160 MMcf per day net to the Company
sourced principally as noted above. The Company has maintained an active
drilling program in this area during 1994 and 1995 and anticipates a similar
program to continue for several years.
CANYON TREND AREA. The Company's activities in this area have been
concentrated in Crockett, Sutton, Terrell and Val Verde Counties, Texas where
the Company drilled 331 natural gas wells during the period 1992 through 1994.
The Company holds approximately 91,800 net acres and now operates
approximately 500 natural gas wells in this area in which it owns a 97%
average working interest. Production is from the Canyon sands and Strawn
limestone at depths from 5,500 to 11,500 feet. In 1994, natural gas deliveries
from this area net to the Company averaged 65 MMcf per day. At September 30,
1995, natural gas deliverability from this area net to the Company was
approximately 54 MMcf per day. The Company has maintained an active drilling
program in the Canyon Trend area during 1995 and expects a similar program to
continue for several years.
PITCHFORK RANCH FIELD. The Pitchfork Ranch field located in Lea County,
New Mexico, produces primarily from the Bone Spring, Atoka and Morrow
formations. In 1994, deliveries net to the Company from this area averaged 36
MMcf per day of natural gas and approximately 2 MBbl per
12
day of crude oil, condensate and natural gas liquids. At September 30, 1995,
deliverability from this area net to the Company was approximately 32 MMcf per
day of natural gas and 3.6 MBbl per day of crude oil, condensate and natural
gas liquids. The Company holds approximately 27,900 net acres and expects to
maintain an active drilling program in this field for several years.
VERNAL AREA. In the Vernal area, located primarily in Uintah County,
Utah, the Company operates approximately 195 producing wells and presently
controls approximately 79,000 net acres. For the first nine months of 1995,
natural gas deliveries net to the Company from the Vernal area averaged 24
MMcf per day which represents deliverability. Production is from the Green
River and Wasatch formations located at depths between 4,500-8,000 feet. The
Company has an average working interest of approximately 60%. The Company
drilled 20 wells in the Vernal area in 1994 and has maintained a comparable
drilling program during 1995.
CANADA. The Company is engaged in the exploration for and the
development, production and marketing of natural gas and crude oil and the
operation of natural gas processing plants in western Canada, principally in
the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts
operations from offices in Calgary. The Company produces natural gas from
seven major areas and crude oil from three major areas. The Sandhills area in
Southern Saskatchewan is the largest single producing area where 160 wells
were drilled in 1994 resulting in deliverability net to the Company from the
field of approximately 38 MMcf per day at December 31, 1994. Canadian natural
gas deliverability net to the Company at September 30, 1995 was approximately
70 MMcf per day and the Company held approximately 350,000 net undeveloped
acres in Canada. The Company expects to maintain an active drilling program in
Canada for several years.
OUTSIDE NORTH AMERICA OPERATIONS
The Company has operations offshore Trinidad and India and is conducting
exploration in selected other international areas. Properties offshore
Trinidad and India comprised 100% of the Company's proved reserves and
production outside of North America at year end 1994.
TRINIDAD. In November 1992, the Company was awarded a 95% working
interest concession in the South East Coast Consortium ("SECC") block offshore
Trinidad, encompassing three undeveloped fields, previously held by three
government-owned energy companies. The Kiskadee field has been developed, the
Ibis field is under development and the Oil Bird field is anticipated to be
developed over the next three to five years. Existing surplus processing and
transportation capacity at the Pelican field facilities owned and operated by
Trinidad and Tobago government-owned companies is being used to process and
transport the production. Natural gas is being sold into the local market
under a take-or-pay agreement with the National Gas Company of Trinidad and
Tobago. In 1994, deliveries net to the Company averaged 63 MMcf per day of
natural gas and 2.6 MBbl per day of crude oil and condensate. At September 30,
1995, deliverability net to the Company was approximately 166 MMcf per day of
natural gas and 8.0 MBbls per day of crude oil and condensate. The Company's
net production from offshore Trinidad was approximately 100 MMcf per day of
natural gas and 6.2 MBbl per day of crude oil and condensate at September 30,
1995. The Company held approximately 71,000 net undeveloped acres in Trinidad.
The Company recently has been awarded the right to develop the U(a) block
adjacent to the SECC block and is presently negotiating the terms of a
production sharing contract with the Government of Trinidad and Tobago.
INDIA. In December 1994, the Company signed agreements covering profit
sharing, joint operations and product sales, and was granted a 30% working
interest in, the Tapti, Panna and Mukta blocks located offshore Bombay, India.
The Company is designated operator of all three areas. The blocks were
previously operated by the Indian national oil company, Oil & Natural Gas
Corporation Limited, which retained a 40% working interest. The 363,000 acre
Tapti Block contains two major proved gas accumulations delineated by 22
expendable exploration wells that have been plugged. The Company has initiated
a development plan for the Tapti Block accumulations. The 106,000 acre Panna
Block and the 192,000 acre Mukta Block are partially developed with 30 wells
producing from five producing platforms located in the Panna and Mukta fields.
The fields were producing approximately 3.5 MBbl per day of crude oil net to
the Company as of September 30,
13
1995; all associated natural gas was being flared. The Company intends to
continue development of the accumulations and to expand processing capacity to
allow crude oil production at full deliverability as well as to permit natural
gas sales.
OTHER INTERNATIONAL. The Company continues to evaluate other selected
conventional natural gas and crude oil opportunities outside North America.
The Company is pursuing other exploitation opportunities in countries where
indigenous natural gas reserves have been identified, particularly where
synergies in natural gas transportation, processing and power cogeneration can
be optimized with other Enron Corp. affiliated companies. In early 1995, the
Company and the Qatar General Petroleum Corporation signed a nonbinding letter
of intent concerning the possible development of a liquefied natural gas
project for natural gas to be produced from the North Dome Field. The Company
and Enron Corp. may jointly hold up to a 40% working interest in the joint
venture and drill and develop to-be-agreed-upon reserves. In addition, the
Company signed letters of intent in early 1995 with the National Oil
Corporation of Uzbekistan, and Gazprom, the Russian natural gas company, to
pursue the feasibility of joint venture development and marketing of
previously discovered conventional hydrocarbon reserves in Uzbekistan. The
Company is also in discussions concerning the potential for conventional oil
and gas development opportunities in China, Mozambique and Qatar. The Company
holds nonoperating working interests in two conventional oil and gas
exploration prospects in the U.K. North Sea.
The Company continues evaluation and assessment of its international
opportunity portfolio in the coalbed methane recovery arena, including
projects in South Wales in the U.K., the Lorraine Basin in France, Galilee
Basin in Queensland, Australia and Hedong basin in China.
MARKETING
WELLHEAD MARKETING
The Company's North America wellhead natural gas production is currently
being sold on the spot market and under long-term natural gas contracts at
market responsive prices. In many instances, the long-term contract prices
closely approximate the prices received for natural gas being sold on the spot
market. Wellhead natural gas volumes from Trinidad are sold at prices that are
based on a fixed price schedule with annual escalations. Natural gas volumes
in India will be sold to the Gas Authority of India, Ltd. under a take-or-pay
contract at a price linked to a basket of world market fuel oil quotations
with floor and ceiling limits. Approximately 45% of the Company's wellhead
natural gas production is currently being sold to pipeline and marketing
subsidiaries of Enron Corp. The Company believes that the terms of its
transactions and agreements with Enron Corp. and/or its affiliates are and
intends that future such transactions and agreements will be at least as
favorable to the Company as could be obtained from third parties.
Substantially all of the Company's wellhead crude oil and condensate is
sold under short-term contracts at market responsive prices.
OTHER MARKETING
Enron Oil & Gas Marketing, Inc. ("EOGM") is a wholly-owned subsidiary of
the Company engaged in various marketing activities. Both the Company and EOGM
contract to provide, under short and long-term agreements, natural gas to
various purchasers and then aggregate the necessary supplies for the sales
with purchases from various sources including third-party producers, marketing
companies, pipelines or from the Company's own production. In addition, EOGM
has purchased and constructed several small gathering systems in order to
facilitate its entry into the gathering business on a strategic basis. Both
the Company and EOGM utilize other short and long-term hedging and trading
mechanisms including sales and purchases utilizing NYMEX-related commodity
market transactions. All of these activities are currently conducted with
companies affiliated with Enron Corp. These marketing activities have provided
an effective balance in managing the Company's exposure to commodity price
risks for both natural gas and crude oil and condensate wellhead prices. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Capital Resources and Liquidity -- Hedging Transactions."
14
<PAGE>
WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES
The following table sets forth certain information regarding the
Company's wellhead volumes of and average prices for natural gas per Mcf,
crude oil and condensate, and natural gas liquids per Bbl, and average lease
and well expenses per Mcfe delivered during each of the three years in the
period ended December 31, 1994 and the nine-month periods ended September 30,
1994 and 1995.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1992 1993 1994 1994 1995
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
VOLUMES (PER DAY)
Natural Gas (MMcf)
United States(1)........... 534 649 614 609 534
Canada..................... 30 58 72 71 75
Trinidad................... -- 2 63 63 110
--------- --------- --------- --------- ---------
Total(1)................. 564 709 749 743 719
========= ========= ========= ========= =========
Crude Oil and Condensate (MBbl)
United States.............. 6.3 6.6 8.0 7.5 9.1
Canada..................... 2.2 2.2 2.0 1.9 2.4
Trinidad................... -- .1 2.5 2.6 4.8
India...................... -- -- .1 -- 2.3
--------- --------- --------- --------- ---------
Total.................... 8.5 8.9 12.6 12.0 18.6
========= ========= ========= ========= =========
Natural Gas Liquids (MBbl)
United States.............. .3 .2 .3 .2 1.2
Canada..................... .4 .4 .4 .5 .3
--------- --------- --------- --------- ---------
Total.................... .7 .6 .7 .7 1.5
========= ========= ========= ========= =========
AVERAGE PRICES
Natural Gas ($/Mcf)
United States(2)........... $ 1.61 $ 1.97 $ 1.71 $ 1.79 $ 1.33
Canada..................... 1.18 1.34 1.42 1.51 .95
Trinidad................... -- .89 .93 .93 .97
Composite(2)............. 1.58 1.92 1.62 1.69 1.23
Crude Oil and Condensate ($/Bbl)
United States.............. $ 18.29 $ 16.96 $ 16.06 $ 15.64 $ 17.20
Canada..................... 16.80 14.63 14.05 13.72 16.31
Trinidad................... -- 14.36 15.50 15.20 16.16
India...................... -- -- 15.70 -- 16.82
Composite................ 17.90 16.37 15.62 15.24 16.77
Natural Gas Liquids ($/Bbl)
United States.............. $ 11.56 $ 13.85 $ 12.45 $ 12.50 $ 11.76
Canada..................... 10.05 9.46 8.45 7.86 9.69
Composite................ 10.69 11.12 9.90 9.43 11.27
LEASE AND WELL EXPENSES ($/MCFE)
United States.............. $ .20 $ .18 $ .19 $ .19 $ .20
Canada..................... .50 .48 .34 .35 .35
Trinidad................... -- 1.46 .17 .15 .14
India...................... -- -- .13 -- 1.59
Composite................ .22 .21 .20 .20 .23
</TABLE>
- ------------
(1) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf
per day in 1994 and in the nine-month periods ended September 30, 1994
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 $1.70 per Mcf in 1992,
$1.57 per Mcf in 1993, $1.27 per Mcf in 1994 and $1.32 per Mcf and $.76
per Mcf in the nine-month periods ended September 30, 1994 and 1995,
respectively, for the volumes described in note (1), net of
transportation costs.
15
<PAGE>
OTHER NATURAL GAS MARKETING VOLUMES AND PRICES
The following table sets forth certain information regarding the
Company's volumes of natural gas delivered under other marketing and
volumetric production payment arrangements, and resulting average per unit
gross revenue and per unit amortization of deferred revenues along with
associated costs during each of the three years in the period ended December
31, 1994 and the nine-month periods ended September 30, 1994 and 1995.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1992 1993 1994 1994 1995
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Volumes (MMcf per day)(1)............ 255 293 324 327 266
Average Gross Revenue ($/Mcf)(2)..... $ 2.62 $ 2.57 $ 2.38 $ 2.41 $ 1.87
Associated Costs ($/Mcf)(3)(4)....... 1.99 2.32 2.06 2.13 1.49
--------- --------- --------- --------- ---------
Margin ($/Mcf)....................... $ 0.63 $ 0.25 $ 0.32 $ 0.28 $ 0.38
========= ========= ========= ========= =========
</TABLE>
- ------------
(1) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf
per day in 1994 and in the nine-month periods ended September 30, 1994
and 1995 delivered under the terms of volumetric production payment and
exchange agreements effective October 1, 1992, as amended.
(2) Includes per unit deferred revenue amortization for the volumes detailed
in note (1) at an equivalent of $2.51 per Mcf in 1992, $2.50 per Mcf in
1993, $2.46 per Mcf in 1994 and $2.46 per Mcf and $2.47 per Mcf in the
nine-month periods ended September 30, 1994 and 1995, respectively.
(3) Includes an average value of $2.37 per Mcf in 1992, $2.20 per Mcf in
1993, $1.92 per Mcf in 1994 and $1.99 per Mcf and $1.50 per Mcf in the
nine-month periods ended September 30, 1994 and 1995, respectively,
including average equivalent wellhead value, any applicable
transportation costs and exchange differentials, for the volumes
detailed in note (1).
(4) Including transportation and exchange differentials.
OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES
The following tables set forth the Company's net proved and proved
developed reserves at December 31, 1993 and 1994, and the changes in the net
proved reserves for the year 1994 as estimated by the Company's engineering
staff. The additional disclosures that include volumes attributable to a
volumetric production payment set forth in the following tables are presented
as additional information and are not intended to represent required
disclosure pursuant to SFAS No. 69 -- "Disclosures about Oil and Gas Producing
Activities."
<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- --------- ---------
<S> <C> <C> <C> <C>
Natural Gas (Bcf)
Net proved reserves at December
31, 1993...................... 1,313.2 271.0 100.5 -- 1,684.7
Additional disclosures:
Volumes attributable to
volumetric production
payment.................. 87.5 -- -- -- 87.5
------------- ------ -------- --------- ---------
Net proved reserves at December
31, 1993, including volumes
attributable to volumetric
production payment............ 1,400.7 271.0 100.5 -- 1,772.2
============= ====== ======== ========= =========
Net proved reserves at December
31, 1993...................... 1,313.2 271.0 100.5 -- 1,684.7
Revisions of previous
estimates................ (17.1) (6.5) 15.0 -- (8.6)
Purchases in place......... 18.8 9.2 -- 29.3 57.3
Extensions, discoveries and
other additions.......... 233.8 50.2 113.9 -- 397.9
Sales in place............. (29.3) (1.0) -- -- (30.3)
Production................. (212.0) (26.3) (23.2) -- (261.5)
------------- ------ -------- --------- ---------
Net proved reserves at December
31, 1994...................... 1,307.4 296.6 206.2 29.3 1,839.5
16
<PAGE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- --------- ---------
<S> <C> <C> <C> <C>
Additional disclosures:
Volumes attributable to
volumetric production
payment.................. 70.9 -- -- -- 70.9
------------- ------ -------- --------- ---------
Net proved reserves at December
31, 1994, including volumes
attributable to volumetric
production payment............ 1,378.3 296.6 206.2 29.3 1,910.4
============= ====== ======== ========= =========
Liquids (MBbl)(1)
Net proved reserves at December
31, 1993...................... 13,172 5,471 2,218 -- 20,861
Revisions of previous
estimates................ 2,179 (177) 455 -- 2,457
Purchases in place......... 358 -- -- 7,617 7,975
Extensions, discoveries and
other additions.......... 5,332 2,848 2,687 -- 10,867
Sales in place............. (257) -- -- -- (257)
Production................. (2,997) (905) (931) (32) (4,865)
------------- ------ -------- --------- ---------
Net proved reserves at December
31, 1994...................... 17,787 7,237 4,429 7,585 37,038
============= ====== ======== ========= =========
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- --------- ---------
<S> <C> <C> <C> <C>
Net proved developed reserves at
Natural Gas (Bcf)
December 31, 1993.......... 1,079.8 250.6 71.4 -- 1,401.8
December 31, 1994.......... 1,128.2 288.3 206.2 -- 1,622.7
Liquids (MBbl)(1)
December 31, 1993.......... 11,165 5,409 1,591 -- 18,165
December 31, 1994.......... 16,770 7,073 4,429 7,585 35,857
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA TOTAL
------------- ------ -------- --------- ---------
<S> <C> <C> <C> <C>
Net proved developed reserves,
including amounts attributable to
volumetric production payment at
Natural Gas (Bcf)
December 31, 1993.......... 1,167.3 250.6 71.4 -- 1,489.3
December 31, 1994.......... 1,199.1 288.3 206.2 -- 1,693.6
Liquids (MBbl)(1)
December 31, 1993.......... 11,165 5,409 1,591 -- 18,165
December 31, 1994.......... 16,770 7,073 4,429 7,585 35,857
</TABLE>
- ------------
(1) Includes crude oil, condensate and natural gas liquids.
Estimates of proved and proved developed reserves at December 31, 1993
and 1994 were based on studies performed by the Company's engineering staff
for reserves in the United States, Canada, Trinidad and India. Opinions by
DeGolyer and MacNaughton, independent petroleum consultants, for the years
ended December 31, 1993 and 1994 covering producing areas containing 65% and
59%, respectively, of proved reserves of the Company on a
net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved
reserves prepared by the Company's engineering staff for the properties
reviewed by DeGolyer and MacNaughton, when compared in total on a net-
equivalent-cubic-feet-of-gas basis, do not differ materially from the
estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and
MacNaughton in the aggregate varied by not more than 5% from those prepared by
the Company's engineering staff. All reports by DeGolyer and MacNaughton were
developed utilizing geological and engineering data provided by the Company.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
17
<PAGE>
natural gas and liquids, including crude oil, condensate and natural gas
liquids, that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the amount and quality of available data and
of engineering and geological interpretation and judgment. As a result,
estimates of different engineers normally vary. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities ultimately recovered. The meaningfulness of such
estimates is highly dependent upon the accuracy of the assumptions upon which
they were based.
In general, the volume of production from oil and gas properties owned by
the Company declines as reserves are depleted. Except to the extent the
Company acquires additional properties containing proved reserves or conducts
successful exploration and development activities, or both, the proved
reserves of the Company will decline as reserves are produced. Volumes
generated from future activities of the Company are therefore highly dependent
upon the level of success in acquiring or finding additional reserves and the
costs incurred in doing so.
ACREAGE
The following tables summarize the Company's developed and undeveloped
acreage at December 31, 1994 and September 30, 1995. Excluded is acreage in
which the Company's interest is limited to owned royalty, overriding royalty
and other similar interests.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
-------------------------- ---------------------------- ----------------------------
GROSS NET GROSS NET GROSS NET
------------ ------------ ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
At December 31, 1994:
United States................... 978,427 637,870 1,952,656 1,705,716 2,931,083 2,343,586
Canada.......................... 501,989 307,996 437,523 353,550 939,512 661,546
India........................... 60,000 18,000 602,207 180,662 662,207 198,662
Trinidad........................ 4,200 3,990 74,851 71,108 79,051 75,098
Other International............. -- -- 13,913,600 11,756,800 13,913,600 11,756,800
------------ ------------ ------------- ------------- ------------- -------------
Total...................... 1,544,616 967,856 16,980,837 14,067,836 18,525,453 15,035,692
============ ============ ============= ============= ============= =============
At September 30, 1995:
United States................... 1,554,024 661,647 2,321,727 1,775,151 3,875,751 2,436,798
Canada.......................... 559,534 335,559 424,302 349,503 983,836 685,062
India........................... 60,000 18,000 602,207 180,662 662,207 198,662
Trinidad........................ 4,200 3,990 74,851 71,108 79,051 75,098
Other International............. -- -- 13,422,400 11,773,100 13,422,400 11,773,100
------------ ------------ ------------- ------------- ------------- -------------
Total...................... 2,177,758 1,019,196 16,845,487 14,149,524 19,023,245 15,168,720
============ ============ ============= ============= ============= =============
</TABLE>
18
DRILLING AND ACQUISITION ACTIVITIES
During the years ended December 31, 1992, 1993 and 1994 and the nine
months ended September 30, 1995 the Company spent approximately $396, $430,
$494 and $401 million, respectively, for exploratory and development drilling
and acquisition of leases and producing properties. The Company drilled,
participated in the drilling of or acquired wells as set out in the table
below for the periods indicated:
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
-------------------------------------------------------- -------------------
1992 1993 1994 1995
---------------- ---------------- ---------------- -------------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ------- ----- ------- ----- ------- ------ ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development Wells Completed
Domestic
Gas........................ 484 399.06 352 279.00 308 244.23 99 77.78
Oil........................ 19 10.80 45 19.01 34 29.57 36 32.06
Dry........................ 64 56.12 59 46.83 41 32.15 38 30.80
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 567 465.98 456 344.84 383 305.95 173 140.64
International
Gas........................ 2 2.00 227 190.10 250 190.30 116 107.66
Oil........................ 13 11.70 4 3.50 11 5.10 13 8.21
Dry........................ 5 4.05 11 7.60 13 11.50 11 8.38
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 20 17.75 242 201.20 274 206.90 140 124.25
----- ------- ----- ------- ----- ------- ----- -------
Total Development............... 587 483.73 698 546.04 657 512.85 313 264.89
----- ------- ----- ------- ----- ------- ----- -------
Exploratory Wells Completed
Domestic
Gas........................ 11 8.72 14 10.03 13 9.80 4 2.52
Oil........................ 1 .40 3 2.50 3 2.57 3 2.63
Dry........................ 16 13.42 32 22.08 23 18.17 6 4.47
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 28 22.54 49 34.61 39 30.54 13 9.62
International
Gas........................ 7 5.75 14 11.40 9 7.90 2 1.24
Oil........................ 4 3.69 2 .90 1 .50 2 2.00
Dry........................ 4 2.85 10 7.35 14 12.50 5 3.70
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 15 12.29 26 19.65 24 20.90 9 6.94
----- ------- ----- ------- ----- ------- ----- -------
Total Exploratory............... 43 34.83 75 54.26 63 51.44 22 16.56
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 630 518.56 773 600.30 720 564.29 335 281.45
Wells in Progress at end of period... 82 60.75 82 61.09 45 28.79 53 38.72
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 712 579.31 855 661.39 765 593.08 388 320.17
===== ======= ===== ======= ===== ======= ===== =======
Wells Acquired
Gas............................. 641 597.29* 44 26.44* 41 40.90* 271 97.37*
Oil............................. 28 25.80* -- 12.80* 60 38.99* 5 .93*
----- ------- ----- ------- ----- ------- ----- -------
Total.................... 669 623.09 44 39.24 101 79.89 276 98.30
===== ======= ===== ======= ===== ======= ===== =======
</TABLE>
- ------------
* Includes the acquisition of additional interests in certain wells in which
the Company previously held an interest.
All of the Company's drilling activities are conducted on a contract
basis with independent drilling contractors. The Company owns no drilling
equipment.
19
<PAGE>
SELECTED CONSOLIDATED FINANCIAL AND OPERATING INFORMATION
The following table sets forth a summary of selected consolidated
financial and operating information for the Company for each of the five years
in the period ended December 31, 1994 and the nine-month periods ended
September 30, 1994 and 1995. This information should be read in conjunction
with the consolidated financial statements of the Company and related notes
thereto incorporated by reference herein (see "Incorporation of Certain
Documents by Reference") and "Management's Discussion and Analysis of
Financial Condition and Results of Operations" included elsewhere in this
Prospectus. Financial information for each of the five years in the period
ended December 31, 1994 has been derived from audited financial statements.
Financial information for the nine-month periods ended September 30, 1994 and
1995 has been derived from unaudited financial statements. The interim data
reflects all adjustments which, in the opinion of the management of the
Company, are necessary to present fairly such information for the interim
periods. Results of the nine-month periods are not necessarily indicative of
the results expected for a full year or any other interim period.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------------------------------------------- ------------------------
1990 1991 1992 1993 1994 1994 1995
----------- ----------- ----------- ----------- ----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF INCOME DATA:
Net operating revenues
Natural gas...................... $ 301,645 $ 321,603 $ 388,988 $ 505,162 $ 489,893 $ 365,654 $ 332,015
Crude oil, condensate and natural
gas liquids.................... 66,165 62,836 58,927 55,834 76,338 52,632 90,342
Gains on sales of reserves and
related assets................. 31,802 14,983 6,037 13,318 54,014 52,212 62,546
Other............................ 3,525 3,166 5,074 6,706 5,578 3,842 7,439
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total........................ 403,137 402,588 459,026 581,020 625,823 474,340 492,342
Operating expenses
Lease and well................... 43,806 49,922 49,406 59,344 60,384 44,782 52,918
Exploration...................... 35,031 31,470 33,278 36,921 41,811 29,647 31,590
Dry hole......................... 12,986 14,698 10,764 18,355 17,197 10,803 8,586
Impairment of unproved oil and
gas properties................. 20,571 12,791 15,136 20,467 24,936 17,364 20,453
Depreciation, depletion and
amortization................... 155,877 160,885 179,839 249,704 242,182 181,645 157,875
General and administrative....... 38,254 36,216 36,648 45,274 51,418 38,050 41,186
Taxes other than income.......... 22,966 18,222 28,346 35,396 28,254 22,010 25,606
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total........................ 329,491 324,204 353,417 465,461 466,182 344,301 338,214
----------- ----------- ----------- ----------- ----------- ----------- -----------
Operating income..................... 73,646 78,384 105,609 115,559 159,641 130,039 154,128
Other income (expense)............... (2,153) (3,215) (3,476) 6,635 2,783 2,238 (1,143)
Interest expense (net of interest
capitalized)....................... 36,879 29,500 22,289 9,921 8,489 6,111 8,810
----------- ----------- ----------- ----------- ----------- ----------- -----------
Income before income taxes........... 34,614 45,669 79,844 112,273 153,935 126,166 144,175
Income tax provision (benefit)(1).... (10,854) (2,247) (17,736) (25,752)(2) 5,937(3) 20,728 33,444(4)
----------- ----------- ----------- ----------- ----------- ----------- -----------
Net income........................... $ 45,468 $ 47,916 $ 97,580 $ 138,025 $ 147,998 $ 105,438 $ 110,731
=========== =========== =========== =========== =========== =========== ===========
Earnings per share of common
stock(5)........................... $ .30 $ .32 $ .63 $ .86 $ .93 $ .66 $ .69
=========== =========== =========== =========== =========== =========== ===========
Average number of common shares(5)... 151,800 151,800 154,533 159,996 159,845 159,826 159,951
=========== =========== =========== =========== =========== =========== ===========
BALANCE SHEET DATA (AT PERIOD END):
Net oil and gas properties........... $ 1,305,136 $ 1,339,666 $ 1,468,011 $ 1,546,045 $ 1,684,811 $ 1,637,762 $ 1,843,150
Total assets......................... 1,417,939 1,455,608 1,731,012 1,811,162 1,861,867 1,855,819 2,109,971
Long-term debt
Affiliate........................ 277,918 132,836 --(6) -- 25,000 25,000 16,320
Other............................ 140,442 289,556 150,000(6) 153,000 165,337 158,862 247,552
Deferred revenue..................... -- -- 301,395 227,528 184,183 195,109 224,085
Shareholders' equity................. 610,042 643,185 826,986(6) 933,073 1,043,419 1,019,712 1,140,295
20
OPERATING DATA:
Wellhead Volumes and Prices
Natural Gas Volumes (MMcf per day)
United States(7)................. 437 466 534 649 613 609 534
Canada........................... 18 25 30 58 73 71 75
Trinidad......................... -- -- -- 2 63 63 110
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total(7)..................... 455 491 564 709 749 743 719
=========== =========== =========== =========== =========== =========== ===========
Average Natural Gas Prices ($/Mcf)
United States.................... $ 1.51 $ 1.38 $ 1.61 $ 1.97 $ 1.71 $ 1.79 $ 1.33
Canada........................... 1.47 1.32 1.18 1.34 1.42 1.51 .95
Trinidad......................... -- -- -- .89 .93 .93 .97
Composite.................... 1.51 1.37 1.58 1.92 1.62 1.69 1.23
Crude/Condensate Volumes (MBbl per
day)
United States.................... 5.8 5.9 6.3 6.6 8.0 7.5 9.1
Canada........................... 2.4 2.3 2.2 2.2 2.0 1.9 2.4
Trinidad......................... -- -- -- .1 2.5 2.6 4.8
India............................ -- -- -- -- .1 -- 2.3
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total........................ 8.2 8.2 8.5 8.9 12.6 12.0 18.6
=========== =========== =========== =========== =========== =========== ===========
Average Crude/Condensate Prices
($/Bbl)
United States.................... $21.95 $19.24 $18.29 $16.96 $16.06 $15.64 $17.20
Canada........................... 21.01 17.58 16.80 14.63 14.05 13.72 16.31
Trinidad......................... -- -- -- 14.36 15.50 15.20 16.16
India............................ -- -- -- -- 15.70 -- 16.82
Composite.................... 21.67 18.78 17.90 16.37 15.62 15.24 16.77
Natural Gas Liquids Volumes (MBbl per
day)
United States.................... .4 .3 .3 .2 .3 .2 1.2
Canada........................... -- .3 .4 .4 .4 .5 .3
Total........................ .4 .6 .7 .6 .7 .7 1.5
Average Natural Gas Liquids Prices
($/Bbl)
United States.................... $10.59 $10.79 $11.56 $13.85 $12.45 $12.50 $11.76
Canada........................... -- 12.48 10.05 9.46 8.45 7.86 9.69
Composite.................... 10.59 11.64 10.69 11.12 9.90 9.43 11.27
</TABLE>
- ------------
(1) Includes benefits of approximately $17 million, $43 million, $65 million
and $36 million in 1991, 1992, 1993 and 1994, respectively, and $29
million and $16 million in the nine-month periods ended September 30, 1994
and 1995, respectively, relating to tight gas sand federal income tax
credits and $25 million and $7 million in 1990 and 1991, respectively,
associated with the utilization of a net operating loss carryforward.
(2) Includes a benefit of $12 million from the reduction of the Company's
deferred federal income tax liability resulting from a reevaluation of
deferred tax requirements partially offset by an approximate $7 million
predominantly non-cash charge primarily to adjust the Company's
accumulated deferred income tax liability for the increase in the
corporate federal income tax rate from 34% to 35%.
(3) Includes a benefit of approximately $8 million related to reduced
estimated state income taxes and certain franchise taxes, a portion of
which is treated as income tax under SFAS No. 109 -- "Accounting for Income
Taxes", and a $5 million benefit from the reduction of the Company's
deferred federal income tax liability resulting from a reevaluation of
deferred tax requirements.
(4) Includes a $12 million benefit associated with the successful resolution
on audit of federal income taxes for certain prior years.
(5) In May 1994, the Board of Directors declared a two-for-one split of the
Company's Common Stock to be effected as a non-taxable dividend of one
share for each share outstanding. Shares were issued on June 15, 1994 to
shareholders of record as of May 31, 1994. All share and per share amounts
presented herein are reflected on a post-split basis.
(6) In August 1992, the Company completed the sale of an additional 8.2
million shares of Common Stock resulting in aggregate net proceeds to the
Company of approximately $112 million used primarily to repay long-term
debt. In September 1992, the Company completed the sale of a volumetric
production payment, resulting in net proceeds of approximately $327
million used to repay long-term debt and for other general corporate
purposes.
(7) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per
day in 1994 and in the nine-month periods ended September 30, 1994 and
1995 delivered under the terms of a volumetric production payment
effective October 1, 1992, as amended.
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following review of operations for each of the three years in the
period ended December 31, 1994 and for the nine-month periods ended September
30, 1994 and 1995 should be read in conjunction with the consolidated
financial statements of the Company and notes thereto and other financial data
incorporated by reference herein. See "Incorporation of Certain Documents by
Reference."
RESULTS OF OPERATIONS
NET OPERATING REVENUES
Wellhead volume and price statistics for the specified periods were as
follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------- --------------------
1992 1993 1994 1994 1995
---------- ---------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C>
Natural Gas Volumes (MMcf per
day)
North America(1)........... 564 707 686 680 609
Trinidad................... -- 2 63 63 110
---------- ---------- ---------- --------- ---------
Total................. 564 709 749 743 719
========== ========== ========== ========= =========
Average Natural Gas Prices
($/Mcf)
North America(2)........... $ 1.58 $ 1.92 $ 1.68 $ 1.76 $ 1.28
Trinidad................... -- .89 .93 .93 .97
Composite............. 1.58 1.92 1.62 1.69 1.23
Crude/Condensate Volumes (MBbl
per day)
North America.............. 8.5 8.8 10.0 9.4 11.5
Trinidad................... -- .1 2.5 2.6 4.8
India...................... -- -- .1 -- 2.3
---------- ---------- ---------- --------- ---------
Total................. 8.5 8.9 12.6 12.0 18.6
========== ========== ========== ========= =========
Average Crude/Condensate Prices
($/Bbl)
North America.............. $ 17.90 $ 16.39 $ 15.65 $ 15.25 $ 17.01
Trinidad................... -- 14.36 15.50 15.20 16.16
India...................... -- -- 15.70 -- 16.82
Composite............. 17.90 16.37 15.62 15.24 16.77
</TABLE>
- ------------
(1) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf
per day in 1994 and in the nine-month periods ended September 30, 1994
and 1995 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 $1.70 per Mcf in 1992,
$1.57 per Mcf in 1993, $1.27 per Mcf in 1994 and $1.32 per Mcf and $.76
per Mcf in the nine-month periods ended September 30, 1994 and 1995,
respectively, for the volumes detailed in note (1), net of
transportation costs.
NINE MONTHS 1995 COMPARED TO NINE MONTHS 1994. During the first nine
months of 1995, net operating revenues increased $18 million to $492 million
as compared to the same period in 1994.
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. In addition, 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 per day during the first nine months of 1995
compared to approximately 110 MMcf per day during the
22
same period in 1994 due to significantly lower United States wellhead natural
gas prices. In addition, the impact of the 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 refocused
its 1995 drilling activity away from natural gas deliverability and toward
natural gas reserve enhancement and crude oil exploitation in the United
States in response to the significant decline in United States natural gas
prices in recent periods. Wellhead crude oil and condensate average prices
increased 10% adding approximately $8 million to net operating revenues
compared to 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
production on stream offshore India, and higher volumes offshore Trinidad and
in North America.
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 volumetric production payment related
margins 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 resulted 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
compared to a $2 million loss during the same period in 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. See "Trading Transactions."
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 $8.4 million increase in net operating
revenues in the first nine months of 1995 over the amount realized from the
exchanged fuel supply and purchase contracts in the same period of 1994. See
"Relationship Between the Company and Enron Corp. -- Contractual Agreements."
Gains on sales of reserves and related assets during the first nine
months of 1995 increased $10 million to $63 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.
1994 COMPARED TO 1993. During 1994, net operating revenues increased to
$626 million, up $45 million as compared to 1993.
Average wellhead natural gas volumes increased approximately 6% compared
to 1993 primarily reflecting the effects of development activities offshore
Trinidad and in Canada partially offset by voluntary curtailments of
production in the United States in 1994. The volume reductions in the United
States as a result of voluntary curtailments were more than offset by the new
natural gas deliveries from the Kiskadee field offshore Trinidad and increased
deliveries in Canada. The increase in wellhead natural gas volumes added $28
million to net operating revenues. Average wellhead natural gas prices were
down significantly from 1993 reducing net operating revenues by
23
approximately $83 million. This 16% reduction in average wellhead natural gas
prices reflects the overall decline in the United States natural gas markets
during the last half of 1994 and increased volumes offshore Trinidad sold
under a long-term contract at a price considerably below North America spot
market prices. A 42% increase in wellhead crude oil and condensate volumes
over 1993 added $22 million to net operating revenues primarily reflecting
development activities offshore Trinidad and increased production in the
United States. A 5% decrease in wellhead crude oil and condensate average
prices decreased net operating revenues by approximately $3 million.
Other marketing activities associated with sales and purchases of natural
gas, natural gas and crude oil price swap transactions, other commodity price
hedging of natural gas and crude oil prices utilizing NYMEX-related commodity
market transactions, and margins relating to the volumetric production payment
added $50 million to net operating revenues during 1994. This increase of $41
million from the same period in 1993 primarily results from a gain of $11
million on natural gas commodity price hedging activities utilizing
NYMEX-related commodity market transactions in 1994 versus an $18 million loss
during 1993 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 $.26 per Mcf. The average price received for these transactions
decreased $.19 per Mcf. Related other natural gas marketing volumes increased
10%.
Gains on sales of selected oil and gas reserves and related assets were
$54 million in 1994 as compared to $13 million in 1993. While the quantity of
equivalent reserves sold in 1994 was slightly less than 1993, higher average
proceeds received per equivalent unit in 1994 as compared to 1993 primarily
contributed to the increased gain recognition. In continuing its strategy of
fully utilizing its assets in optimizing profitability, cash flow and return
on investments, the Company expects to continue the sale of similar properties
from time to time.
1993 COMPARED TO 1992. During 1993, net operating revenues increased to
$581 million, up $122 million as compared to 1992.
Average wellhead natural gas volumes increased approximately 26% compared
to 1992 primarily reflecting the effects of exploration and development
activities relating to tight gas sand formations. Wellhead natural gas
delivered volumes were curtailed less during portions of 1993 than for the
comparable periods in 1992 due to the significant increases realized in
wellhead natural gas prices in 1993. Average wellhead natural gas prices were
up approximately 22% in 1993 over those received in 1992, adding approximately
$87 million to net operating revenues. Increases in wellhead natural gas
volumes in 1993 added $83 million to net operating revenues compared to 1992.
Average wellhead crude oil and condensate prices in 1993 were down 9% compared
to 1992, reducing net operating revenues by $5 million. Increases in wellhead
crude oil and condensate volumes in 1993 added approximately $2 million to net
operating revenues compared to 1992.
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 $8 million to net operating revenues during 1993.
This decrease of $54 million from 1992 primarily results from shrinking
margins associated with sales under long-term fixed price contracts and
amortization of volumetric production payment deferred revenue due to
increases in market responsive natural gas prices associated with volumes
supplying these dispositions and losses on natural gas commodity price hedging
activities utilizing NYMEX-related commodity market transactions. 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, increased
$.33 per Mcf. Related other natural gas marketing volumes increased 15%.
24
The impact of the other marketing activities, a substantial portion of
which serve as hedges of commodity price risks for a portion of wellhead
deliveries for the respective periods, were more than offset by reductions in
revenues associated with market responsive prices for wellhead deliveries
during those periods.
OPERATING EXPENSES
NINE MONTHS 1995 COMPARED TO NINE MONTHS 1994. 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 including the initiation of operations in India in
late December 1994 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. Depreciation, depletion and
amortization ("DD&A") expense decreased $24 million to $158 million reflecting
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
reduction included in 1994 associated with state franchise taxes and higher
production related taxes associated with new production in 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.
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.
1994 COMPARED TO 1993. During 1994, total operating expenses of $466
million were approximately $1 million higher than the $465 million incurred in
1993. Lease and well expenses of $60 million were approximately $1 million
higher than 1993 primarily due to increased expenses related to new operations
offshore Trinidad partially offset by cost reductions in North America.
Exploration expenses of $42 million increased $5 million from the previous
year primarily due to an increased level of exploration activities. Impairment
of unproved oil and gas properties increased $4 million from 1993 primarily
due to impairments associated with certain offshore Gulf of Mexico leases.
DD&A expense decreased from $250 million in 1993 to $242 million in 1994
reflecting a $.09 per Mcfe decrease in the average DD&A rate to $.80 per Mcfe.
The rate decrease is primarily due to increased production from offshore
Trinidad at an average DD&A rate significantly less than the North America
operations DD&A rate and a $.03 per Mcfe reduction in the North America
operations DD&A rate. General and administrative expenses increased $6 million
to $51 million primarily due to overall higher costs associated with expanded
international and domestic operations. Taxes other than income decreased
approximately $7 million from 1993 primarily due to lower taxable United
States wellhead volumes and prices and reductions included in 1994 related to
revisions of certain prior year production taxes. Included in 1994 and 1993
are benefits associated with reductions in state franchise taxes of $4 million
and $3 million, respectively. The Company continues to benefit from certain
state severance tax exemptions allowed on high cost natural gas volumes.
25
Total per unit operating costs for lease and well expense, DD&A, general
and administrative expense, interest expense, and taxes other than income
decreased $.14 per Mcfe, averaging $1.29 per Mcfe during 1994 compared to
$1.43 per Mcfe for 1993. The decrease was primarily due to per unit reductions
in DD&A and taxes other than income as discussed above.
1993 COMPARED TO 1992. During 1993, total operating expenses of $465
million were $112 million higher than the $353 million incurred in 1992. Lease
and well expenses increased approximately $10 million primarily due to
expanded domestic and international operations. Exploration expenses increased
approximately $4 million primarily due to increased exploration activities in
North America. An unsuccessful Gulf of Mexico well added nearly $4 million to
dry hole expenses and a related $3 million to lease impairments in 1993. Dry
hole expenses also reflect the impact of increased drilling activity outside
North America. DD&A expense increased $70 million to $250 million reflecting
an increase in production volumes and an average DD&A rate increase from $.79
per Mcfe in 1992 to $.89 per Mcfe for 1993. The DD&A rate increase is
primarily due, as expected, to factors associated with the tight gas sands
drilling program which costs are being more than offset by benefits realized
in the form of tight gas sand federal income tax credits and certain state
severance tax exemptions. General and administrative expenses increased almost
$9 million to $45 million primarily reflecting cost reductions included in
1992 related to changes associated with certain employee compensation plans
and overall higher costs in 1993 due to an expansion of domestic and
international operations. Taxes other than income increased $7 million
primarily due to increased production volumes and revenues in 1993, partially
offset by continuing benefits associated with certain state severance tax
exemptions allowed on high cost natural gas volumes and a $3 million reduction
of state franchise taxes resulting from refunds of prior year payments
received in 1993.
Total per unit operating costs for lease and well expense, DD&A, general
and administrative expense, interest expense, and taxes other than income
increased $.03 per Mcfe, averaging $1.43 per Mcfe during 1993 compared to
$1.40 per Mcfe for 1992. The total increase was associated with DD&A expense
which was up $.10 per Mcfe as noted above being partially offset by a
reduction of $.07 Mcfe in all other costs.
OTHER INCOME
Other income for 1993 includes $4 million in interest income associated
with the investment of funds temporarily surplus to the Company and $4 million
associated with settlements related to the termination of certain long-term
natural gas contracts.
INTEREST EXPENSE
Net interest expense for the first nine months of 1995 was up $3 million
as compared to the same period in 1994 reflecting primarily a higher level of
debt outstanding during the 1995 period.
Net interest expense in 1994 decreased approximately $1 million to $8
million as compared to 1993 primarily due to favorable interest rates on new
financing acquired by a subsidiary of the Company for operations offshore
Trinidad and the retirement of higher interest rate debt. The estimated fair
value of outstanding interest rate swap agreements at December 31, 1994 was a
negative $0.5 million based on termination values obtained from third parties.
Net interest expense decreased $12 million, or 55%, to $10 million in
1993 as compared to 1992 reflecting the repayment of a substantial portion of
the Company's long-term debt in 1992 with proceeds from the sale of common
stock in August 1992 and the sale of a volumetric production payment in
September 1992. The estimated fair value of outstanding interest rate swap
agreements at December 31, 1993 was a negative $3.3 million based upon
termination values obtained from third parties.
26
INCOME TAXES
Income tax provision increased $13 million for the 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.
Income tax provision in 1994 includes a benefit of approximately $36
million associated with tight gas sand federal income tax credit utilization,
a benefit of approximately $8 million related to reduced estimated state
income taxes and a portion of certain franchise taxes which is treated as
income tax under SFAS No. 109, and a $5 million benefit from the reduction of
the Company's deferred federal income tax liability resulting from a
reevaluation of deferred tax requirements.
Income tax benefit in 1993 includes a benefit of approximately $65
million associated with tight gas sand federal income tax credit utilization,
an approximate $7 million predominantly one-time non-cash charge recorded in
the third quarter of 1993 primarily to adjust the Company's accumulated
deferred federal income tax liability for the increase in the corporate
federal income tax rate from 34% to 35% and a $12 million benefit from the
reduction of the Company's deferred federal income tax liability resulting
from a reevaluation of deferred tax requirements.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW
The primary sources of cash for the Company during the nine-month period
ended September 30, 1995 and for each of the years in the three-year period
ended December 31, 1994 included funds generated from operations, the sale of
Common Stock, the sale of a volumetric production payment, proceeds from the
sale of selected oil and gas reserves and related assets and the issuance of
debt. Primary cash outflows during these periods included funds used in
operations, exploration and development expenditures, dividends and the
repayment of debt.
Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is generally derived by adjusting net
income to eliminate the effects of depreciation, depletion and amortization,
impairment of unproved oil and gas properties, deferred taxes, gains on sales
of oil and gas reserves and related assets, certain other miscellaneous
non-cash amounts, except for amortization of deferred revenue, and exploration
and dry hole expenses. However, based on the continuing practice of the
Company of selling selected oil and gas reserves and related assets in
furtherance of its strategy of fully utilizing its assets in optimizing
profitability, cash flow and return on investments, it believes that net
proceeds from these transactions should also be considered as available
discretionary cash flow and accordingly is presenting those values for all
periods shown. 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. The Company generated
discretionary cash flow of approximately $514 million in 1994, $521 million in
1993 and $346 million in 1992. The 1993 amount includes $50 million associated
with a federal income tax refund resulting from the settlement on audit of
federal income taxes paid in certain prior years.
Net operating cash flows for the first nine months of 1995 and for each
of the years in the three-year period ended December 31, 1994 have been
revised to reflect proceeds from the sale of a volumetric production payment
during 1992 and the elimination of the related amortization of deferred
revenues as net operating cash flows rather than as investing cash flows as
previously reported. 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. Net
operating cash flows were approximately $383 million in 1994, $406 million in
1993, and
27
$608 million in 1992. Decreased 1994 net operating cash flows were primarily
due to the receipt in 1993 of a refund on settlement on audit of federal
income taxes paid in certain prior years. Decreased 1993 net operating cash
flows were primarily due to the receipt in 1992 of $327 million of proceeds
from the sale of a volumetric production payment, increased net operating
revenues and a decrease in provision for current taxes resulting from both
increased tight gas sand federal income tax credit utilization and the receipt
of a refund on settlement on audit of federal income taxes paid in certain
prior years. In accordance with the requirements of SFAS No. 95 -- "Statement
of Cash Flows", net proceeds from the sale of selected oil and gas reserves
and related assets are not included in the determination of net operating cash
flows.
SALE OF SELECTED OIL AND GAS RESERVES AND RELATED ASSETS
During the first nine months of 1995, the Company received proceeds of
$101 million from the sale of selected oil and gas reserves and related assets
compared to $82 million received in the first nine months of 1994. Taxable
gains from the first nine months of 1995 sales generated income taxes of $24
million leaving, net proceeds of $77 million. During 1994, the Company
received proceeds of $91 million from the sale of selected oil and gas
reserves and related assets compared to $42 million received in 1993. While
the quantity of equivalent reserves sold in 1994 was slightly less than 1993,
higher average proceeds received per equivalent unit of reserves sold in 1994
as compared to 1993 resulted in significantly higher 1994 proceeds. Taxable
gains resulting from the 1994 sales generated income taxes of $20 million,
leaving net proceeds of $71 million. Taxable gains resulting from such sales
in 1993 generated federal income taxes of $8 million, leaving net proceeds of
$34 million.
SALE OF VOLUMETRIC PRODUCTION PAYMENT
In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership. Under the terms of the production
payment agreements, the Company conveyed a real property interest in
approximately 124 Bcfe (136 TBtu) of certain natural gas and other
hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were
amended providing for the extension of the original term of the volumetric
production payment through March 31, 1999 and including a revised schedule of
daily quantities of hydrocarbons to be delivered which is approximately
one-half of the original schedule. The revised schedule will total
approximately 89.1 Bcfe (97.8 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu)
remaining to be delivered under the original agreement. Daily quantities of
hydrocarbons no longer required to be delivered under the revised schedule
during the period from October 1, 1993 through June 30, 1996 are available for
sale by the Company. The Company retains responsibility for its working
interest share of the cost of operations. In accordance with generally
accepted accounting principles, the Company accounted for the proceeds
received in the transaction as deferred revenue which is being amortized into
revenue and income as natural gas and other hydrocarbons are produced and
delivered to the purchaser during the term, as revised, of the volumetric
production payment thereby matching those revenues with the depreciation of
asset values which remained on the balance sheet following the sale and the
operating expenses incurred for which the Company retained responsibility. The
Company expects the above transaction, as amended, to have minimal direct
impact on future earnings. However, cash made available by the sale of the
volumetric production payment has provided considerable financial flexibility
for the pursuit of investment alternatives.
28
<PAGE>
EXPLORATION AND DEVELOPMENT EXPENDITURES
The table below sets out components of actual exploration and development
expenditures for the years ended December 31, 1992, 1993 and 1994, along with
those estimated for the year 1995 and actual components of exploration and
development expenditures for the nine-month periods ended September 30, 1994
and 1995.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30,
--------------------
EXPENDITURE CATEGORY 1992 1993 1994 1994 1995
- -------------------- --------- --------- --------- --------- ---------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Capital
Drilling and Facilities......... $ 260 $ 331 $ 342 $ 257 $ 225
Leasehold Acquisitions.......... 23 29 52 32 17
Producing Property
Acquisitions.................. 65 9 34 14 114
Capitalized Interest and
Other......................... 14 14 14 10 9
--------- --------- --------- --------- ---------
Total...................... 362 383 442 313 365
Exploration Expenses................. 44 55 59 41 40
--------- --------- --------- --------- ---------
Total................................ $ 406 $ 438 $ 501 $ 354 $ 405
========= ========= ========= ========= =========
</TABLE>
Exploration and development expenditures for the first nine months of
1995 increased $51 million compared to the same period in 1994, and primarily
reflect the acquisitions of selected properties to complement existing United
States producing areas.
Exploration and development expenditures increased $63 million, or 14%,
in 1994 compared to 1993. The increase primarily reflects the acquisitions of
selected properties to compliment existing North America producing areas and
the addition of new international activities in India. See
"Business -- Exploration and Production" for additional information detailing
the specific geographic locations of the Company's drilling programs and
"-- Outlook" below for a discussion related to future exploration and
development expenditure plans.
Exploration and development expenditures in 1993 increased to $438
million, an 8% increase, as compared to the $406 million expended in 1992. The
increase was attributable to increased domestic drilling activity with reduced
emphasis on development drilling expenditures associated with tight gas sand
formations. The Company also implemented its first development program outside
of North America during 1993, installing a jacket, platform and production
facilities and initiating natural gas production from the Kiskadee field
offshore the southeast coast of Trinidad.
HEDGING TRANSACTIONS
With the objective of enhancing the certainty of future revenues, the
Company has, as of October 23, 1995, entered into hedging transactions for
approximately 400 BBtu per day (approximately 381 MMcf per day) and 529 BBtu
per day (approximately 504 MMcf per day) 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
transactions involve NYMEX-based commodity price swap agreements totaling 260
BBtu per day at an average price of $1.98 per MMBtu and 447 BBtu per day at an
average price of $2.00 per MMBtu for the last three months of 1995 and the
year 1996, respectively. The remaining hedge transactions of 140 BBtu per day
and 82 BBtu per day 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 per day 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 per day 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
29
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 also may close out any
portion of the existing or yet to be entered into hedges as determined
appropriate by management of the Company.
TRADING TRANSACTIONS
Subsequent to September 30, 1995, the Company sold call options with a
notional volume of 50 BBtu per day at an average price of $2.10 per MMBtu for
the period January through December, 1996.
FINANCING
The Company's long-term debt-to-total-capital ratio was 19%, 15% and 14%
as of September 30, 1995 and December 31, 1994 and 1993, respectively. The
Company has entered into an agreement with Enron Corp. pursuant to which the
Company may borrow funds from Enron Corp. at a representative market rate of
interest on a revolving basis. During 1994, there were no funds borrowed by
the Company under this agreement. During the first nine months of 1995, the
average of the daily balances of funds borrowed by the Company under the
agreement was $2.3million, and the balance at September 30, 1995 was $16.3
million. Under a promissory note effective January 1, 1993 at a fixed interest
rate of 7%, the Company may advance funds temporarily surplus to the Company
to Enron Corp. for investment purposes. Daily outstanding balances of funds
advanced to Enron Corp. under the note averaged $200,000 during the first nine
months of 1995 and $69 million during 1994 with no balance outstanding at
December 31, 1994 or September 30, 1995. There was a balance of $7 million
outstanding at December 31, 1994 under a commercial paper program initiated in
1990. Proceeds from the commercial paper program were used to fund current
transactions. During 1994, total long-term debt increased $37 million to $190
million as a result of $23 million of new borrowings related to certain
international drilling activities, a $7 million increase in commercial paper,
and the recording of an $8 million capital lease obligation. The estimated
fair value of the Company's long-term debt, including current maturities of $2
million and $30 million, at December 31, 1994 and 1993 was $186 million and
$192 million, respectively, based upon quoted market prices and, where such
prices were not available, upon interest rates currently available to the
Company at year end.
OUTLOOK
Uncertainty continues to exist as to the direction of future North
America natural gas price trends and there is a wide divergence in the
opinions held by some in the industry. However, recent history would tend to
support, and it seems there is emerging among a larger number of industry
representatives somewhat of a consensus, that natural gas prices will remain
below parity with crude oil, condensate and natural gas liquids for some time.
This situation is being impacted by improvements in the technology used in
drilling and completing oil and gas wells that are tending to mitigate the
impacts of fewer oil and gas wells being drilled, the deregulation of the
natural gas market under Federal Energy Regulatory Commission Order 636 and
subsequent related orders, and improvements being realized in the availability
and utilization of natural gas storage capacity. However, the continually
increasing recognition of natural gas as a more environmentally friendly
source of energy along with the availability of significant domestically
sourced supplies should result
30
in further increases in demand and a supporting/strengthening of the overall
natural gas market over time. Being primarily a natural gas producer, the
Company is more significantly impacted by changes in natural gas prices than
by changes in crude oil and condensate prices. Based on the portion of the
Company's anticipated natural gas volumes for which prices have not, in
effect, been hedged using NYMEX-related commodity market transactions,
long-term marketing contracts and the sale of a volumetric production payment,
the Company's net income and cash flow sensitivity to changing natural gas
prices is approximately $4.0 million for each $.10 per Mcf change in average
wellhead natural gas prices. Using various commodity price hedging mechanisms,
the Company has, in effect, locked in prices for an average of about 50% of
its anticipated wellhead natural gas volumes and about 30% of its anticipated
wellhead crude oil and condensate volumes for the year 1995 and about 65% of
its anticipated wellhead natural gas volumes and about 40% of its anticipated
wellhead crude oil and condensate volumes for the year 1996. The percentage of
volumes hedged may change during the remainder of 1995 and will change in
future years.
Other factors representing positive impacts that are more certain
continue to hold good potential for the Company in future periods. While the
drilling qualification period for the tight gas sand federal income tax credit
expired on December 31, 1992, the Company has continued in 1995, and should
continue in the future, to realize significant benefits associated with
production from wells drilled during the qualifying period as it will be
eligible for the federal income tax credit through the year 2002. However, all
other factors remaining equal, the annual benefit, which was $36 million in
1994 and is estimated to be approximately $21 million for 1995, is expected to
continue to decline in future periods as production from the qualified wells
declines. The drilling qualification period for a certain state severance tax
exemption available on qualifying high-cost natural gas revenues continues
through August 1996 in its current form and in a modified and somewhat reduced
form from that point through August 2002. Consequently, new qualifying
production will be added prospectively to that presently qualified. Other
natural gas marketing activities are also expected to continue to contribute
meaningfully to financial results. The Company completed a fairly significant
restructure of its other natural gas marketing portfolio during 1992 with the
sale of a volumetric production payment of approximately 124 Bcfe (136 TBtu)
for $326.8 million that was subsequently revised in 1993 and elimination of
most delivery obligations under four long-term fixed price marketing
contracts. The proceeds from the sale of the volumetric production payment
added substantially to the financial flexibility of the Company supporting
future development while the combined effect of all elements of the
restructuring on net income has not been, and will not in the future be,
significant. These factors are expected to contribute significantly to
earnings, cash flow, and the ability of the Company to pursue the continuation
of an active exploration, development and selective acquisition program.
The Company plans to continue to focus a substantial portion of its
development and certain exploration expenditures in its major producing areas
in North America. However, based on the continuing uncertainty associated with
North America natural gas prices and the continuing weakness in that market,
and as a result of the recent success realized offshore Trinidad and
opportunities available to the Company in conjunction with the recent signing
of agreements in India, the Company anticipates expending an increasing
portion of its available funds in the further development of these
opportunities. In addition, the Company expects to include limited but
meaningful exploratory exposure in other areas outside of North America in its
expenditure plans and will continue to evaluate the potential for involvement
in other exploitation type opportunities. The continuation of expenditures in
other areas outside of North America in the near term is expected to be
primarily for the evaluation of conventional oil and gas exploration and
exploitation opportunities in the U.K. North Sea and China, respectively, and
coalbed methane recovery prospects in Australia and China. Other prospects in
various locations will also attract the expenditure of some funds. (See
"Business -- Exploration and Production" for additional information detailing
the specific geographic locations of the related drilling programs). The
Company continues to pursue a strategy of funding
31
exploration, development and acquisition activities primarily from available
internally generated cash flow.
The level of exploration and development expenditures will vary in future
periods depending on energy market conditions and other related economic
factors. Based upon existing economic and market conditions, the Company
believes net operating cash flow and available financing alternatives will be
sufficient to fund its net investing cash requirements for the near term.
However, the Company has significant flexibility with respect to its financing
alternatives and adjustment of its exploration and development expenditure
plans as circumstances warrant. While the Company has certain continuing
commitments associated with expenditure plans related to operations in India,
they are not anticipated to be material when considered in relation to the
total financial capacity of the Company.
OTHER
The cost of environmental compliance has not been material to the
Company.
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.
32
<PAGE>
MANAGEMENT
The current directors and executive officers of the Company and their
names and ages are as follows:
NAME AGE POSITION
---- --- --------
Forrest E. Hoglund.................. 62 Chairman of the Board, President and
Chief Executive Officer; Director
Fred C. Ackman...................... 64 Director
Richard D. Kinder................... 51 Director
Kenneth L. Lay...................... 53 Director
Edward Randall, III................. 68 Director
Joe Michael McKinney................ 55 President-International Operations
Mark G. Papa........................ 49 President-North American Operations
Walter C. Wilson.................... 53 Senior Vice President and Chief
Financial Officer
Ben B. Boyd......................... 54 Vice President and Controller
Dennis M. Ulak...................... 41 Vice President and General Counsel
Forrest E. Hoglund joined the Company as Chairman of the Board, Chief
Executive Officer and Director in September 1987. Since May 1990, he has also
served as President of the Company. Mr. Hoglund was a director of USX
Corporation from February 1986 until September 1987. He joined Texas Oil & Gas
Corp. ("TXO") in 1977 as president, was named Chief Operating Officer in 1979,
Chief Executive Officer in 1982, and served TXO in those capacities until
September 1987. Mr. Hoglund is also an advisory director of Texas Commerce
Bank National Association.
Fred C. Ackman is the former Chairman, President and Chief Executive
Officer of The Superior Oil Company. For over five years Mr. Ackman has been a
consultant to the oil and gas industry and has interests in ranching and
investments.
Richard D. Kinder has been President and Chief Operating Officer of Enron
Corp. since October 1990. From December 1988 until October 1990, he served
Enron Corp. as Vice Chairman of the Board. For over five years prior to his
election as Vice Chairman, Mr. Kinder served in various management and legal
positions with Enron Corp. and its affiliates. Mr. Kinder is also a director
of Enron Corp., Enron Global Power & Pipelines L.L.C., EOTT Energy Corp. (the
general partner of EOTT Energy Partners, L.P.), Enron Liquids Pipeline Company
(the general partner of Enron Liquids Pipeline, L.P.), Sonat Offshore Drilling
Inc. and Baker Hughes Incorporated.
Kenneth L. Lay has been Chairman of the Board and Chief Executive Officer
of Enron Corp. for over five years. From February 1989 until October 1990, he
also served as President of Enron Corp. Mr. Lay is also a director of Eli
Lilly and Company, Compaq Computer Corporation, Trust Company of the West,
EOTT Energy Corp. (the general partner of EOTT Energy Partners, L.P.), and
Enron Corp.
Edward Randall, III is principally involved in investments. Mr. Randall
is also a director of KN Energy, Inc. and PaineWebber Group Inc.
Joe Michael McKinney has been President-International Operations since
February 1994 with responsibilities for all exploration, drilling, production
and engineering activities for the Company's international ventures outside
North America. Mr. McKinney joined Enron Oil & Gas International, Inc., a
wholly-owned subsidiary of the Company, in December 1991 as Senior Vice
President of Operations and was elected President and Chief Operating Officer
of Enron Oil & Gas International, Inc. in April 1993, a capacity in which he
continues to serve. Prior to joining the Company, Mr. McKinney held operations
management positions with Union Texas Petroleum Company, The Superior Oil
Company and Exxon Company, USA.
33
Mark G. Papa has been President-North American Operations since February
1994. From May 1986 through January 1994, Mr. Papa served as Senior Vice
President-Operations. Mr. Papa joined Belco Petroleum Corporation, a
predecessor of the Company, in 1981 as Division Production Coordinator and
served as Senior Vice President-Drilling and Production, BelNorth Petroleum
Corporation from May 1984 until May 1986.
Walter C. Wilson has been Senior Vice President and Chief Financial
Officer since May 1991. Mr. Wilson joined the Company in November 1987 as Vice
President and Controller and was named Senior Vice President-Finance in
October 1988. Prior to joining the Company Mr. Wilson held financial
management positions with Exxon Company, USA for 16 years and The Superior Oil
Company for four years.
Ben B. Boyd has been Vice President and Controller since March 1991. Mr.
Boyd joined the Company in March 1989 as Director of Accounting and was named
Controller in May 1990. Prior to joining the Company, Mr. Boyd held financial
management positions with DeNovo Oil & Gas, Inc., Scurlock Oil Company and
Coopers & Lybrand.
Dennis M. Ulak has been Vice President and General Counsel since March
1992. Mr. Ulak joined the Company in March 1987 as Senior Counsel and was
named Assistant General Counsel in August 1990. Prior to joining the Company,
Mr. Ulak held various legal positions with Enron Corp. and Northern Natural
Gas Company.
THE SELLING STOCKHOLDER
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP
BEFORE STOCK OFFERINGS AFTER STOCK OFFERINGS(1)(2)
----------------------------- SHARES TO -----------------------------
SELLING STOCKHOLDER SHARES PERCENTAGE BE SOLD(1) SHARES PERCENTAGE
- ------------------------------------- -------------- ---------- ------------- -------------- ----------
<S> <C> <C> <C> <C> <C>
Enron Corp. 128,000,000 80% 27,000,000 101,000,000 63%
</TABLE>
- ------------
(1) Assumes that the Underwriters' over-allotment options in the Stock
Offerings are not exercised. If such options are exercised in full, Enron
Corp. will sell 31,050,000 shares of Common Stock in the Stock Offerings
and will beneficially own 96,950,000 shares of Common Stock (approximately
61% of the outstanding shares) after the Stock Offerings.
(2) Concurrently with the Stock Offerings, Enron Corp. is offering
Exchangeable Notes, which at maturity may be exchanged for no more than
10,000,000 shares of Common Stock (no more than 11,000,000 shares if the
over-allotment option to the Underwriters in the Exchangeable Notes
Offering is exercised in full) owned by Enron Corp., subject to adjustment
under certain circumstances and to Enron Corp.'s option to pay an amount
in cash in lieu of such mandatory exchange. Following consummation of the
Exchangeable Notes Offering, the shares that may be delivered upon
exchange therefor will continue to be beneficially owned by Enron Corp.
until such time, if any, as they are delivered at maturity of the
Exchangeable Notes. If the Underwriters' over-allotment options in the
Stock Offerings and the Exchangeable Notes Offering are exercised in full
and the maximum number of shares of Common Stock are delivered at maturity
of the Exchangeable Notes, Enron Corp. will beneficially own 85,950,000
shares of Common Stock or approximately 54% of the outstanding shares.
The registration related to the Stock Offerings and the Common Stock
deliverable upon exchange of the Exchangeable Notes is being provided pursuant
to the terms of a Stock Restriction and Registration Agreement with Enron
Corp., under which the Company has agreed that upon the request of Enron Corp.
(or certain assignees), the Company will register under the Securities Act and
applicable state securities laws the sale of Common Stock owned by Enron Corp.
The Company's obligation is subject to certain limitations relating to a
minimum amount of Common Stock required for registration, the timing of
registration and other similar matters. The Company is obligated to pay all
expenses incidental to such registration, excluding underwriters' discounts
and commissions and certain legal fees and expenses.
34
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
OWNERSHIP OF COMMON STOCK
Through its ability to elect all of the directors of the Company, Enron
Corp. has the ability to control all matters relating to the management of the
Company, including any determination with respect to acquisition or
disposition of Company assets, future issuance of Common Stock or other
securities of the Company and any dividends payable on the Common Stock. Enron
Corp. also has the ability to control the Company's exploration, development,
acquisition and operating expenditure plans. There is no agreement between
Enron Corp. and the Company that would prevent Enron Corp. from acquiring
additional shares of Common Stock of the Company.
The sale by Enron Corp. of the shares of Common Stock of the Company will
cause Enron Corp.'s ownership interest in the Company to fall below 80% with the
result that (i) the Company will cease to be included in the consolidated
federal income tax return filed by Enron Corp. and (ii) the Tax Allocation
Agreement between the Company and Enron Corp. described below will cease to be
effective from the time at which deconsolidation occurs. The Company and Enron
Corp. have entered into a new tax agreement pursuant to which, among other
things, Enron Corp. has agreed (in exchange for the payment of $8.0 million by
the Company) to be liable for, and to indemnify the Company against, all federal
income taxes and state taxes measured by net income imposed on the Company for
periods through the date Enron Corp. reduces its ownership in the Company to
less than 80%. The Company does not believe that the cessation of consolidated
tax reporting with Enron Corp. and effectiveness of the Tax Allocation Agreement
concurrently with deconsolidation or the terms of the new agreement will have a
material adverse effect on its financial condition or results of operations.
CONTRACTUAL ARRANGEMENTS
The Company entered into a Services Agreement (the "Services Agreement")
with Enron Corp. effective January 1994, pursuant to which Enron Corp.
provides various services, such as maintenance of certain employee benefit
plans, provision of telecommunications and computer services, lease of office
space and the provision of purchasing and operating services and certain other
corporate staff and support services. Such services historically have been
supplied to the Company by Enron Corp., and the Services Agreement provides
for the further delivery of such services substantially identical in nature
and quality to those services previously provided. The Company has agreed to a
fixed rate for the rental of office space and to reimburse Enron Corp. for all
other direct costs incurred in rendering services to the Company under the
contract and to pay Enron Corp. for allocated indirect costs incurred in
rendering such services up to a maximum of $6.7 million for 1994, such cap to
be increased in subsequent years for inflation and certain changes in the
Company's allocation bases with any increase not to exceed 7.5% per year.
Approximately $6.6 million was paid under the Services Agreement by the
Company to Enron Corp. in 1994. The Services Agreement is for an initial term
of five years through December 1998 and will continue thereafter until
terminated by either party.
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 (the "Swap Agreements") of equivalent value. As a result of
the transactions, the Company has been relieved of all performance obligations
associated with the Cogen Contracts. The Company will realize net operating
revenues and receive corresponding cash payments of approximately $91 million
during the period extending through December 31, 1999 under the terms of the
Swap Agreements. The estimated fair value of the Swap Agreements was
approximately $81 million at the date the Swap Agreements were received. The
net 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 that anticipated under the Cogen Contracts.
35
The Company has been included in the consolidated federal income tax return
filed by Enron Corp. as the common parent for itself and its subsidiaries and
affiliated companies, excluding any foreign subsidiaries. Consistent therewith
and pursuant to a Tax Allocation Agreement between the Company, the Company's
subsidiaries and Enron Corp., either Enron Corp. has paid to the Company and
each subsidiary an amount equal to the tax benefit realized in the Enron Corp.
consolidated federal income tax return resulting from the utilization of the
Company's or the subsidiary's net operating losses and/or tax credits, or the
Company and each subsidiary has paid to Enron Corp. an amount equal to the
federal income tax computed on its separate taxable income less the tax benefits
associated with any net operating losses and/or tax credits generated by the
Company or the subsidiary which were utilized in the Enron Corp. consolidated
return. Enron Corp. has paid the Company and each subsidiary for the tax
benefits associated with their net operating losses and tax credits utilized in
the Enron Corp. consolidated return, provided that a tax benefit was realized
except as discussed below, even if such benefits could not have been used by the
Company or the subsidiary on a separately filed tax return. The Company entered
into an agreement with Enron Corp. providing for the Company to be paid for all
realizable benefits associated with tight gas sand federal income tax credits
concurrent with tax reporting and settlement for the periods in which they were
generated. The Tax Allocation Agreement applies to the Company and each of its
subsidiaries for all years in which the Company or any of its subsidiaries are
or were included in the Enron Corp. consolidated return. To the extent a state
or other taxing jurisdiction requires or permits a consolidated, combined, or
unitary tax return to be filed and such return includes the Company or any of
its subsidiaries, the principles expressed with respect to consolidated federal
income tax allocation shall apply. The Tax Allocation Agreement will cease to be
effective from the time at which deconsolidation occurs. The Company and Enron
Corp. have entered into a new tax agreement pursuant to which, among other
things, Enron Corp. has agreed (in exchange for the payment of $8.0 million by
the Company) to be liable for, and to indemnify the Company against, all federal
income taxes and state taxes measured by net income imposed on the Company for
periods through the date Enron Corp. reduces its ownership in the Company to
less than 80%. The Company does not believe that the cessation of consolidated
tax reporting with Enron Corp. and effectiveness of the Tax Allocation Agreement
concurrently with deconsolidation or the terms of the new agreement will have a
material adverse effect on its financial condition or results of operations.
For a discussion of transactions between the Company and Enron Corp. and
its affiliates, see the Company's Annual Report on Form 10-K for the year
ended December 31, 1994 incorporated herein by reference. See "Incorporation
of Certain Documents by Reference."
CONFLICTS OF INTEREST
The nature of the respective businesses of the Company and Enron Corp.
and its affiliates is such as to potentially give rise to conflicts of
interest between the two companies. Conflicts could arise, for example, with
respect to transactions involving purchases, sales and transportation of
natural gas and other business dealings between the Company and Enron Corp.
and its affiliates, potential acquisitions of businesses or oil and gas
properties, the issuance of additional shares of voting securities, the
election of directors or the payment of dividends by the Company.
Circumstances may also arise that would cause Enron Corp. to engage in
the exploration for and/or development and production of natural gas and crude
oil in competition with the Company. For example, opportunities might arise
which would require financial resources greater than those available to the
Company, which are located in areas or countries in which the Company does not
intend to operate or which involve properties that the Company would be
unwilling to acquire. Also, Enron Corp. might acquire a competing oil and gas
business as part of a larger acquisition. In addition, as part of Enron
Corp.'s strategy of securing supplies of natural gas or capital, Enron Corp.
may from time to time acquire producing properties or interests in entities
owning producing
36
properties, and thereafter engage in exploration, development and production
activities with respect to such properties or indirectly engage in such
activities through such companies. Enron Corp. subsidiaries provide or arrange
financing, including debt or equity financing, for exploration and production
companies that compete with the Company. In connection with such activities,
Enron Corp. affiliates may make investments in the debt or equity of such
companies. There are currently no such transactions under consideration that
would result in voting control by Enron Corp. or any of its affiliates, other
than the transaction described in the next paragraph. In its financing
activities Enron Corp. or any entity in which it has an interest may also make
loans secured by oil and gas properties or securities of oil and gas companies,
may acquire production payments or may receive interests in oil and gas
properties as equity components of lending transactions. As a result of its
lending activities, Enron Corp. may also acquire oil and gas properties or
companies upon foreclosure of secured loans or as part of a borrower's
rearrangement of its obligations. Such acquisition, exploration, development and
production activities may directly or indirectly compete with the Company's
business. There can be no assurances that Enron Corp. will not engage, directly
or indirectly through entities other than the Company, in the natural gas and
crude oil exploration, development and production business in competition with
the Company.
Joint Energy Development Investments Limited Partnership ("JEDI"), a
limited partnership in which Enron Capital & Trade Resources Corp. ("ECT"), a
wholly owned subsidiary of Enron Corp., owns a 50% general partner interest, has
entered into an agreement to acquire a controlling interest in Coda. Coda is
engaged in the exploration for, and the development, production and marketing
of, natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil
accounts for approximately 86% of Coda's proved reserves. At December 31, 1994,
Coda reported estimated proved natural gas reserves of 39,808 MMcf and estimated
proved crude oil, condensate and natural gas liquids reserves of 39,207 MBbls.
Enron anticipates that the transaction will be consummated in early 1996,
subject to Coda stockholder approval and other conditions. Conflicts may arise
between Coda and the Company, and if the acquisition of Coda occurs Enron will
be required to resolve such conflicts in a manner that is consistent with its
fiduciary and contractual duties to other investors in Coda and JEDI and its
fiduciary duties to the Company. ECT has entered into an agreement with JEDI and
other investors in Coda designed to minimize certain conflicts of interest that
may arise and providing, among other things, that the Company has no obligation
to offer any business opportunities to Coda.
The Company and Enron Corp. and its affiliates have in the past entered
into material intercompany transactions and agreements incident to their
respective businesses, and the Company and Enron Corp. and its affiliates may
be expected to enter into material transactions and agreements from time to
time in the future. Such transactions and agreements have related to, among
other things, the purchase and sale of natural gas and crude oil, the
financing of exploration and development efforts by the Company, and the
provision of certain corporate services. The Company believes that its
existing transactions and agreements with Enron Corp. and its affiliates have
been at least as favorable to the Company as could be obtained from third
parties, and the Company intends that the terms of any future transactions and
agreements between the Company and Enron Corp. and its affiliates will be at
least as favorable to the Company as could be obtained from third parties.
37
DESCRIPTION OF COMMON STOCK
AUTHORIZED AND OUTSTANDING CAPITAL STOCK
The authorized capital stock of the Company consists of 160,000,000
shares of Common Stock, $.01 par value, of which 159,799,955 shares were
outstanding on October 31, 1995. The following summary description of the
capital stock of the Company is qualified in its entirety by reference to the
Restated Certificate of Incorporation of the Company, as amended, a copy of
which is filed as an exhibit to the Registration Statement of which this
Prospectus is a part.
The Common Stock possesses ordinary voting rights for the election of
directors and in respect to other corporate matters, each share being entitled
to one vote. There are no cumulative voting rights, meaning that the holders
of a majority of the shares voting for the election of directors can elect all
the directors if they choose to do so. The Common Stock carries no preemptive
rights and is not convertible, redeemable or assessable, or entitled to the
benefits of any sinking fund. The holders of Common Stock are entitled to
dividends in such amounts and at such times as may be declared by the Board of
Directors out of funds legally available therefor.
Upon liquidation or dissolution, holders of Common Stock are entitled to
share ratably in all net assets available for distribution to stockholders
after payment of any corporate debts. All outstanding shares of Common Stock
are duly authorized, validly issued, fully paid and nonassessable.
The transfer agent and registrar of the Common Stock is First Chicago
Trust Company of New York, Jersey City, New Jersey.
LIMITATION ON DIRECTORS' LIABILITY
Delaware corporation law authorizes corporations to limit or eliminate
the personal liability of directors to corporations and their stockholders for
monetary damages for breach of directors' fiduciary duty of care. The duty of
care requires that, when acting on behalf of the corporation, directors must
exercise an informed business judgment based on all material information
reasonably available to them. Absent the limitations authorized by such laws,
directors are accountable to corporations and their stockholders for monetary
damages for conduct constituting gross negligence in the exercise of their
duty of care. The Delaware laws enable corporations to limit available relief
to equitable remedies such as injunction or rescission. The Restated
Certificate of Incorporation, as amended, of the Company limits the liability
of directors of the Company to the Company or its stockholders (in their
capacity as directors but not in their capacity as officers) to the fullest
extent permitted by the Delaware law. Specifically, directors of the Company
will not be personally liable for monetary damages for breach of a director's
fiduciary duty as a director, except for liability (i) for any breach of the
director's duty of loyalty to the Company or its stockholders, (ii) for acts
or omissions not in good faith or which involve intentional misconduct or a
knowing violation of law, (iii) for unlawful payments of dividends or unlawful
stock repurchases or redemptions as provided in Section 174 of the Delaware
General Corporation Law, or (iv) for any transaction from which the director
derived an improper personal benefit.
This provision in the Restated Certificate of Incorporation may have the
effect of reducing the likelihood of derivative litigation against directors,
and may discourage or deter stockholders or management from bringing a lawsuit
against directors for breach of their duty of care, even though such an
action, if successful, might otherwise have benefited the Company and its
stockholders.
38
CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES
FOR NON-UNITED STATES HOLDERS OF COMMON STOCK
The following is a summary of certain United States federal income tax
consequences of the acquisition, ownership and disposition of Common Stock by
a holder that, for United States federal income and estate tax purposes, is a
Non-United States Holder. For purposes of this discussion, a "Non-United
States Holder" means a corporation, individual or partnership that is, as to
the United States, a foreign corporation, a non-resident alien individual or a
foreign partnership, or a trust or estate other than one the income of which
is subject to United States federal income tax regardless of its source. This
summary does not address all aspects of United States federal income and
estate taxation and does not deal with foreign, state and local tax
consequences that may be relevant to Non-United States Holders in light of
their specific circumstances. Furthermore, this summary is based on the
provisions of the United States Internal Revenue Code of 1986, as amended, and
the regulations, rulings and judicial decisions thereunder, all of which are
subject to change. PROSPECTIVE INVESTORS ARE URGED TO CONSULT THEIR OWN TAX
ADVISORS WITH RESPECT TO THE UNITED STATES TAX CONSEQUENCES TO THEM OF
ACQUIRING, HOLDING AND DISPOSING OF COMMON STOCK AS WELL AS ANY TAX
CONSEQUENCES THAT MAY ARISE UNDER THE LAWS OF ANY FOREIGN, STATE, LOCAL OR
OTHER TAXING JURISDICTION.
DIVIDENDS
Dividends paid to a Non-United States Holder generally will be subject to
withholding of United States federal income tax at a rate of 30% (or a lower
rate prescribed by an applicable tax treaty). If the dividends are effectively
connected with the conduct of a trade or business within the United States by
the Non-United States Holder, the dividends will be subject to the ordinary
United States federal income tax on net income that applies to United States
persons and will not be subject to withholding if the Non-United States Holder
files a United States Internal Revenue Service Form 4224 with the Company or
its dividend paying agent. In the case of corporate holders, such dividends
might also be subject to the United States branch profits tax at a rate of 30%
(or a lower rate prescribed by an applicable tax treaty). A Non-United States
Holder may be required to satisfy certain certification requirements in order
to obtain any reduction of or exemption from withholding under the foregoing
rules and may obtain a refund of any excess amounts currently withheld by
filing an appropriate refund claim with the United States Internal Revenue
Service.
Distributions in excess of the Company's current and accumulated earnings
and profits, as determined for United States federal income tax purposes, will
be treated first as a return of capital to the extent of the Non-United States
Holder's tax basis in the Common Stock (and will be applied against and reduce
such holder's tax basis in the Common Stock) and thereafter as gain from the
sale of Common Stock. The portion treated as a return of capital will not be
subject to United States federal income tax and the portion, if any, treated
as gain will be subject to the rules described under " -- Gain on Disposition"
below. Because the Company will not be able to determine whether a
distribution should properly be treated as a dividend or as a return of
capital at the time of payment, it is required to treat all distributions as
dividends for United States withholding tax purposes. Non-United States
Holders will be eligible to claim a refund to the extent that a distribution
represents a return of capital and may in certain circumstances be eligible to
claim a refund to the extent that a distribution is treated as gain.
Non-United States Holders should consult their own tax advisors with respect
to distributions in excess of current and accumulated earnings and profits.
GAIN ON DISPOSITION
GENERAL RULE
Subject to special rules for individuals described below, a Non-United
States Holder generally will not be subject to United States federal income
tax on gain recognized on a sale or other disposition of Common Stock unless
(a) the gain is effectively connected with the conduct of a trade or business
within the United States by the Non-United States Holder (in which case the
United States branch profits tax described above may also apply to corporate
holders) or (b) the gain is
39
treated as effectively connected with the conduct of a trade or business
within the United States because the Company is or has been a "United States
real property holding corporation" for United States federal income tax
purposes (in which case, withholding of such tax may also apply). The Company
believes that it is currently, and is likely to remain, a United States real
property holding corporation. The preceding sentence notwithstanding, under
currently effective United States federal income tax laws, gain recognized by
a Non-United States Holder will not be treated as effectively connected with
the conduct of a trade or business within the United States (or subject to
withholding) unless such Non-United States Holder held, directly or
indirectly, at any time during the five-year period ending on the date of
disposition, more than five percent of the Common Stock. Non-United States
Holders should consult applicable tax treaties, which may provide for
different rules (including possibly the exemption of certain capital gains
from tax).
INDIVIDUALS
In addition to the rules described above, an individual Non-United States
Holder who holds Common Stock as a capital asset generally will be subject to
tax on any gain recognized on the disposition of such stock if such individual
is present in the United States for 183 days or more in the taxable year of
disposition and either (a) has a "tax home" in the United States (as
specifically defined under the United States federal income tax laws) or (b)
maintains an office or other fixed place of business in the United States to
which the gain from the sale of the stock is attributable. Certain individual
Non-United States Holders may also be subject to tax pursuant to provisions of
United States federal income tax law applicable to United States expatriates.
FEDERAL ESTATE TAX
Common Stock owned or treated as owned by an individual Non-United States
Holder at the date of death will be subject to United States federal estate
tax, unless an applicable estate tax treaty provides otherwise.
INFORMATION REPORTING AND BACKUP WITHHOLDING
The Company or its designated paying agent (the "payor") must report
annually to the United States Internal Revenue Service and to each Non-United
States Holder the amount of dividends paid to and the tax, if any, withheld
with respect to such holder. That information may also be made available to
the tax authorities of the country in which the Non-United States Holder
resides.
United States information reporting requirements (other than the
reporting of dividend payments described in the preceding paragraph) and
United States backup withholding (imposed at a 31% rate) generally will not
apply to dividends paid to a Non-United States Holder at an address outside
the United States, unless the payor has knowledge that the payee is a United
States person. Otherwise, information reporting and backup withholding may
apply to dividends paid on the Common Stock to a Non-United States Holder who
fails to furnish certain information, including a tax identification number,
in the manner required by United States law and applicable regulations.
Payment of the proceeds of a disposition of Common Stock by a United
States office of a broker is subject to backup withholding and information
reporting, unless the holder certifies to the broker under penalties of
perjury as to its name, address and status as a Non-United States Holder or
the holder otherwise establishes an exemption. Neither backup withholding nor
information reporting generally will apply to a payment of the proceeds of a
disposition of Common Stock by a foreign office of a foreign broker that is
not a United States Related Person (as defined below). Information reporting
requirements (but not backup withholding) will apply to a payment of the
proceeds of a disposition of Common Stock by a foreign office of a broker that
is a United States person or a United States Related Person, unless the broker
has documentary evidence in its records that the holder is a Non-United States
Related Person and certain other conditions are met, or the holder otherwise
establishes an exemption. For this purpose, a "United States Related Person"
is (a) a foreign broker, 50% or more of whose gross income for certain periods
is effectively connected with the conduct of a trade or business in the United
States or (b) a foreign broker that is a "controlled foreign corporation" for
United States federal income tax purposes.
40
Backup withholding is not an additional tax. Any amounts withheld under
the backup withholding rules will be refunded or credited against the
Non-United States Holder's United States federal income tax liability,
provided that required information is furnished to the United States Internal
Revenue Service.
PLAN OF DISTRIBUTION
This Prospectus relates to the 11,000,000 shares of Common Stock that may
be delivered by Enron Corp. pursuant to the Exchangeable Notes and is Appendix
A to the Enron Corp. Exchangeable Notes Prospectus. At maturity of the
Exchangeable Notes, the principal amount of each such note will be mandatorily
exchanged by Enron Corp. for shares of Common Stock or, at the option of Enron
Corp., cash in lieu of such mandatory exchange. For a description of the
Exchangeable Notes, see "Description of the Exchangeable Notes" in the Enron
Corp. Exchangeable Notes Prospectus.
Enron Corp., the Company and the Company's Chief Executive Officer have
agreed that during the period beginning from the date of this Prospectus and
continuing to and including the date 270 days after the date of this
Prospectus, subject to certain exceptions set forth in the underwriting
agreements, they will not offer, sell, contract to sell or otherwise dispose
of Common Stock, any securities of the Company which are substantially similar
to shares of Common Stock or any securities which are convertible into or
exchangeable for Common Stock or such substantially similar securities without
the prior written consent of Goldman, Sachs & Co., except for the shares of
Common Stock offered in connection with the concurrent Stock Offerings.
In connection with the distribution of the Exchangeable Notes, Enron
Corp. and the Company have agreed to indemnify the several Underwriters
against certain liabilities, including liabilities under the Securities Act,
or to contribute to payments the Underwriters may be required to make in
respect thereof.
VALIDITY OF COMMON STOCK
The validity of the shares of Common Stock deliverable upon exchange of
the Exchangeable Notes will be passed upon for the Company by Dennis M. Ulak,
Esq., Vice President and General Counsel of the Company, and for the
Underwriters by Bracewell & Patterson, L.L.P. Certain matters will be passed
upon for Enron Corp. by Vinson & Elkins L.L.P. Mr. Ulak owns substantially
less than 1% of the outstanding shares of Common Stock of the Company or
common stock of Enron Corp. Bracewell & Patterson, L.L.P. provides services to
Enron Corp. and certain of its subsidiaries (including the Company) and
affiliates on matters unrelated to the offering of the Exchangeable Notes, the
delivery of the Common Stock upon exchange thereof and the Stock Offerings.
EXPERTS
The consolidated financial statements and schedule included in the
Company's Annual Report on Form 10-K for the year ended December 31, 1994,
incorporated by reference in this Prospectus, have been audited by Arthur
Andersen LLP, independent public accountants, as indicated in their report
with respect thereto, and are incorporated by reference herein in reliance
upon the authority of said firm as experts in accounting and auditing in
giving said report.
The letter report of DeGolyer and MacNaughton, independent petroleum
consultants, included as an exhibit to the Company's Annual Report on Form
10-K for the year ended December 31, 1994, and the estimates from the reports
of that firm appearing in such Annual Report, are incorporated by reference
herein on the authority of said firm as experts in petroleum engineering and
in giving such reports.
41
<PAGE>
==============================================================================
NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN
OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES
DESCRIBED IN THIS PROSPECTUS OR AN OFFER TO SELL OR THE SOLICITATION OF AN
OFFER TO BUY SUCH SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR
SOLICITATION IS UNLAWFUL. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE
MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT
THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF
OR THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT
TO ITS DATE.
------------------------
TABLE OF CONTENTS
PAGE
-----
Available Information................ 2
Incorporation of Certain Documents by
Reference.......................... 2
Prospectus Summary................... 3
Use of Proceeds...................... 10
Price Range of Common
Stock and Cash Dividends........... 10
Business............................. 11
Selected Consolidated Financial and
Operating Information.............. 20
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 22
Management........................... 33
The Selling Stockholder.............. 34
Relationship Between the
Company and Enron Corp............. 35
Description of Common Stock.......... 38
Certain United States Federal Tax
Consequences For Non-United States
Holders of Common Stock............ 39
Plan of Distribution................. 41
Validity of Common Stock............. 41
Experts.............................. 41
ENRON OIL & GAS COMPANY
COMMON STOCK
(PAR VALUE $.01 PER SHARE)
------------------------
PROSPECTUS
------------------------
==============================================================================
<PAGE>
==============================================================================
NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN
OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES
DESCRIBED IN THIS PROSPECTUS OR AN OFFER TO SELL OR THE SOLICITATION OF AN
OFFER TO BUY SUCH SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR
SOLICITATION IS UNLAWFUL. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE
MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT
THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF ENRON SINCE THE DATE HEREOF OR THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.
------------------------
TABLE OF CONTENTS
PAGE
-----
Available Information................ 2
Incorporation of Certain Documents by
Reference.......................... 2
Prospectus Summary................... 3
Risk Factors Relating to Exchangeable
Notes.............................. 5
Enron Corp........................... 7
Recent Events........................ 8
Selected Financial Data of Enron..... 10
Capitalization....................... 11
Relationship Between Enron and EOG.. 12
Use of Proceeds...................... 14
Ratio of Enron's Earnings to Fixed
Charges............................ 14
Price Range of EOG Common Stock and
Cash Dividends..................... 14
Description of the Exchangeable
Notes.............................. 15
Certain United States Federal Income
Tax Considerations................. 24
Underwriting......................... 27
Validity of the Exchangeable Notes... 28
Experts.............................. 28
Prospectus Relating to Common Stock
of Enron Oil & Gas Company......... Appendix A
10,000,000 EXCHANGEABLE NOTES
ENRON CORP.
% EXCHANGEABLE NOTES
DUE , 1998
GOLDMAN, SACHS & CO.
MERRILL LYNCH & CO.
SALOMON BROTHERS INC
REPRESENTATIVES OF THE UNDERWRITERS
==============================================================================
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following table sets forth those expenses to be incurred by Enron in
connection with the issuance and distribution of the securities being
registered. Except for the Securities and Exchange Commission registration fee
and NASD, Inc. filing fees, all amounts shown are estimates.
Securities and Exchange Commission
Registration Fee................... $ 75,388
NASD Filing Fees..................... 22,365
Accounting Fees and Expenses......... 50,000
Legal Fees and Expenses.............. 70,000
Fees and Expenses of Transfer Agent
and Trustee........................ 15,000
Blue Sky Fees and Expenses, Including
Counsel Fees....................... 10,000
Printing and Engraving Expenses...... 150,000
Miscellaneous........................ 32,247
-----------
Total...................... $ 425,000
===========
ITEM 15. INDEMNIFICATION OF OFFICERS AND DIRECTORS
Section 145 of Chapter 1 of Title 8 of the Delaware Code provides that
every corporation created under the provisions thereof shall have the power to
indemnify its directors, officers, employees and agents against certain
liabilities.
The Restated Certificate of Incorporation, as amended, of Enron contains
the following provisions relating to indemnification of directors and
officers:
"1. A director of the Corporation shall not be personally liable to
the Corporation or its stockholders for monetary damages for breach of
fiduciary duty as a director, except for liability (i) for any breach of
the director's duty of loyalty to the Corporation or its stockholders,
(ii) for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of law, (iii) under Section 174 of the
Delaware General Corporation Law, or (iv) for any transaction from which
the director derived an improper personal benefit.
2. (A) Each person who was or is made a party or is threatened to
be made a party to or is involved in any action, suit or proceeding,
whether civil, criminal, administrative or investigative (hereinafter a
"proceeding"), by reason of the fact that he or she, or a person of whom
he or she is the legal representative, is or was a director or officer,
of the Corporation or is or was serving at the request of the Corporation
as a director, officer, employee or agent of another corporation or of a
partnership, joint venture, trust or other enterprise, including service
with respect to employee benefit plans, whether the basis of such
proceeding is alleged action in an official capacity as a director,
officer, employee or agent or in any other capacity while serving as a
director, officer, employee or agent, shall be indemnified and held
harmless by the Corporation to the fullest extent authorized by the
Delaware General Corporation Law, as the same exists or may hereafter be
amended (but, in the case of any such amendment, only to the extent that
such amendment permits the Corporation to provide broader indemnification
rights than said law permitted the Corporation to provide prior to such
amendment), against all expense, liability and loss (including attorneys'
fees, judgments, fines, ERISA excise taxes or penalties and amounts paid
or to be paid in settlement) reasonably incurred or suffered by such
person in connection therewith, and such indemnification shall continue
as to a person who has ceased to be a director, officer, employee or
agent and shall inure to the benefit of his or her heirs, executors and
administrators; provided, however, that, except as provided in paragraph
II-1
(B) hereof, the Corporation shall indemnify any such person seeking
indemnification in connection with a proceeding (or part thereof) initiated
by such person only if such proceeding (or part thereof) was authorized by
the Board of Directors of the Corporation. The right to indemnification
conferred in this Section shall be a contract right and shall include the
right to be paid by the Corporation the expenses incurred in defending any
such proceeding in advance of its final disposition; provided, however,
that, if the Delaware General Corporation Law requires, the payment of such
expenses incurred by a director or officer in his or her capacity as a
director or officer (and not in any other capacity in which service was or
is rendered by such person while a director or officer, including, without
limitation, service to an employee benefit plan) in advance of the final
disposition of the proceeding, shall be made only upon delivery to the
Corporation of an undertaking, by or on behalf of such director or officer,
to repay all amounts so advanced if it shall ultimately be determined that
such director or officer is not entitled to be indemnified under this
Section or otherwise. The Corporation may, by action of its Board of
Directors, provide indemnification to employees and agents of the
Corporation with the same scope and effect as the foregoing indemnification
of directors and officers.
(B) If a claim under paragraph 2(A) of this Article XVI is not paid
in full by the Corporation within thirty days after a written claim has
been received by the Corporation, the claimant may at any time thereafter
bring suit against the Corporation to recover the unpaid amount of the
claim and, if successful in whole or in part, the claimant shall be
entitled to be paid also the expense of prosecuting such claim. It shall
be a defense to any such action (other than an action brought to enforce
a claim for expenses incurred in defending any proceeding in advance of
its final disposition where the required undertaking, if any is required,
has been tendered to the Corporation) that the claimant has not met the
standards of conduct which make it permissible under the Delaware General
Corporation Law for the Corporation to indemnify the claimant for the
amount claimed, but the burden of proving such defense shall be on the
Corporation. Neither the failure of the Corporation (including its Board
of Directors, independent legal counsel, or its stockholders) to have
made a determination prior to the commencement of such action that
indemnification of the claimant is proper in the circumstances because he
or she has met the applicable standard of conduct set forth in the
Delaware General Corporation Law, nor an actual determination by the
Corporation (including its Board of Directors, independent legal counsel,
or its stockholders) that the claimant has not met such applicable
standard of conduct, shall be a defense to the action or create a
presumption that the claimant has not met the applicable standard of
conduct.
(C) The right to indemnification and the payment of expenses
incurred in defending a proceeding in advance of its final disposition
conferred in this Section shall not be exclusive of any other right which
any person may have or hereafter acquire under any statute, provision of
the Certificate of Incorporation, bylaw, agreement, vote of stockholders
or disinterested directors or otherwise.
(D) The Corporation may maintain insurance, at its expense, to
protect itself and any director, officer, employee or agent of the
Corporation or another corporation, partnership, joint venture, trust or
other enterprise against any such expense, liability or loss, whether or
not the Corporation would have the power to indemnify such person against
such expense, liability or loss under the Delaware General Corporation
Law."
Enron has purchased liability insurance policies covering its directors
and officers to provide protection where Enron cannot legally indemnify a
director or officer and where a claim arises under the Employee Retirement
Income Security Act of 1974 against a director or officer based on an alleged
breach of fiduciary duty or other wrongful act.
II-2
ITEM 16. EXHIBITS
**1 -- Form of Underwriting Agreement for Exchangeable Notes.
*4(a) -- Indenture dated as of November 1, 1985, between Enron and Harris
Trust and Savings Bank (Form T-3 Application for Qualification of
Indentures under the Trust Indenture Act of 1939, File No. 22-14390,
filed October 24, 1985).
**4(b) -- Form of First Supplemental Indenture between Enron and Harris
Trust and Savings Bank, as Trustee.
5 -- Opinion of James V. Derrick, Jr., Esq., Senior Vice President and
General Counsel of Enron, as to validity of the Exchangeable Notes.
8 -- Opinion of Vinson & Elkins L.L.P. regarding certain tax matters.
10 -- Form of 1995 Tax Allocation Agreement between Enron and Enron Oil &
Gas Company.
**12 -- Computations of Ratios of Earnings to Fixed Charges.
23(a) -- Consents of Arthur Andersen LLP.
**23(b) -- Consent of DeGolyer and MacNaughton.
23(c) -- The consent of James V. Derrick, Jr., Esq., is contained in his
opinion filed as Exhibit 5 hereto.
**24 -- Powers of Attorney.
**25 -- Form T-1 Statement of Eligibility under the Trust Indenture Act
of 1939 of Harris Trust and Savings Bank.
- ------------
* Incorporated by reference as indicated.
** Previously filed.
ITEM 17. UNDERTAKINGS
(a) The undersigned Registrant hereby undertakes that for purposes of
determining any liability under the Securities Act of 1933, each filing of
Enron's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in the
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide offering
thereof.
(b) Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of the Registrants pursuant to the provisions described under Item 15
above, or otherwise, the Registrants have been advised that in the opinion of
the Securities and Exchange Commission such indemnification is against public
policy as expressed in the Act and is, therefore, unenforceable. In the event
that a claim for indemnification against such liabilities (other than the
payment by the Registrant of expenses incurred or paid by a director, officer
or controlling person of such registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or
controlling person in connection with the securities being registered, such
Registrant will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication
of such issue.
(c) The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities
Act of 1933, the information omitted from the form of prospectus filed as
part of this registration statement in reliance upon Rule 430A and
contained in a form of prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4), or 497(h) under the Securities Act shall be deemed
to be part of this registration statement as of the time it was declared
effective.
(2) For purposes of determining any liability under the Securities
Act of 1933, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at
that time shall be deemed to be the initial BONA FIDE offering thereof.
II-3
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, ENRON
CERTIFIES THAT IT HAS REASONABLE GROUNDS TO BELIEVE THAT IT MEETS ALL OF THE
REQUIREMENTS FOR FILING ON FORM S-3 AND HAS DULY CAUSED THIS REGISTRATION
STATEMENT OR AMENDMENT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED,
THEREUNTO DULY AUTHORIZED, IN THE CITY OF HOUSTON AND STATE OF TEXAS, ON THE
6TH DAY OF DECEMBER, 1995.
ENRON CORP.
(Registrant)
By: KURT S. HUNEKE
KURT S. HUNEKE
VICE PRESIDENT, FINANCE AND
TREASURER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THIS
REGISTRATION STATEMENT OR AMENDMENT HAS BEEN SIGNED BY THE FOLLOWING PERSONS
IN THE CAPACITIES WITH ENRON CORP. INDICATED AND ON THE 6TH DAY OF DECEMBER,
1995.
SIGNATURE TITLE
- ----------------------------- ------------------------------------------------
KENNETH L. LAY Chairman of the Board, Chief Executive Officer
(KENNETH L. LAY) and Director (Principal Executive Officer)
JACK I. TOMPKINS Senior Vice President and Chief Information,
(JACK I. TOMPKINS) Administrative and Accounting Officer (Principal
Accounting Officer)
KURT S. HUNEKE Vice President, Finance and Treasurer (Principal
(KURT S. HUNEKE) Financial Officer)
ROBERT A. BELFER* Director
(ROBERT A. BELFER)
NORMAN P. BLAKE, JR.* Director
(NORMAN P. BLAKE, JR.)
JOHN H. DUNCAN* Director
(JOHN H. DUNCAN)
JOE H. FOY* Director
(JOE H. FOY)
WENDY L. GRAMM* Director
(WENDY L. GRAMM)
ROBERT K. JAEDICKE* Director
(ROBERT K. JAEDICKE)
II-4
RICHARD D. KINDER* Director and President and Chief
(RICHARD D. KINDER) Operating Officer
CHARLES A. LEMAISTRE* Director
(CHARLES A. LEMAISTRE)
JOHN A. URQUHART* Director
(JOHN A. URQUHART)
JOHN WAKEHAM* Director
(JOHN WAKEHAM)
CHARLS E. WALKER* Director
(CHARLS E. WALKER)
HERBERT S. WINOKUR, JR.* Director
(HERBERT S. WINOKUR, JR.)
*By: PEGGY B. MENCHACA
PEGGY B. MENCHACA
(ATTORNEY-IN-FACT FOR PERSONS
INDICATED)
II-5
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION PAGE
- ------- ----------- ----
**1 -- Form of Underwriting Agreement for Exchangeable Notes.
*4(a) -- Indenture dated as of November 1, 1985, between Enron and Harris
Trust and Savings Bank (Form T-3 Application for Qualification of
Indentures under the Trust Indenture Act of 1939, File No. 22-14390,
filed October 24, 1985).
**4(b) -- Form of First Supplemental Indenture between Enron and Harris
Trust and Savings Bank, as Trustee.
5 -- Opinion of James V. Derrick, Jr., Esq., Senior Vice President and
General Counsel of Enron, as to validity of the Exchangeable Notes.
8 -- Opinion of Vinson & Elkins L.L.P. regarding certain tax matters.
10 -- Form of 1995 Tax Allocation Agreement between Enron and Enron Oil &
Gas Company.
**12 -- Computations of Ratios of Earnings to Fixed Charges.
23(a) -- Consents of Arthur Andersen LLP.
**23(b) -- Consent of DeGolyer and MacNaughton.
23(c) -- The consent of James V. Derrick, Jr., Esq., is contained in his
opinion filed as Exhibit 5 hereto.
**24 -- Powers of Attorney.
**25 -- Form T-1 Statement of Eligibility under the Trust Indenture Act
of 1939 of Harris Trust and Savings Bank.
- ------------
* Incorporated by reference as indicated.
** Previously filed.
<PAGE>
EXHIBIT 5
December 6, 1995
Enron Corp.
1400 Smith Street
Houston, Texas 77002
Gentlemen:
As Senior Vice President and General Counsel of Enron Corp., a Delaware
corporation ("Enron"), I am familiar with its registration statement on Form S-3
(the "Registration Statement") relating to the proposed offering of Enron
Exchangeable Notes (the "Exchangeable Notes"), which will be mandatorily
exchanged by Enron into a number of shares of Enron Oil & Gas Company Common
Stock or, at Enron's option, cash with equal value. In connection therewith, I
have examined, among other things, a copy of the Restated Certificate of
Incorporation and Bylaws of Enron, the corporate proceedings taken to date with
respect to the authorization, issuance and sale of the Exchangeable Notes, a
copy of the Indenture dated as of November 1, 1985 (the "Indenture") between
Enron and Harris Trust and Savings Bank, Trustee, as supplemented, and the forms
of certain other agreements to be entered into by Enron, and I have performed
such other investigations as I have considered appropriate as the basis for the
opinions expressed herein.
Based on the foregoing, I am of the opinion that:
(1) Enron is a corporation duly organized, validly existing and in good
standing under the laws of the State of Delaware.
(2) The Exchangeable Notes of Enron have been validly authorized for
issuance, and (subject to the Registration Statement becoming effective and any
applicable state securities or Blue Sky laws being complied with), when the
terms thereof and their issue and sale have been duly established, upon issuance
and delivery thereof as set forth in the Registration Statement, and upon
receipt by Enron of the purchase price thereof, the Exchangeable Notes will be
validly issued and will be binding obligations of Enron.
I am a member of the bar of the State of Texas. The opinion set forth
above is limited in all respects to the laws of the State of Texas, the General
Corporation Law of the State of Delaware and federal law.
Enron Corp.
December 6, 1995
Page 2
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I hereby consent to the filing of this opinion as an exhibit to the
Registration Statement and to the references to me under the caption "Validity
of the Exchangeable Notes" in the Prospectus constituting part of the
Registration Statement and to the filing of this opinion as an exhibit thereto.
By giving such consent I do not admit that I am an expert with respect to any
part of the Registration Statement, including this exhibit, within the meaning
of the term "expert" as used in the Securities Act of 1933, as amended, or the
rules and regulations of the Securities and Exchange Commission issued
thereunder.
Very truly yours,
/s/ JAMES V. DERRICK, JR.
James V. Derrick, Jr.
<PAGE>
EXHIBIT 8
(713) 758-2194 (713) 615-5660
December 5, 1995
Enron Corp.
1400 Smith Street
Houston, Texas 77002-7369
Ladies and Gentlemen:
We have participated in the preparation of the Registration Statement
on Form S-3 (Registration No. 33-64057) (such Registration Statement, as amended
at the effective date thereof being referred to herein as the "Registration
Statement") filed with the Securities and Exchange Commission under the
Securities Act of 1933, as amended (the "Securities Act"), with respect to the
registration of Exchangeable Notes of Enron Corp., as well as the prospectus
relating thereto and included as part of the Registration Statement (the
"Prospectus").
The statements in the Prospectus under the caption "Certain United
States Federal Income Tax Considerations" have been prepared by us and, in our
opinion, are based upon reasonable interpretations of law in effect as of the
date hereof. Because of the absence of authority as to the proper
characterization of the Exchangeable Notes for federal income tax purposes, no
assurance can be given, however, that the Internal Revenue Service will accept,
or that a court will uphold, such interpretations.
We hereby consent to the references to this firm under the captions
"Certain United States Federal Income Tax Considerations" and "Validity of the
Exchangeable Notes" in the Prospectus and to the filing of this opinion as an
exhibit to the Registration Statement. By giving such consent, we do not admit
that we are within the category of persons whose consent is required under
Section 7 of the Securities Act or the rules and regulations of the Commission
issued thereunder.
Very truly yours,
VINSON & ELKINS L.L.P.
<PAGE>
EXHIBIT 10
1995 TAX ALLOCATION AGREEMENT
THIS 1995 TAX ALLOCATION AGREEMENT ("Agreement") is entered into
effective as of the Deconsolidation Date being December ___, 1995 between Enron
Corp., a Delaware corporation with its principal place of business being
Houston, Texas ("Enron"), Enron Oil & Gas Company, also a Delaware corporation
with its principal place of business being Houston, Texas ("EOG"), and those
domestic subsidiaries of EOG listed below as additional parties. (Enron, EOG,
and those EOG subsidiaries listed below are hereinafter collectively referred to
as the "Parties" and singularly as a "Party", while EOG and its domestic
subsidiaries are collectively referred to as "EOG").
RECITALS
WHEREAS, Enron and EOG previously entered into that certain First
Amended and Restated Tax Allocation Agreement (hereinafter the "Base Agreement")
executed in August 1991 generally providing for the apportionment and allocation
of federal income and other tax liabilities between the Parties; and
WHEREAS, the Parties subsequently modified the terms of the Base
Agreement, as reflected in Modification "A" to the First Amended and Restated
Tax Allocation Agreement executed in 1992 (the Base Agreement and Modification
"A" are hereinafter collectively referred to as the "Earlier Agreements") so as
to further specify their agreement as to the apportionment and allocation of
federal income and other tax liabilities; and
WHEREAS, Enron is considering selling a certain number of shares of
common stock that it owns in EOG, thus reducing its ownership interest in EOG
below 80 percent and thereby precluding Enron from continuing to include EOG in
the consolidated federal income tax returns prepared by Enron as common parent
for the taxable periods following the Deconsolidation Date;
WHEREAS, EOG has represented in various public statements that the
Deconsolidation, when coupled with the effectiveness of the Earlier Agreements
and this Agreement, will not have a material adverse effect on its financial
condition or results of operations; and
WHEREAS, the Earlier Agreements do not fully address the obligations of
the Parties vis-a-vis one another upon Deconsolidation; and
WHEREAS, the Parties have agreed to change certain of the provisions of
the Earlier Agreements and thus would like to memorialize such agreement
regarding their respective rights, obligations, and intentions as to any tax
payments to be made by EOG to Enron or by Enron to EOG during the
Post-Deconsolidation Date Period but related to the Pre-Consolidation Date
Period and, in particular, the Parties' rights, obligations, and intentions with
respect to (i) paragraph 7 of Modification "A" and (ii) any refund of Taxes to
be received by the Consolidated Group attributable to the four years from 1988
through and including 1991, and have such terms generally supersede those of the
Earlier Agreements.
NOW, THEREFORE, the Parties to this Agreement agree as follows:
ARTICLE I
DEFINITIONS
1.1 DEFINITIONS: As used in this Agreement, the following terms have
the following meanings:
"Code" means the Internal Revenue Code of 1986, as amended, or
corresponding provisions of any subsequent federal tax laws.
"Consolidated Group" means the "affiliated group" of corporations of
which Enron is the "common parent corporation", as such terms are defined in
Code ss. 1504(a)(1).
"Consolidated Minimum Tax Credit(s)" means the consolidated minimum tax
credit(s) computed in accordance with Code ss.ss. 53, 1502, and 1503, and shown
on a Consolidated Return with respect to those tax periods up to and including
the Deconsolidation Date.
"Consolidated Return" means the consolidated federal income tax return
of the Consolidated Group for each taxable year as filed or to be filed by Enron
on behalf of the Consolidated Group.
"Consolidated Tax Liability" means, generally, the consolidated federal
income tax liability computed in accordance with Treasury Regulation ss.
1.1502-2 and shown on a Consolidated Return, taking into account all credits to
which the Consolidated Group is entitled under the Code, but not taking into
account any "consolidated alternative minimum tax liability" (as provided under
Code ss.ss. 55, 1502, and 1503) or any Consolidated Minimum Tax Credit.
"Deconsolidation" means that event which causes Enron to no longer have
the requisite ownership interest in EOG so as to allow the Parties to file as a
Consolidated Group.
"Deconsolidation Date" means that date when Enron and EOG no longer
constitute a Consolidated Group.
"Earlier Agreements" has that meaning ascribed to it in the Recitals.
"Party" and "Parties" have that meaning ascribed to them in the
Recitals.
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"Pre-Deconsolidation Date Period" means, chronologically, those tax
years prior to the 1995 tax year plus that period in time beginning January 1,
1995 and ending on and including the Deconsolidation Date.
"Post-Deconsolidation Date Period" means, chronologically, that period
following the Deconsolidation Date.
"Taxes" or "Tax" means federal income taxes as provided in Code ss. 11,
alternative minimum tax as provided in Code ss. 55, and any state taxes measured
by net income (including state taxes measured by net income reflected in any
Unitary Tax Returns filed by Enron) and any interest or penalties thereon. The
term Taxes or Tax, however, specifically excludes any tax imposed by any foreign
government.
"Unitary Tax Return" means a state income tax return which reflects the
combined and/or consolidated reporting (either on a domestic or worldwide basis)
of Enron and its affiliates for a state which either (i) imposes its income tax
on its apportioned and/or allocable share of the net income and its United
States affiliates that are engaged in a "unitary business", part of which is
conducted in the state or (ii) imposes its income tax on its apportioned and/or
allocable share of the net income of a taxpayer and its affiliates--both
domestic and foreign--that are engaged in a unitary business.
Other terms defined herein have the meanings given them.
ARTICLE II
TAX INDEMNIFICATION
2.1 ENRON'S TAX INDEMNIFICATION FOR THE PRE-DECONSOLIDATION DATE
PERIOD: Enron shall be liable for, indemnify, and hold EOG harmless for all
Taxes (i) imposed on or incurred by EOG for the Pre-Deconsolidation Date Period
and (ii) equitably apportioned to EOG by Enron for all tax periods beginning
before and ending after the Deconsolidation Date. Enron, in turn, shall be
entitled to receive all refunds of Taxes attributable to the Pre-Deconsolidation
Date Period, if any, from either the applicable tax authorities or EOG (in the
event such refund(s) have been made directly to EOG), except with respect to the
$10.5 million amount set forth in Section 2.3(a) below.
2.2 EOG'S 1995 TAX LIABILITY AND PAYMENT
(a) EOG's sole liability for Taxes for the portion of the
Pre-Deconsolidation Date Period attributable to the 1995 tax year shall be based
on EOG's preparation of its portion of Enron's 1995 Consolidated Return and
Enron's review thereof. Any discrepancies between EOG's return position and
Enron's subsequent review shall be resolved by consultation by each Party's
respective tax officers and Enron's ultimate determination shall be controlling
as long as such determination does not have a material adverse effect on EOG's
financial condition or results of operations.
-3-
(b) The Parties agree that in determining EOG's allocable
share of the (i) Unitary and (ii) Consolidated Tax Liabilities for the 1995 tax
year that they shall follow the allocation and methodology set forth in the
Earlier Agreements.
(c) EOG shall pay Enron its allocable share of the estimated
Unitary and Consolidated Tax Liabilities for the 1995 tax year, net of any 1995
Code ss. 29 credits, within 45 days from the Deconsolidation Date. A "true-up"
payment, should one be necessary, shall be made by EOG to Enron or Enron to EOG
within 15 days after Enron's subsequent determination of EOG's liability based
on taxable income and tax credits reported as part of Enron's 1995 Unitary and
Consolidated Returns and EOG's separate state Tax returns.
(d) Enron shall be liable for, indemnify, and hold EOG
harmless for all Taxes attributable to the event of Deconsolidation.
2.3 OTHER PAYMENTS TO BE MADE BETWEEN THE PARTIES
(a) Enron is obligated to pay to EOG $10.5 million
attributable to a federal income tax refund to be received by Enron for the four
tax years from 1988 through and including 1991.
(b) In consideration of Enron's tax indemnification as set
forth in Section 2.1 to this Agreement, EOG shall be obligated to pay to Enron
$8 million no later than on the Deconsolidation Date.
(c) In the event Enron has not paid EOG the $10.5 million
refund amount by the Deconsolidation Date, EOG shall have the right to offset
its $8 million indemnification payment obligation to Enron by such $10.5 million
sum thus resulting in a net payment by Enron to EOG of $2.5 million no later
than on the Deconsolidation Date.
ARTICLE III
MINIMUM TAX CREDIT
AND RELATED MATTERS ASSOCIATED WITH DECONSOLIDATION
3.1 CONSOLIDATED MINIMUM TAX CREDIT
(a) As currently calculated by Enron, no Consolidated Minimum
Tax Credits have been allocated to EOG by Enron based on Consolidated Returns
filed through tax year ended December 31, 1994 under the methodology followed
for the Pre-Deconsolidation Date Period and Enron has not made any determination
of EOG's allocable share of Consolidated Minimum Tax Credits for the 1995 tax
year. In the event Consolidated Minimum Tax Credits are allocated to EOG, EOG
shall be obligated to reimburse Enron for the amount of such credits allocated
to EOG upon the occurrence of the earlier of the following two events:
-4-
(i) The date of EOG's filing of its federal income
tax return for the tax year in the Post-Deconsolidation Date Period
when EOG utilizes any reallocated Consolidated Minimum Tax Credits; or
(ii) The date of Enron's filing its federal income
tax return for the tax year in the Post-Deconsolidation Date Period
when Enron could have utilized such Consolidated Minimum Tax Credits
but is precluded from doing so because of the reallocation to EOG.
(b) For purposes of Section 3.1(a)(ii), no Consolidated
Minimum Tax Credits will be considered usable by Enron until Enron could have
first utilized all Consolidated Minimum Tax Credits remaining with Enron after
the reallocation. Any minimum tax credits generated by Enron in the
Post-Deconsolidation Date Period shall be disregarded in making this
determination. For purposes of Section 3.1(a)(i), no Consolidated Minimum Tax
Credits will be considered as utilized by EOG until EOG first utilizes all
minimum tax credits it has generated in the Post-Deconsolidation Date Period.
(c) For purposes of Section 3.1(a), any payments to be made
between EOG and Enron may be made for more than one tax year of the
Post-Deconsolidation Date Period until the reallocated Consolidated Minimum Tax
Credit is used (or could have been used) in its entirety.
3.2 CONSOLIDATED MINIMUM TAX CREDIT ALLOCATION ADJUSTMENTS: In the
event the amount of the Consolidated Minimum Tax Credits allocated to EOG are
adjusted resulting in a reduction of Consolidated Minimum Tax Credits previously
utilized by EOG and a payment has been made by EOG to Enron pursuant to the
terms of Section 3.1, Enron shall be obligated to pay EOG for any assessment
made against it by the Internal Revenue Service attributable to such adjustment.
Payment shall be made by Enron to EOG on the day EOG pays the Internal Revenue
Service for such assessment.
ARTICLE IV
AUDITS AND OTHER TAX PROCEEDINGS
4.1 GENERAL COOPERATION AND EXCHANGE OF INFORMATION
(a) EOG shall provide, or cause to be provided, to Enron
copies of all correspondence received from any taxing authority by EOG in
connection with the liability of the Parties for Taxes for the
Pre-Deconsolidation Date Period. EOG shall also provide Enron with access to or
copies of any materials requested by Enron which would assist Enron in resolving
any tax matters for the Consolidated Group for the Pre-Deconsolidation Date
Period. Further, the Parties will provide each other with such cooperation and
information as they may reasonably request of each other in preparing or filing
any return, amended return, or claim for refund, in determining liability or
right of refund, or in conducting any audit or other proceeding, in respect of
Taxes
-5-
imposed on the Parties or their respective affiliates including, by way of
example, information relating to net operating losses, foreign tax credits,
overall foreign losses, and excess loss accounts..
(b) Enron on one hand and EOG on the other hand and their
affiliates will preserve and retain all returns, schedules, workpapers, and all
material records or other documents relating to any such returns, claims,
audits, or other proceedings until the expiration of the statutory period of
limitations (including extensions) of the taxable periods to which such
documents relate and until the final determination of any payments which may be
required with respect to such periods under this Agreement and shall make such
documents available at the then-current corporate headquarters of such Party to
the other Party or any affiliate thereof, and their respective officers,
employees, and agents, upon reasonable notice and at reasonable times, it being
understood that such representative shall be entitled to make copies of any such
books and records relating to Enron or EOG as they shall deem necessary.
(c) Enron on one hand and EOG on the other hand further agree
to permit representatives of the other Party or any affiliate thereof to meet
with employees of such Party on a mutually convenient basis in order to enable
such representatives to obtain additional information and explanations of any
documents provided pursuant to this Section 4.1. Enron on one hand and EOG on
the other hand shall make available to the representatives of the other Party or
any affiliate thereof sufficient workspace and facilities to perform the
activities described in this Section. Any information obtained pursuant to this
Section 4.1 shall be kept confidential, except as may be otherwise necessary in
connection with the filing of returns or claims for refund or in conducting any
audit or other proceeding. Each Party shall provide the cooperation and
information required by this Section 4.1 at its own expense.
4.2 AUDITS: In the event of an audit by the Internal Revenue Service,
or by any state or local tax authority, of a return filed by Enron for the
Pre-Deconsolidation Date Period, Enron shall give EOG timely and reasonable
notice of audit proceedings and EOG will provide all necessary information and
other assistance reasonably requested by Enron with respect to issues concerning
the activities of EOG. All communications with the Internal Revenue Service
concerning such audit will be made by Enron unless otherwise agreed between the
Parties hereto.
4.3 MATERIAL ADVERSE IMPACT TO EOG: Notwithstanding the provisions of
Section 4.2, the Parties agree that in no event shall Enron file any amended tax
return, claim for refund, or make any tax election affecting the
Pre-Deconsolidation Date Period that would have any material adverse impact on
EOG's financial condition or results of operations without first obtaining the
written permission of EOG.
-6-
ARTICLE V
UNITARY TAX RETURNS
FOR POST-DECONSOLIDATION DATE PERIOD FILINGS
Enron agrees to continue to file any Unitary Tax Returns and allocate
Unitary tax liability for the Post-Deconsolidation Date Period in which the
operations of EOG are reflected in a manner consistent with the methodology
followed for the Pre-Deconsolidation Date Period.
ARTICLE VI
OTHER PROVISIONS
6.1 EFFECT OF THE AGREEMENT: The obligations of the Parties set forth
under this Agreement shall be unconditional and absolute, and shall remain in
effect without limitation as to time. Further, all prior tax sharing and
allocation agreements between Enron and EOG (including the Earlier Agreements)
shall terminate effective as of the Deconsolidation Date, except that those
provisions of the Earlier Agreement regarding the allocation of Consolidated Tax
Liability shall remain in effect for the 1995 tax year until the provisions of
Section 2.2 of this Agreement are fully implemented by the Parties.
6.2 CONFLICT OR AMBIGUITY: Because the terms of this Agreement
generally supersede the terms of the Earlier Agreements, the Parties agree that
if there is any conflict or ambiguity between the Earlier Agreements and this
Agreement the terms of this Agreement shall control.
6.3 ASSIGNABILITY: The rights and obligations of the Parties under this
Agreement may not be assigned by a Party without the prior written consent of
the other Party to this Agreement.
6.4 GOVERNING LAW: This Agreement shall be governed by the laws of the
state of Texas.
IN WITNESS WHEREOF, the Parties hereto have caused their names to be
subscribed and executed by the respective authorized officers on the dates
indicated, effective as of the date first written above.
ENRON CORP.
By:____________________________________
Robert J. Hermann
Vice President, Tax
ENRON OIL & GAS COMPANY
By:____________________________________
Susan M. Murray
Vice President, Tax
ENRON OIL & GAS INTERNATIONAL, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-TRINIDAD, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-AUSTRALIA, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-FRANCE, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
-8-
EOGI-RUSSIA, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-QATAR, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-UZBEKISTAN, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-KUWAIT, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
ENRON OIL & GAS-CARTHAGE, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
-9-
ERSO, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
ENRON OIL & GAS PROPERTY MANAGEMENT, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
ENRON OIL & GAS MARKETING, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
I N HOLDINGS, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
NILO OPERATING COMPANY
By:____________________________________
Susan M. Murray
Vice President, Tax
-10-
EOGI-TRINIDAD U(a) BLOCK, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
EOGI-ALGERIA, INC.
By:____________________________________
Susan M. Murray
Vice President, Tax
-11-
EOGI TRINIDAD COMPANY
By:____________________________________
Dennis M. Ulak
Assistant Secretary
EOGI AUSTRALIA COMPANY
By:____________________________________
Dennis M. Ulak
Assistant Secretary
EOGI-KAZAKHSTAN, INC.
By:____________________________________
Dennis M. Ulak
Assistant Secretary
EOGI-INDIA, INC.
By:____________________________________
Dennis M. Ulak
Assistant Secretary
EOGI-CHINA, INC.
By:____________________________________
Dennis M. Ulak
Assistant Secretary
-12-
EOGI-UNITED KINGDOM, INC.
By:____________________________________
Angus H. Davis
Assistant Secretary
-13-
ENRON OIL & GAS INVESTMENTS, INC.
By:____________________________________
Douglas Weaver
President
-14-
<PAGE>
EXHIBIT 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in this Registration Statement of our reports dated February 17, 1995
included in Enron Corp.'s Annual Report on Form 10-K for the year ended December
31, 1994 and to all references to our Firm included in this Registration
Statement.
ARTHUR ANDERSEN LLP
Houston, Texas
December 6, 1995
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in this Registration Statement of our report on the consolidated
financial statements of Enron Oil & Gas Company and subsidiaries dated February
17, 1995, included in Enron Oil & Gas Company's Form 10-K for the year ended
December 31, 1994, and to all references to our Firm included in this
Registration Statement.
ARTHUR ANDERSEN LLP
Houston, Texas
December 6, 1995
