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<SEC-DOCUMENT>0000950129-01-001563.txt : 20010323
<SEC-HEADER>0000950129-01-001563.hdr.sgml : 20010323
ACCESSION NUMBER: 0000950129-01-001563
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 13
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010322
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: EL PASO CORP/DE
CENTRAL INDEX KEY: 0001066107
STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922]
IRS NUMBER: 760568816
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-14365
FILM NUMBER: 1575201
BUSINESS ADDRESS:
STREET 1: 1001 LOUISIANA ST
STREET 2: EL PASCO ENERGY BLDG
CITY: HOUSTON
STATE: TX
ZIP: 77002
BUSINESS PHONE: 7134202131
MAIL ADDRESS:
STREET 1: 1001 LOUISIANA ST
CITY: HOUSTON
STATE: TX
ZIP: 77002
FORMER COMPANY:
FORMER CONFORMED NAME: EL PASO ENERGY CORP/DE
DATE OF NAME CHANGE: 19980716
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>h82590e10-k405.txt
<DESCRIPTION>EL PASO CORPORATION - YEAR ENDED DECEMBER 31, 2000
<TEXT>
<PAGE> 1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO .
COMMISSION FILE NUMBER 1-14365
EL PASO CORPORATION
(FORMERLY EL PASO ENERGY CORPORATION)
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0568816
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
</TABLE>
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2131
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
<S> <C>
Common Stock, par value $3 per New York Stock Exchange
share...............................
Preferred Stock Purchase Rights....... New York Stock Exchange
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT.
Aggregate market value of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of March 16, 2001,
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $35,108,511,995
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Common Stock, par value $3 per share. Shares outstanding on March 16, 2001:
508,892,767
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: Portions of our definitive Proxy Statement for the 2001 Annual
Meeting of Stockholders, to be filed not later than 120 days after the end of
the fiscal year covered by this report, are incorporated by reference into Part
III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 2
EL PASO CORPORATION
TABLE OF CONTENTS
<TABLE>
<CAPTION>
CAPTION PAGE
------- ----
<S> <C> <C>
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 16
Item 3. Legal Proceedings........................................... 16
Item 4. Submission of Matters to a Vote of Security Holders......... 16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 17
Item 6. Selected Financial Data..................................... 18
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 19
Risk Factors and Cautionary Statement for Purposes of the
"Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995... 31
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 37
Item 8. Financial Statements and Supplementary Data................. 40
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 84
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 84
Item 11. Executive Compensation...................................... 84
Item 12. Security Ownership of Management............................ 84
Item 13. Certain Relationships and Related Transactions.............. 84
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 84
Signatures.................................................. 89
</TABLE>
- ---------------
Below is a list of terms that are common to our industry and used
throughout this document:
<TABLE>
<S> <C>
/d = per day
Bbl = barrels
BBtu = billion British thermal units
= billion British thermal unit
BBtue equivalents
Bcf = billion cubic feet
MBbls = thousand barrels
MMBbls = million barrels
MMBtu = million British thermal units
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
MMcf = million cubic feet
MMcfe = million cubic feet of gas equivalents
Mgal = thousand gallons
MWh = megawatt hours
MMWh = thousand megawatt hours
Tcfe = trillion cubic feet of gas equivalents
</TABLE>
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Also, when we refer to cubic feet measurements, all measurements
are at 14.73 pounds per square inch.
i
<PAGE> 3
PART I
ITEM 1. BUSINESS
GENERAL
We are a global energy company originally founded in 1928 in El Paso,
Texas. For many years, we served as a regional pipeline company conducting
business mainly in the western United States. However, over the past five years,
we have grown into a company whose operations span the wholesale energy value
chain, from natural gas production and extraction to power generation. Our
substantial growth during this period has been accomplished through a series of
strategic acquisitions, transactions, and internal growth initiatives, each of
which has enhanced and improved our competitive abilities in the U.S. and global
energy markets. Significant milestones include:
<TABLE>
<CAPTION>
YEAR TRANSACTION IMPACT
- ---- ----------- ------
<S> <C> <C>
1995 Acquisition of Eastex Energy Inc. Signaled our entry into the wholesale
energy marketing business.
1996 $4 billion acquisition of the energy Expanded our U.S. interstate pipeline
businesses of Tenneco Inc. system from coast to coast and signaled our
entry into the international energy market.
1998 Acquisition of DeepTech International, Inc. Expanded our U.S. onshore and offshore
gathering capacity and capabilities.
1999 $6 billion merger with Sonat Inc. Expanded our pipeline operations into the
southeast portion of the U.S. and signaled
our entrance into the exploration and
production business through the addition of
1.5 Tcfe of natural gas reserves.
Creation of $1.1 billion Electron structure Provided the vehicle through which we have
become a significant non-utility generator
of power.
2000 Acquisition of PG&E's Texas Midstream Expanded our midstream operations to cover
operations a majority of the metropolitan markets and
industrial hubs in the state of Texas.
2001 Completion of our $24 billion merger with This merger places us as a top tier
The Coastal Corporation participant in every aspect of the
wholesale energy marketplace.
</TABLE>
With each significant merger and acquisition, we have evaluated our
processes and organizational structure to achieve cost savings and operating
efficiencies. These actions have included restructuring our workforce and
consolidating our operations. These activities occurred again following the
completion of our merger with Coastal in January 2001. Also during this period,
we have completed numerous smaller acquisitions and transactions to enhance and
expand the scope of our core operations and activities. The discussion of our
operations and segments that follows in this document does not include the
activities or operations of The Coastal Corporation.
OPERATIONS
Our principal operations include:
- the transportation, gathering, processing, and storage of natural gas;
- the marketing of energy and energy-related commodities and products;
- the generation of power;
- the development and operation of energy infrastructure facilities; and
- the exploration and production of natural gas and oil.
1
<PAGE> 4
Our Pipelines segment owns or has interests in approximately 38,000 miles
of interstate natural gas pipelines in the U.S. Our systems connect the nation's
principal natural gas supply regions to the five largest consuming regions in
the United States: the Gulf Coast, California, the Northeast, the Midwest, and
the Southeast. These operations represent one of the largest, and only,
integrated coast-to-coast mainline natural gas transmission systems in the U.S.
Our pipeline systems also own or have interests in over 150 Bcf of storage
capacity used to provide a variety of services to our customers.
Our Merchant Energy segment is involved in a broad range of activities in
the energy marketplace including asset ownership, trading and risk management
and financial services. We are one of North America's largest wholesale energy
commodity marketers and traders, and buy, sell, and trade natural gas, power,
and other energy commodities in the U.S. and internationally. We are also a
significant non-utility owner of electric generating capacity with 64 facilities
in 16 countries. Most recently, we have announced our expansion into the
liquefied natural gas business, capitalizing upon the increasing U.S. and
worldwide demand for natural gas. The financial services businesses of Merchant
Energy invest in emerging businesses to facilitate growth in the U.S. and
Canadian energy markets. As a global energy merchant, we evaluate and measure
risks inherent in the markets we serve, and use sophisticated systems and
integrated risk management techniques to manage those risks.
Our Field Services segment provides natural gas gathering, products
extraction, fractionation, dehydration, purification, compression and intrastate
transmission services. These services include gathering of natural gas from more
than 11,000 natural gas wells with over 19,000 miles of natural gas gathering
and natural gas liquids pipelines, and 20 natural gas processing, treating, and
fractionation facilities located in some of the most prolific and active
production areas in the U.S., including the San Juan Basin, east and south
Texas, Louisiana, and the Gulf of Mexico. We conduct our intrastate transmission
operations through interests in five intrastate systems, which serve a majority
of the metropolitan areas and industrial load centers in Texas. Our primary
vehicle for growth and development of midstream energy assets is El Paso Energy
Partners, L.P., a publicly traded master limited partnership of which our
subsidiary is the general partner. Through Energy Partners, we provide natural
gas and oil gathering and transportation, storage, and other related services,
principally in the Gulf of Mexico.
Our Production segment leases approximately 2.7 million net acres in 11
states, including Louisiana, New Mexico, Texas, Oklahoma, and Arkansas, as well
as the Gulf of Mexico. We also have exploration and production rights in Turkey.
During 2000, our daily equivalent natural gas production was approximately 0.6
Bcf/d, and our reserves at December 31, 2000 were approximately 1.7 Tcfe.
In addition to our energy activities, we have announced a
telecommunications strategy that will leverage our knowledge of the commodity
and capital markets into the emerging telecommunications market. Our strategy
involves:
- accessing fiber deep within metropolitan markets to aggregate supply in
major U.S. cities;
- utilizing fiber rings and key points of interconnection of major carriers
and service providers to allow for liquidity to develop in major markets;
and
- assembling a high capacity thin fiber national long-haul backbone.
We will overlay against this asset base a merchant-based operating support
system and valuation models that will allow us to apply the merchant skills
developed in our core commodity business to the rapidly changing
telecommunications markets.
SEGMENTS
Our business unit activities are segregated into four primary business
segments: Pipelines, Merchant Energy, Field Services, and Production. These
segments are strategic business units that provide a variety of energy products
and services. During 2000, we combined our International and Merchant Energy
segments to reflect the ongoing globalization of our Merchant Energy strategy
and its operating activities. We manage each
2
<PAGE> 5
segment separately and each requires different technology and marketing
strategies. Our telecommunication business is combined with our corporate and
other activities. For information relating to operating revenues, operating
income, EBIT, and identifiable assets by segment, you should see Item 8,
Financial Statements and Supplementary Data, Note 15, which is incorporated
herein by reference.
PIPELINES
Our Pipelines segment provides natural gas transmission services in the
U.S. We conduct our activities through five wholly owned and two partially owned
interstate systems along with a liquefied natural gas terminalling facility and
natural gas storage facilities. Each of these systems is discussed below:
The TGP system. The Tennessee Gas Pipeline system consists of
approximately 14,700 miles of pipeline with a design capacity of 5,970 MMcf/d.
During 2000, TGP transported natural gas volumes averaging approximately 73
percent of its capacity. This multiple-line system begins in the natural gas-
producing regions of Louisiana, including the Gulf of Mexico, and south Texas
and extends to the northeast section of the U.S., including the New York City
and Boston metropolitan areas. TGP also has an interconnect at the U.S.-Mexico
border. Along its system, TGP has approximately 89 Bcf of underground working
gas storage capacity.
The EPNG system. The El Paso Natural Gas system consists of approximately
9,800 miles of pipeline with a design capacity of 4,744 MMcf/d. During 2000,
EPNG transported natural gas volumes averaging approximately 82 percent of its
capacity. The EPNG system delivers natural gas from the San Juan Basin of
northern New Mexico and southern Colorado and the Permian Basin and Anadarko
Basin to California, which is its single largest market, as well as markets in
Nevada, Arizona, New Mexico, Texas, Oklahoma, and northern Mexico.
The SNG system. The Southern Natural Gas system consists of approximately
8,200 miles of pipeline with a design capacity of 2,834 MMcf/d. During 2000, SNG
transported volumes averaging approximately 73 percent of its capacity. SNG's
interstate pipeline system extends from gas fields in Texas, Louisiana,
Mississippi, Alabama and the Gulf of Mexico to markets in Louisiana,
Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including
the metropolitan areas of Atlanta and Birmingham. SNG is the principal pipeline
supplier to the growing southeastern markets of Alabama and Georgia. In August
2000, the South Georgia Natural Gas system was combined with the SNG system as
part of SNG's rate case settlement. Along its system, SNG has approximately 60
Bcf of underground working gas storage capacity.
The Midwestern system. The Midwestern system consists of approximately 400
miles of pipeline with a design capacity of 785 MMcf/d. During 2000, Midwestern
transported natural gas volumes averaging approximately 33 percent of its
capacity. The Midwestern system connects with the TGP system at Portland,
Tennessee, and extends to Chicago to serve the Chicago metropolitan area. As a
result of our merger with Coastal in January 2001, we will be required to sell
the Midwestern system. We expect to complete the sale in the second quarter of
2001.
The MPC system. The Mojave Pipeline Company system consists of
approximately 400 miles of pipeline with a design capacity of approximately 400
MMcf/d. During 2000, MPC transported natural gas volumes approximating 100
percent of its capacity. The MPC system connects with the EPNG transmission
system at Topock, Arizona and the Kern River Gas Transmission Company system in
California and extends to customers in the vicinity of Bakersfield, California.
Florida Gas Transmission system. We own a 50 percent interest in Citrus
Corp., a holding company that owns 100 percent of Florida Gas Transmission
Company. Florida Gas is the primary pipeline transporter of natural gas in the
state of Florida and the sole pipeline transporter to peninsular Florida. The
system consists of approximately 4,800 miles of interstate natural gas pipelines
with a design capacity of 1,462 MMcf/d. During 2000, Florida Gas transported
volumes averaging approximately 92 percent of its capacity. The system extends
from south Texas to a point near Miami, Florida.
3
<PAGE> 6
Portland Natural Gas Transmission. We own an approximate 19 percent
interest in the Portland Natural Gas Transmission system. Portland consists of
approximately 300 miles of interstate natural gas pipeline with a design
capacity of 215 MMcf/d extending from the Canadian border near Pittsburg, New
Hampshire to Dracut, Massachusetts. During 2000, Portland transported volumes
averaging approximately 51 percent of its capacity.
Southern LNG, Inc. Southern LNG owns a liquefied natural gas receiving
terminal, located on Elba Island, near Savannah, Georgia, capable of achieving a
peak send out of 540 MMcf/d and a base load send out of 333 MMcf/d. Inactive
since the early 1980s, Southern LNG received an order from the Federal Energy
Regulatory Commission (FERC) in March 2000 granting it permission to reactivate
the receiving terminal. We expect the terminal to be in service in the fourth
quarter of 2001.
Bear Creek Storage. Bear Creek Storage Company owns and operates an
underground natural gas storage facility located in Louisiana. The facility has
a capacity of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek's
working storage capacity is committed equally to the TGP and SNG systems under
long-term contracts.
Regulatory Environment
Our interstate natural gas systems and storage operations are regulated by
FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
Each system operates under separate FERC approved tariffs that establish rates,
terms, and conditions under which each system provides services to its
customers. Generally, FERC's authority extends to:
- transportation of natural gas, rates, and charges;
- certification and construction of new facilities;
- extension or abandonment of services and facilities;
- maintenance of accounts and records;
- depreciation and amortization policies;
- acquisition and disposition of facilities;
- initiation and discontinuation of services; and
- various other matters.
Our wholly owned and investee pipelines have tariffs established through
filings with FERC that have a variety of terms and conditions, each of which
affects its operations and its ability to recover fees for the services it
provides. By and large, changes to these fees or terms can only be implemented
upon approval by FERC.
Our interstate pipeline systems are also subject to the Natural Gas
Pipeline Safety Act of 1968 that establishes pipeline and liquefied natural gas
plant safety requirements, the National Environmental Policy Act, and other
environmental legislation. Each of our systems has a continuing program of
inspection designed to keep all of our facilities in compliance with pollution
control and pipeline safety requirements. We believe that our systems are in
substantial compliance with the applicable requirements.
For a further discussion of significant rate and regulatory matters, see
Item 8, Financial Statements and Supplementary Data, Note 11.
Markets and Competition
Our interstate systems face varying degrees of competition from alternative
energy sources, such as electricity, hydroelectric power, coal, and fuel oil.
Also, the potential consequences of proposed and ongoing restructuring and
deregulation of the electric power industry are currently unclear. Restructuring
and deregulation may benefit the natural gas industry by creating more demand
for natural gas turbine generated
4
<PAGE> 7
electric power, or it may hamper demand by allowing a more effective use of
surplus electric capacity through increased wheeling as a result of open access.
TGP. TGP's customers include natural gas producers, marketers and
end-users, as well as other gas transmission and distribution companies, none of
which individually represents more than 10 percent of the revenues on TGP's
system. Currently, over 70 percent of TGP's capacity is subject to firm
contracts expiring after 2001. These contracts have an average term in excess of
five years. TGP continues to pursue future markets and customers for the
capacity that is not committed beyond 2001 and expects this capacity will be
placed under a combination of long-term and short-term contracts. However, there
can be no assurance that TGP will be able to replace these contracts or that the
terms of new contracts will be as favorable to TGP as the existing ones.
In a number of key markets, TGP faces competitive pressures from other
major pipeline systems, which enable local distribution companies and end-users
to choose a supplier or switch suppliers based on the short-term price of
natural gas and the cost of transportation. Competition among pipelines is
particularly intense in TGP's supply areas, Louisiana and Texas. In some
instances, TGP has had to discount its transportation rates in order to maintain
market share. The renegotiation of TGP's expiring contracts may be adversely
affected by these competitive factors.
EPNG. EPNG faces competition from other pipeline companies that transport
natural gas to the California market. EPNG's current capacity to deliver natural
gas to California is approximately 3.3 Bcf/d, and the combined capacity of all
pipeline companies serving the California market is approximately 6.9 Bcf/d. In
2000, the demand for interstate pipeline capacity to California averaged 5.4
Bcf/d, equivalent to approximately 78 percent of the total interstate pipeline
capacity serving that state. Natural gas shipped to California across the EPNG
system represented approximately 35 percent of the natural gas consumed in the
state in 2000. EPNG's ability to remarket its capacity under expiring contracts
may be adversely affected by excess capacity into California.
The significant customers served by EPNG in California during 2000 included
Southern California Gas Company, with capacity of 1,150 MMcf/d under contract
until August 2006, and Merchant Energy, with capacity of 1,221 MMcf/d under
contract through May 2001. In February 2001, EPNG completed its open season on
the capacity held by Merchant Energy and all of the available capacity was
re-subscribed. Contracts were awarded to 30 different entities, including 271
MMcf/d to Merchant Energy, all at published tariff rates under contracts with
durations from 17 months to 15 years.
SNG. SNG's customers include distribution and industrial customers,
electric generation companies, gas producers, other gas pipelines and gas
marketing and trading companies. SNG provides transportation services in both
its natural gas supply and market areas. SNG's contracts to provide firm
transportation service for its customers are for varying amounts and periods of
time. Substantially all of the firm transportation capacity currently available
in SNG's two largest market areas is fully subscribed. The significant customers
served by SNG include:
- Atlanta Gas Light Company, with capacity of 770 MMcf/d under contracts
that expire beginning in 2005 through 2007, with the majority expiring in
2005;
- Alabama Gas Corporation, with capacity of 384 MMcf/d under contracts that
expire beginning in 2005 through 2008, with the majority expiring in
2008; and
- South Carolina Pipeline Corporation, with capacity of 188 MMcf/d under
contract which expires primarily in 2005.
Nearly all of SNG's firm transportation contracts automatically extend the
term for additional months or years unless notice of termination is given by one
of the parties.
Competition among pipelines is strong in a number of SNG's key markets.
Customers purchase natural gas supply from producers and natural gas marketing
companies in unregulated transactions and contract with SNG for transportation
services to deliver this supply to their markets. SNG's three largest customers
are able
5
<PAGE> 8
to obtain a significant portion of their natural gas requirements through
transportation from other pipelines. In addition, SNG competes with several
pipelines for the transportation business of many of its other customers. The
competition with such pipelines is intense, and SNG must, at times, discount its
transportation rates in order to maintain market share.
MERCHANT ENERGY
Our Merchant Energy segment is a market maker involved in a broad range of
activities in the wholesale energy marketplace, including asset ownership,
trading and risk management, and financial services. Merchant Energy is
organized into six functional units, each with complementary activities that
support our overall global merchant energy model. These units are:
- Marketing and Origination;
- Trading and Risk Management;
- Power Generation;
- LNG;
- Financial Services; and
- Operations.
Marketing and Origination. The Marketing and Origination unit provides
energy solutions in natural gas, power, and other energy commodity markets. This
unit also markets capacity from power and natural gas assets, and creates
innovative structured transactions to enhance the value of Merchant Energy's
assets. This unit is able to provide its customers with flexible solutions to
meet their energy supply and financial risk management requirements by utilizing
its knowledge of the marketplace, natural gas pipelines, storage, and power
transmission infrastructures, supply aggregation, transportation management and
valuation, and integrated price risk management. They also enter into short and
long term energy supply and purchase contracts and perform total energy
infrastructure outsourcing for customers.
Trading and Risk Management. The Trading and Risk Management unit trades
natural gas, power, other energy commodities, and related financial instruments
in North America and Europe and provides pricing and valuation analysis for the
Marketing and Origination unit. Using the financial markets, this unit manages
the inherent risk of Merchant Energy's asset and trading portfolios using
value-at-risk limits set by our Board of Directors and optimizes the value
inherent in the segment's asset portfolio.
During 2000, the Marketing and Origination and Trading and Risk Management
units grew their combined physical and financially settled volumes by
approximately 40% to 106,656 BBtue/d. Power marketed during 2000 increased by
over 43 percent. We expect our marketed volumes to significantly increase in
2001.
Marketing and trading energy commodity volumes for the years ended December
31 were:
<TABLE>
<CAPTION>
2000 1999 1998
------- ------ ------
<S> <C> <C> <C>
Physical natural gas marketed (Bbtu/d).................... 6,899 6,713 7,089
Power marketed (MMWh)..................................... 113,652 79,361 55,210
Financial settled volumes (Bbtue/d)....................... 98,574 68,678 31,793
</TABLE>
6
<PAGE> 9
Power Generation. Our Power Generation unit is one of the largest
non-utility generators in the U.S., and currently owns or has interests in 64
power plants in 16 countries. These plants represent 17,153 gross megawatts of
generating capacity. Of these facilities, 75 percent are natural gas fired, 15
percent are geothermal, with the remaining 10 percent utilizing natural gas
liquids, coal, and other fuels. During 2000, Merchant Energy continued acquiring
domestic non-utility generation (NUG) assets, especially those with above-market
power purchase agreements. As part of these efforts, we used Chaparral
Investors, L.L.C. (also referred to as Electron) to expand Merchant Energy's
growth in the power generation business. Through Chaparral, Merchant Energy has
invested in 27 U.S. power generation facilities with a total generating capacity
of approximately 5,600 gross megawatts. A subsidiary of Merchant Energy serves
as the manager of Chaparral and its wholly-owned subsidiary, Mesquite Investors,
L.L.C., under a management agreement, which expires in 2006. As compensation for
managing Chaparral, Merchant Energy is paid an annual performance-based
management fee.
Detailed below are brief descriptions, by region, of Merchant Energy's
power generation projects that are either operational or in various stages of
construction or development.
<TABLE>
<CAPTION>
NUMBER OF GROSS
REGION PROJECT STATUS FACILITIES MEGAWATTS
- ------ -------------- ---------- ---------
<S> <C> <C> <C>
North America
East Coast Operational............................... 13 3,263
Under Construction........................ 1 716
Under Development......................... 3 1,664
Central Operational............................... 7 1,253
West Coast Operational............................... 21 1,036
South America Operational............................... 7 4,114
Under Construction........................ 1 470
Asia Operational............................... 5 2,589
Under Construction........................ 2 1,108
Europe Operational............................... 3 544
Under Construction........................ 1 396
-- ------
Total..................................................... 64 17,153
== ======
</TABLE>
LNG. The LNG unit contracts for LNG terminalling and regasification
capacity, coordinates short and long term LNG supply deliveries, and is
developing an international LNG supply and marketing business. As of December
31, 2000, our LNG unit has contracted for over 280 Bcf per year of LNG
regasification capacity at three locations along the Eastern Coast of the U.S.
and one location in Louisiana. In the Caribbean, we have contracted for 105 Bcf
per year of long term supplies of LNG with deliveries scheduled to begin in
2002.
Financial Services. The Financial Services unit provides financing to the
energy and power industries and provides institutional funds management.
Merchant Energy owns EnCap, an institutional funds management firm specializing
in financing independent oil and natural gas producers. EnCap manages three
separate institutional oil and natural gas investment funds in the U.S., and
serves as investment advisor to Energy Capital Investment Company PLC, a
publicly traded investment company in the United Kingdom. During 2000, we
acquired Enerplus Global Energy Management, Inc., an institutional and retail
funds management firm in Canada. Combined, EnCap and Enerplus manage funds with
a market value of approximately $2 billion. In addition to EnCap and Enerplus,
Merchant Energy's Financial Services unit holds investments of approximately $62
million. Also in 2000, it began originating financing for North American power
development projects. As of December 31, 2000, it had funded $5 million of loans
with additional commitments for $68 million.
7
<PAGE> 10
Operations. The Operations unit conducts the day-to-day operations of
Merchant Energy's assets in close coordination with the Marketing and
Origination, and Trading and Risk Management units. Our Operations unit operates
13 generating facilities in the U.S. and three facilities in two foreign
countries.
Finance and Administration. In addition to its functional units, Merchant
Energy has a Finance and Administration unit that implements financing
strategies for its assets, and provides accounting and administrative services
for the segment's activities.
Regulatory Environment
Merchant Energy's domestic power generation activities are regulated by
FERC under the Federal Power Act with respect to its rates, terms, and
conditions of service and other reporting requirements. In addition, exports of
electricity outside of the U.S. must be approved by the Department of Energy.
Its cogeneration power production activities are regulated by FERC under the
Public Utility Regulatory Policies Act with respect to rates, procurement and
provision of services, and operating standards. All of its power generation
activities are also subject to U.S. Environmental Protection Agency (EPA)
regulations.
Merchant Energy's foreign operations are regulated by numerous governmental
agencies in the countries in which these projects are located. Generally, many
of the countries in which Merchant Energy conducts and will conduct business
have recently developed or are developing new regulatory and legal structures to
accommodate private and foreign-owned businesses. These regulatory and legal
structures and their interpretation and application by administrative agencies
are relatively new and sometimes limited. Many detailed rules and procedures are
yet to be issued and we expect that the interpretation of existing rules in
these jurisdictions will evolve over time. We believe that our operations are in
compliance in all material respects with all applicable environmental laws and
regulations in the applicable foreign jurisdictions. We also believe that the
operations of our projects in many of these countries eventually may be required
to meet standards that are comparable in many respects to those in effect in the
U.S. and in countries within the European Community.
Markets and Competition
Merchant Energy maintains a diverse supplier and customer base. During
2000, Merchant Energy's activities served over 900 suppliers and over 1,300
sales customers around the world.
Merchant Energy's trading, marketing, and power development businesses
operate in a highly
competitive environment. Its primary competitors include:
- affiliates of major oil and natural gas producers;
- multi-national energy infrastructure companies;
- large domestic and foreign utility companies;
- affiliates of large local distribution companies;
- affiliates of other interstate and intrastate pipelines; and
- independent energy marketers and power producers with varying scopes of
operations and financial resources.
8
<PAGE> 11
Merchant Energy competes on the basis of price, access to production,
understanding of pipeline and transmission networks, imbalance management,
experience in the marketplace, and counterparty credit.
Many of Merchant Energy's generation facilities sell power pursuant to
long-term agreements with investor-owned utilities in the U.S. Because of the
terms of its power purchase agreements for its facilities, Merchant Energy's
revenues are not significantly impacted by competition from other sources of
generation for these facilities. The power generation industry is rapidly
evolving, and regulatory initiatives have been adopted at the federal and state
level aimed at increasing competition in the power generation business. As a
result, it is likely that when the power purchase agreements expire, these
facilities will be required to compete in a significantly different market in
which operating efficiency and other economic factors will determine success.
Merchant Energy is likely to face intense competition from generation companies
as well as from the wholesale power markets. The successful acquisition of new
business opportunities is dependent upon Merchant Energy's ability to respond to
requests to provide new services, mitigate potential risks, and maintain strong
business development, legal, financial, and operational support teams with
experience in the respective marketplace.
FIELD SERVICES
Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, storage, products extraction,
fractionation, dehydration, purification, compression, transportation of natural
gas and natural gas liquids, and intrastate natural gas transmission services.
It also provides well-ties and offers real-time information services, including
electronic wellhead gas flow measurement, and works with Merchant Energy to
provide fully bundled natural gas services with a broad range of pricing options
as well as financial risk management products.
Field Services' assets include natural gas gathering and natural gas
liquids pipelines, treating, processing, and fractionation facilities in the San
Juan Basin, the producing regions of east and south Texas, and Louisiana.
Through our subsidiaries, we own a one percent general partner interest in
Energy Partners and a one percent non-managing interest in many of its
subsidiaries. We also own 27.8 percent of the partnership's common units and
$170 million of its preferred units. Energy Partners is our primary vehicle for
the acquisition and development of midstream energy infrastructure assets.
Energy Partners' assets provide gathering, transportation, storage, and other
related activities for producers of natural gas and oil. Energy Partners owns or
has interests in twelve natural gas and oil pipeline systems, seven offshore
platforms, two natural gas storage facilities, five producing oil and natural
gas properties, and an overriding royalty interest in a non-producing oil and
natural gas property. As a result of our merger with Coastal in January 2001,
Energy Partners sold its interests in several assets in the Gulf of Mexico.
These sales consisted of interests in seven natural gas pipeline systems, a
dehydration facility and two offshore platforms. Energy Partners completed these
sales in March of 2001.
In December 2000, Field Services purchased PG&E's Texas Midstream
operations. The acquired assets consisted of 7,500 miles of natural gas
transmission and natural gas liquids pipelines that transport approximately 2.8
Bcf/d, nine natural gas processing and fractionation plants that process 1.5
Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. These assets serve
a majority of the metropolitan areas and the largest industrial load centers in
Texas, as well as numerous natural gas trading hubs. These assets also create a
physical link between our EPNG and TGP systems. In the first quarter of 2001,
Field Services sold some of these acquired natural gas liquids transportation
and fractionation assets to Energy Partners. The assets sold included more than
600 miles of natural gas liquids gathering and transportation pipelines and
three fractionation plants located in south Texas.
9
<PAGE> 12
The following tables provide information concerning Field Services' natural
gas gathering and transportation facilities, its processing facilities, and its
facilities accounted for under the equity method as of and for each of the three
years ended December 31:
<TABLE>
<CAPTION>
AVERAGE THROUGHPUT
THROUGHPUT (BBTUE/D)(2) PERCENT OF
MILES OF CAPACITY --------------------- OWNERSHIP
GATHERING & TREATING PIPELINE(1) (MMCFE/D)(2) 2000 1999 1998 INTEREST
- -------------------- ----------- ------------ ----- ----- ----- ----------
<S> <C> <C> <C> <C> <C> <C>
Western Division.................... 5,555 1,200 1,237 1,262 1,191 100
Eastern Division.................... 1,251 909 271 386 424 100
Central Division(3)................. 9,890 6,760 1,425 1,528 1,771 100
Energy Partners(4)(5)............... 2,076 1,545 774 698 695 30
Oasis(6)............................ 608 350 268 263 289 --
Viosca Knoll(5)..................... 125 10 6 142 287 --
</TABLE>
<TABLE>
<CAPTION>
AVERAGE NATURAL GAS
AVG. INLET VOLUME LIQUIDS SALES
INLET (BBTU/D)(2) (MGAL/D) PERCENT OF
CAPACITY(2) -------------------- -------------------- OWNERSHIP
PROCESSING PLANTS (MMCF/D) 2000 1999 1998 2000 1999 1998 INTEREST
- ----------------- ----------- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Western Division......... 600 635 650 586 384 432 370 100
Eastern Division......... 369 121 140 160 222 264 349 100
Central Division(3)...... 1,883 309 242 269 307 202 208 100
Coyote Gulch............. 120 87 97 69 -- -- -- 50
</TABLE>
- ---------------
(1) Mileage amounts are approximate for the total systems and have not been
reduced to reflect Field Services' net ownership.
(2) All volumetric information reflects Field Services' net interest and is
subject to increases or decreases depending on operating pressures and point
of delivery into or out of the system.
(3) Reflects the acquisition of PG&E's Texas Midstream operations in December
2000.
(4) In the first quarter of 2001, Energy Partners sold their interests in
several of its gathering, transmission, and treating systems in the Gulf of
Mexico. Total miles of the pipelines sold were 881. Our net interest in
these systems included combined throughput capacity of 542 MMcfe/d and
average throughput for the years ended December 31, 2000, 1999, and 1998 of
241 BBtue/d, 277 BBtue/d, and 330 BBtue/d.
(5) Field Services sold its 49 percent interest in Viosca Knoll to Energy
Partners in June 1999 and its remaining one percent interest in September
2000.
(6) Field Services sold its 35 percent interest in Oasis in December 2000.
Regulatory Environment
Some of Field Services' and Energy Partners' operations are subject to
regulation by FERC in accordance with the Natural Gas Act of 1938 and the
Natural Gas Policy Act of 1978. Each pipeline subject to regulation operates
under separate FERC approved tariffs with established rates, terms and
conditions under which the pipeline provides services.
In addition, some of Field Services' and Energy Partners' operations,
directly owned or owned through equity investments, are subject to the Natural
Gas Pipeline Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act, and
the National Environmental Policy Act. Each of the pipelines has a continuing
program of inspection designed to keep all of the facilities in compliance with
pollution control and pipeline safety requirements and Field Services and Energy
Partners believe that these systems are in substantial compliance with
applicable requirements.
Markets and Competition
Field Services competes with, among others, major interstate and intrastate
pipeline companies in the transportation of natural gas and natural gas liquids.
Field Services also competes with major integrated energy companies, independent
natural gas gathering and processing companies, natural gas marketers, and oil
and natural gas producers in gathering and processing natural gas and natural
gas liquids. Competition for throughput and natural gas supplies is based on a
number of factors, including price, efficiency of facilities,
10
<PAGE> 13
gathering system line pressures, availability of facilities near drilling
activity, service, and access to favorable downstream markets.
PRODUCTION
Our Production segment is engaged in the exploration for and the
acquisition, development, and production of natural gas, oil, and natural gas
liquids in the major producing basins of the United States. Production has
onshore and coal seam operations and properties in 11 states and offshore
operations and properties in federal and state waters in the Gulf of Mexico. It
also has exploration and production rights in Turkey.
Production sells its natural gas primarily at spot-market prices. It sells
its natural gas liquids at market prices under monthly or long-term contracts
and its oil production at posted prices, subject to adjustments for gravity and
transportation. Production engages in hedging activities on its natural gas and
oil production in order to stabilize cash flows and reduce the risk of downward
commodity price movements on sales of its production. A significant portion of
the segment's 2000 production was hedged by entering into third-party contracts
and forward sales.
Strategically, Production emphasizes disciplined investment criteria and
manages its existing production portfolio to maximize volumes and minimize
costs. Production expects to continue an active onshore and offshore drilling
program to capitalize on its land and seismic holdings. Production is also
pursuing strategic acquisitions of producing properties and the development of
coal seam projects. In 2000, Production replaced 229 percent of the reserves it
produced.
Natural Gas and Oil Reserves
The following table details Production's proved reserves at December 31,
2000. Information in the table is based upon the reserve report prepared by
Production dated January 1, 2001, and agrees with Production's estimate of
reserves filed with other federal agencies except for differences of less than 5
percent resulting from actual production, acquisitions, property sales, and
necessary reserve revisions and additions to reflect actual experience.
<TABLE>
<CAPTION>
NET PROVED RESERVES(1)
------------------------------------
NATURAL GAS LIQUIDS(2) TOTAL
----------- ---------- ---------
(MMCF) (MBBLS) (MMCFE)
<S> <C> <C> <C>
Producing......................................... 912,567 13,672 994,598
Non-Producing..................................... 148,887 4,969 178,698
Undeveloped....................................... 490,882 11,854 562,008
--------- ------ ---------
Total proved reserves..................... 1,552,336 30,495 1,735,304
========= ====== =========
</TABLE>
- ---------------
(1) Net proved reserves exclude royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
(2) Includes oil, condensate, and natural gas liquids.
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
Production. The reserve data represents only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretations and judgment. As a result, estimates of different
engineers often vary. In addition, results of drilling, testing, and production
subsequent to the date of an estimate may justify revision of such estimate.
Reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered. The meaningfulness of reserve estimates is highly
dependent upon the accuracy of the assumptions upon which they were based. In
general, the volume of production from natural gas and oil properties owned
11
<PAGE> 14
by Production declines as reserves are depleted. Except to the extent Production
conducts successful exploration and development activities or acquires
additional properties containing proved reserves, or both, the proved reserves
of Production will decline as reserves are produced.
For further discussion of our reserves, see Item 8, Financial Statements
and Supplementary Data, Note 19.
Wells and Acreage
The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, and coal seam acreage at December
31, 2000. Any acreage in which Production's interest is limited to owned
royalty, overriding royalty, and other similar interests is excluded.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
--------------------- --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Onshore..................... 488,988 297,334 946,288 668,537 1,435,276 965,871
Offshore.................... 292,660 196,525 1,087,567 1,040,145 1,380,227 1,236,670
Coal seam................... 32,634 26,666 581,045 437,493 613,679 464,159
--------- --------- --------- --------- --------- ---------
Total.................. 814,282 520,525 2,614,900 2,146,175 3,429,182 2,666,700
========= ========= ========= ========= ========= =========
</TABLE>
The domestic net developed acreage is concentrated primarily in the Gulf of
Mexico (38 percent), Texas (21 percent), Oklahoma (18 percent), and Louisiana
(18 percent). Approximately 19 percent, 18 percent, and 5 percent of our total
domestic net undeveloped acreage is under leases that have minimum remaining
primary terms expiring in 2001, 2002, and 2003.
The following table details Production's working interests in onshore,
offshore, and coal seam natural gas and oil wells at December 31, 2000. Gross
wells include 21 multiple completions.
<TABLE>
<CAPTION>
PRODUCTIVE NUMBER OF
NATURAL GAS PRODUCTIVE TOTAL WELLS BEING
WELLS OIL WELLS PRODUCTIVE WELLS DRILLED
------------- ----------- ----------------- -----------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ----- ----- --- ------- ------- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Onshore.......................... 1,393 967 27 25 1,420 992 20 12
Offshore......................... 144 60 15 12 159 72 1 1
Coal seam........................ 1,042 652 -- -- 1,042 652 57 41
----- ----- -- -- ----- ----- -- --
Total....................... 2,579 1,679 42 37 2,621 1,716 78 54
===== ===== == == ===== ===== == ==
</TABLE>
The following table details Production's exploratory and development wells
drilled during the years 1998 through 2000.
<TABLE>
<CAPTION>
NET EXPLORATORY NET DEVELOPMENT
WELLS DRILLED WELLS DRILLED
------------------ ------------------
2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Productive......................................... 5 12 15 199 116 204
Dry................................................ 11 14 19 5 2 18
-- -- -- --- --- ---
Total.................................... 16 26 34 204 118 222
== == == === === ===
</TABLE>
The information above should not be considered indicative of future
drilling performance, nor should it be assumed that there is any correlation
between the number of productive wells drilled and the amount of natural gas and
oil that may ultimately be recovered.
12
<PAGE> 15
Net Production, Unit Prices, and Production Costs
The following table details Production's net production volumes, average
sales prices received, and average production costs associated with the sale of
natural gas and oil for each of the years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
------ ------ ------
<S> <C> <C> <C>
Net Production:
Natural Gas (Bcf)........................................ 188 186 226
Oil, Condensate, and Liquids (MMBbls).................... 5 6 8
Total (Bcfe)..................................... 219 221 276
Average Realized Sales Price:
Natural Gas ($/Mcf)...................................... $ 2.26 $ 2.05 $ 1.95
Oil, Condensate, and Liquids ($/Bbl)..................... $17.98 $15.46 $12.22
Average Production Cost ($/Mcfe)(1)........................ $ 0.34 $ 0.44 $ 0.33
</TABLE>
- ---------------
(1) Includes direct lifting costs (labor, repairs and maintenance, materials,
and supplies) and the administrative costs of production offices, insurance,
and property and severance taxes.
Acquisition, Development, and Exploration Expenditures
The following table details information regarding Production's costs
incurred in its development, exploration, and acquisition activities during each
of the years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Acquisition Costs:
Proved.................................................... $ 74 $ 3 $ 2
Unproved.................................................. 41 45 48
Development Costs........................................... 269 178 375
Exploration Costs:
Delay Rentals............................................. 6 7 11
Seismic Acquisition and Reprocessing...................... 13 58 53
Drilling.................................................. 81 74 92
---- ---- ----
Total Capital Expenditures........................ $484 $365 $581
==== ==== ====
</TABLE>
Regulatory and Operating Environment
The federal government and the states in which Production operates or owns
interests in producing properties regulate various matters affecting natural gas
and oil production, including drilling and spacing of wells, conservation,
forced pooling, and protection of correlative rights among interest owners.
Production is also subject to governmental safety regulations in the
jurisdictions in which it operates.
Production's operations under federal natural gas and oil leases are
regulated by the statutes and regulations of the United States Department of the
Interior that currently impose liability upon lessees for the cost of pollution
resulting from their operations. Royalty obligations on all federal leases are
regulated by the Minerals Management Service, which has promulgated valuation
guidelines for the payment of royalties by producers. Other federal, state, and
local laws and regulations relating to the protection of the environment affect
Production's natural gas and oil operations through their effect on the
construction and operation of facilities, drilling operations, production, or
the delay or prevention of future offshore lease sales. We maintain substantial
insurance on behalf of Production for sudden and accidental spills and oil
pollution liability.
Production's business has operating risks normally associated with the
exploration for and production of natural gas and oil, including blowouts,
cratering, pollution, and fires, each of which could result in damage to life or
property. Offshore operations may encounter usual marine perils, including
hurricanes and other adverse weather conditions, and governmental regulations as
well as interruption or termination by
13
<PAGE> 16
governmental authorities based on environmental and other considerations.
Customary with industry practices, we maintain broad insurance coverage on
behalf of Production with respect to potential losses resulting from these
operating hazards.
Markets and Competition
The natural gas and oil business is highly competitive in the search for
and acquisition of additional reserves and in the sale of natural gas, oil, and
liquids. Production's competitors include major and intermediate sized oil and
natural gas companies, independent oil and natural gas operations, and
individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price, contract terms, and
quality of service. To some degree, price competition is mitigated by
Production's hedging activities.
CORPORATE AND OTHER OPERATIONS
Through our corporate group, we perform management, legal, financial, tax,
consulting, administrative and other services for our operating business
segments. The costs of providing these services are allocated to our business
segments. Our other operations include the assets and operations of our
telecommunications business.
ENVIRONMENTAL
A description of our environmental activities is included in Item 8,
Financial Statements and Supplementary Data, Note 11, and is incorporated by
reference herein.
EMPLOYEES
As of March 19, 2001, including the employees we acquired as a result of
our merger with Coastal, we had approximately 15,000 full-time employees, of
which 600 are subject to collective bargaining arrangements.
14
<PAGE> 17
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers as of March 19, 2001, are listed below. Prior to
August 1, 1998, all references to El Paso refer to positions held with El Paso
Natural Gas Company.
<TABLE>
<CAPTION>
OFFICER
NAME OFFICE SINCE AGE
---- ------ ------- ---
<S> <C> <C> <C>
William A. Wise.............. Chairman, President, and Chief Executive 1983 55
Officer of El Paso
H. Brent Austin.............. Executive Vice President and Chief Financial 1992 46
Officer of El Paso
Ralph Eads................... Executive Vice President of El Paso and 1999 41
President of El Paso's Merchant Energy
Group
Joel Richards III............ Executive Vice President of El Paso 1990 54
John W. Somerhalder II....... Executive Vice President of El Paso and 1990 45
President of El Paso's Pipeline Group
Britton White Jr............. Executive Vice President and General Counsel 1991 57
of El Paso
Rodney D. Erskine............ President of El Paso Production 2001 56
John D. Hushon............... President of El Paso Merchant Energy Europe 1996 55
Greg G. Jenkins.............. President of El Paso Global Networks 1996 43
Byron R. Kelley.............. President of El Paso Energy International 2001 53
Robert G. Phillips........... President of El Paso Field Services 1995 46
Clark C. Smith............... President of El Paso Merchant Energy North 2000 46
America
William A. Smith............. President of El Paso Global LNG 1999 56
Tom M. Wade.................. President of Petroleum Markets 2001 48
</TABLE>
Mr. Wise has been Chief Executive Officer since January 1990 and the
Chairman of the Board of Directors since January 2001. He was also Chairman of
the Board from January 1994 until October 1999. Mr. Wise became the President of
El Paso in July 1998 and also served in that capacity from January 1990 to April
1996. Mr. Wise is a member of the Board of Directors of Battle Mountain Gold
Company and is the Chairman of the Board of El Paso Tennessee Pipeline Co. and
El Paso Energy Partners Company, the general partner of Energy Partners.
Mr. Austin has been an Executive Vice President since May 1995. He has been
our Chief Financial Officer since April 1992. Prior to that period, he served in
various positions with Burlington Resources Inc.
Mr. Eads has been an Executive Vice President since July 1999 and President
of the El Paso Merchant Energy Group since January 2001. Mr. Eads was a Managing
Director and Co-Head of the Energy Group at Donaldson, Lufkin & Jenrette from
January 1996 through June 1999. Prior to that period, he was Managing Director,
Head of Energy at S.G. Warburg Company.
Mr. Richards has been an Executive Vice President since December 1996. From
January 1991 until December 1996, he was a Senior Vice President of El Paso.
Mr. Somerhalder has been an Executive Vice President of El Paso since April
2000, and President of our Pipeline segment since January 2001. He has been
Chairman of the Board of TGP, EPNG, and SNG since January 2000. He was President
of TGP from December 1996 to January 2000, President of El Paso Energy Resources
Company from April 1996 to December 1996 and a Senior Vice President of El Paso
from August 1992 to April 1996.
Mr. White has been an Executive Vice President of El Paso and General
Counsel since December 1996. Prior to that period, he was a Senior Vice
President and General Counsel of El Paso.
15
<PAGE> 18
Mr. Erskine has been President of El Paso Production since our merger with
Coastal in January 2001. He was Senior Vice President of Coastal from August
1997. He has held various positions with Coastal Oil & Gas Corporation, a
subsidiary of Coastal, since 1994.
Mr. Hushon has been President of El Paso Merchant Energy Europe since
January 2001. He was President of El Paso International from April 1996 to
January 2001. He was Senior Vice President of El Paso International from
September 1995 to April 1996. Prior to that period, Mr. Hushon was a senior
partner in the law firm of Arent Fox Kintner Plotkin & Kahn.
Mr. Jenkins has been President of El Paso Global Networks since August
2000. He was President of Merchant Energy from December 1996 to August 2000. He
was Senior Vice President and General Manager of Entergy Corp. from May 1996 to
December 1996. Prior to that period, he was President and Chief Executive
Officer of Hadson Gas Services Company.
Mr. Kelley has been President of El Paso International since January 2001.
He was Executive Vice President of Business Development and commercial
management for El Paso International since 1996. Prior to that period, Mr.
Kelley held various positions with Tenneco Energy.
Mr. Phillips has been President of El Paso Field Services since June 1997.
He was President of El Paso Energy Resources Company from December 1996 to June
1997, President of Field Services from April 1996 to December 1996 and was a
Senior Vice President of El Paso from September 1995 to April 1996. Prior to
that period, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.
Mr. Clark C. Smith has been President of El Paso Merchant Energy North
America since August 2000. He served as President and CEO of Engage Energy Inc.
since 1997. Prior to that period, he held the position of President and CEO of
Coastal Gas Marketing Company and held several positions with Enron Corp.
Mr. William A. Smith has been President of El Paso Global LNG since March
2001. He was an Executive Vice President of El Paso from October 1999 to March
2001. He was Executive Vice President and General Counsel of Sonat Inc. from
1995 to September 1999. He was Vice Chairman of Sonat Exploration from 1994 to
1995 and Chairman and President of SNG from 1989 to 1994.
Mr. Wade has been President of Petroleum Markets since January 2001. He has
held various positions with Coastal since 1980.
Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
ITEM 2. PROPERTIES
A description of our properties is included in Item 1, Business, and is
incorporated by reference herein.
We are of the opinion that we have satisfactory title to the properties
owned and used in our businesses, subject to liens for current taxes, liens
incident to minor encumbrances, and easements and restrictions that do not
materially detract from the value of such property or the interests therein or
the use of such properties in our businesses. We believe that our physical
properties are adequate and suitable for the conduct of our business in the
future.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Financial Statements and Supplementary Data, Note 11, which is
incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
16
<PAGE> 19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is traded on the New York Stock Exchange under the symbol
EPG. As of March 16, 2001, we had 68,070 stockholders of record. This does not
include individual participants who own our common stock, but whose shares are
held by a clearing agency, such as a broker or bank.
The following table reflects the quarterly high and low sales prices for
our common stock based on the daily composite listing of stock transactions for
the New York Stock Exchange and the cash dividends we declared in each quarter.
<TABLE>
<CAPTION>
HIGH LOW DIVIDENDS
-------- -------- ---------
(PER SHARE)
<S> <C> <C> <C>
2000
First Quarter...................................... $42.3125 $30.3125 $ 0.2060
Second Quarter..................................... 52.5000 39.3750 0.2060
Third Quarter...................................... 67.5000 46.2500 0.2060
Fourth Quarter..................................... 74.2500 57.1300 0.2060
1999
First Quarter...................................... $39.3750 $30.6875 $ 0.2000
Second Quarter..................................... 38.3750 31.9375 0.2000
Third Quarter...................................... 40.5000 34.4375 0.2000
Fourth Quarter..................................... 43.4375 33.3750 0.2000
</TABLE>
In January 2001, our Board of Directors declared a quarterly dividend of
$0.2125 per share of common stock, payable on April 2, 2001, to stockholders of
record on March 2, 2001. Future dividends will be dependent upon business
conditions, earnings, our cash requirements, and other relevant factors.
In June 1999, our stockholders approved an increase in our authorized
common stock to 750 million shares. We also rescinded our common stock
repurchase program which authorized us to repurchase up to 10 million shares in
order to meet a requirement to treat our 1999 merger with Sonat as a pooling of
interests under generally accepted accounting principles.
We have an odd-lot stock sales program available to stockholders who own
fewer than 100 shares of our common stock. The voluntary program offers these
stockholders a convenient method to sell all of their odd-lot shares at one time
without incurring any brokerage costs. We also have a dividend reinvestment and
common stock purchase plan available to all of our common stockholders of
record. The voluntary plan provides our stockholders a convenient and economical
means of increasing their holdings in our common stock. Neither the odd-lot
program nor the dividend reinvestment and common stock purchase plan have a
termination date, however we may suspend either at any time. You should direct
your inquiries to Fleet National Bank, our exchange agent.
17
<PAGE> 20
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- ------- -------- -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Operating Results Data:(1)
Operating revenues(2)(3)........................... $21,950 $10,709 $9,560 $10,184 $6,597
Merger-related and asset impairment charges........ 91 557 15 50 99
Ceiling test charges(4)............................ -- 352 1,035 -- --
Income (loss) before extraordinary items and
cumulative effect of accounting change.......... 582 (242) (306) 405 294
Basic earnings (loss) per common share before
extraordinary items and cumulative effect of
accounting change............................... 2.53 (1.06) (1.35) 1.81 1.61
Diluted earnings (loss) per common share before
extraordinary items and cumulative effect of
accounting change............................... 2.44 (1.06) (1.35) 1.77 1.59
Cash dividends declared per common share........... 0.82 0.80 0.76 0.73 0.70
Basic average common shares outstanding............ 230.... 228 226 224 183
Diluted average common shares outstanding.......... 243 228 226 229 185
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------------
2000 1999 1998 1997 1996
------- ------- ------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Financial Position Data:(1)
Total assets(3)................................. $27,445 $16,667 $14,455 $14,784 $13,206
Long-term debt, less current maturities......... 5,606 5,223 3,692 3,404 3,251
Company-obligated preferred securities of
consolidated trusts.......................... 625 325 325 -- --
Minority interest............................... 2,331 1,368 374 380 347
Stockholders' equity............................ 3,569 2,947 3,437 3,921 3,514
</TABLE>
- ---------------
(1) Our operating results and financial position reflect the acquisition in June
1996 of Cornerstone Natural Gas, in December 1996 of El Paso Tennessee
Pipeline (formerly Tenneco Inc.), in August 1998 of DeepTech International,
and in December 2000 of PG&E's Texas Midstream operations. These
acquisitions were accounted for as purchases and therefore operating results
are included in our results prospectively from the purchase date.
(2) We restated historical operating revenues due to the implementation in 2000
of Emerging Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a
Principal versus Net as an Agent, which provides guidance on the gross
versus net presentation of revenues and expenses. These reclassifications
impacted operating revenues and expenses, but had no impact on net income
(loss) or earnings per share.
(3) The increase to our 2000 operating revenues and total assets reflects the
significant growth in our Merchant Energy operations.
(4) Ceiling test charges are reductions in earnings that result when capitalized
costs of natural gas and oil properties exceed the upper limit, or ceiling,
on the value of these properties.
18
<PAGE> 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Over the past several years, our business activities and operations have
changed dramatically as a result of significant acquisitions, transactions, and
internal growth initiatives, designed to enhance our ability to compete
effectively in the global energy industry. These changes have significantly
expanded our operating scope, our ability to generate operating cash flows and
our needs for cash for investment opportunities. Consequently, we have
substantially expanded our credit facilities and created other financing
structures and facilities to meet our needs during this period. The more
significant changes are discussed below.
Merger with The Coastal Corporation
In January 2001, we merged with The Coastal Corporation. We accounted for
the merger as a pooling of interests and converted each share of Coastal common
stock and Class A common stock on a tax-free basis into 1.23 shares of our
common stock. We also exchanged Coastal's outstanding convertible preferred
stock for our common stock on the same basis as if the preferred stock had been
converted into Coastal common stock immediately prior to the merger. We issued a
total of 271 million shares, including 4 million shares issued to holders of
Coastal stock options. The total value of the transaction was approximately $24
billion, including $7 billion of assumed debt and preferred equity.
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; petroleum refining, marketing and distribution; chemicals
production; power production; and coal mining. Coastal owns interests in
approximately 18,000 miles of natural gas pipelines extending across the
midwestern and the Rocky Mountain areas of the U.S. has proved reserves of 3.6
Tcfe. Coastal also has international and domestic interests in natural gas and
oil producing properties, power generation plants, and crude oil refining
facilities.
Purchase of Texas Midstream Operations
In late December 2000, we completed our purchase of PG&E's Texas Midstream
operations for $887 million, including the assumption of $527 million of debt.
We accounted for this acquisition as a purchase. The assets acquired consist of
7,500 miles of natural gas transmission and natural gas liquids pipelines that
transport approximately 2.8 Bcf/d, nine natural gas processing plants that
process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. These
assets serve a majority of the metropolitan areas and the largest industrial
load centers in Texas, as well as numerous natural gas trading hubs. These
assets also create a physical link between our EPNG and TGP systems. In March
2001, Field Services sold some of these acquired natural gas liquids
transportation and fractionation assets to Energy Partners. The assets sold
include more than 600 miles of natural gas liquids gathering and transportation
pipelines and three fractionation plants located in south Texas.
In December 2000, to comply with a Federal Trade Commission order, we sold
our interest in Oasis Pipeline Company. Proceeds from the sale were $22 million
and we recognized an extraordinary loss of $19 million, net of income taxes of
$9 million.
Merger with Sonat Inc.
In October 1999, we completed our merger with Sonat. In the merger, we
issued one share of our common stock for each share of Sonat common stock. Total
shares issued were approximately 110 million shares. In connection with a
Federal Trade Commission order related to this merger, we sold our East
Tennessee Natural Gas Company and Sea Robin Pipeline Company as well as our
one-third interest in Destin Pipeline Company. Proceeds from the sales were
approximately $616 million and we recognized an extraordinary gain of $89
million, net of income taxes of $60 million. We accounted for the merger as a
pooling of interests.
19
<PAGE> 22
Merger-Related Costs and Asset Impairment Charges
As we have integrated the activities and operations of our mergers and
acquisitions, we have incurred, and will continue to incur, charges that will
have a significant impact on our results of operations, financial position and
cash flows. These costs, which are of a non-recurring nature, will include
employee severance, retention, and transition charges; write-offs or write-downs
of duplicate assets; charges to relocate assets and employees; contract
termination charges; and charges to align accounting policies and practices.
During the three year period ended December 31, 2000, we incurred charges
related to the mergers with Coastal, Sonat, and Zilkha Energy. In September
2000, we announced a plan to geographically consolidate our pipeline operations
with Coastal's following the completion of our Coastal merger. Under the
consolidation plan, El Paso Natural Gas Company's operations will be relocated
from El Paso, Texas to Colorado Springs, Colorado, and ANR Pipeline Company, a
subsidiary of Coastal, will be relocated from Detroit, Michigan, to Houston,
Texas. Along with this consolidation, we will also conduct numerous relocations
among our various operating sites. All relocations under these plans are
expected to be completed by mid-year 2001.
Upon our merger with Coastal, we issued approximately 4 million shares of
our common stock in exchange for Coastal employee, former employee, and outside
director stock options. The total charge in connection with this exchange was
approximately $278 million and will be included in our combined operations
during the first quarter of 2001.
As a result of our merger with Coastal, we will also be required to sell
our Midwestern pipeline system. Proceeds from the sale are expected to be
approximately $90 million, and will result in a before tax gain of approximately
$50 million. We expect to complete this sale in the second quarter of 2001.
Additionally, in the first quarter of 2001 Energy Partners sold its
interest in several offshore assets. These sales consisted of interests in seven
natural gas pipeline systems, a dehydration facility and two offshore platforms.
Proceeds from these sales were approximately $135 million and resulted in a loss
to the partnership of approximately $23 million. As additional consideration for
these sales, we committed to pay Energy Partners a series of payments totaling
$29 million. This amount, as well as our proportional share of the losses on the
sale of the partnership's assets, will be recorded as a charge in our income
statement in the first quarter of 2001.
We do not anticipate the impact of the sale of our Midwestern system or the
transactions by or with Energy Partners to have a material effect on our ongoing
financial position, operating results, or cash flows.
On January 30, 2001, we completed an employee restructuring, which resulted
in the reduction of 3,285 full-time positions through a combination of early
retirements and terminations. These reductions occurred across all locations and
business segments. These actions resulted in severance and termination charges,
retention payments for employees retained in the combined organization, and the
acceleration of employee benefits under existing benefit plans. Total charges in
connection with these actions are estimated to be approximately $890 million
with a majority being recorded in the first quarter of 2001.
The total cost of our merger-related activities, as well as additional
charges we will incur as we complete our evaluations of the contracts, operating
assets, and accounting policies of the combined organization could range between
$1.6 billion and $2 billion. This estimate is based on the costs we expect to
record in the first quarter of 2001 and our preliminary estimates of additional
costs we will incur. We expect that most of these charges will be recorded in
2001.
Also during the three year period ended December 31, 2000, we incurred a
variety of asset impairment charges ranging from those as a result of rate
filings within our regulated pipelines to write-downs of operating plants and
contracts that were determined to be impaired. We also recorded write-downs of
capitalized costs of our natural gas and oil properties under the full cost
method of accounting in both 1998 and 1999.
20
<PAGE> 23
Our merger-related costs and asset impairment charges are reflected in the
results of operations discussed below for each of our segments. The table below
provides a summary of our merger-related costs and asset impairment charges by
each of our business segments, and in total, for each of the three years ended
December 31:
<TABLE>
<CAPTION>
2000 1999 1998
---- ---- ------
(IN MILLIONS)
<S> <C> <C> <C>
Merger-related costs and asset impairment charges
Pipelines................................................. $-- $ 90 $ --
Merchant Energy........................................... -- 67 --
Field Services............................................ 11 8 --
Production................................................ -- 31 15
--- ---- ------
Segment total.......................................... 11 196 15
Corporate and other....................................... 80 361 --
--- ---- ------
Consolidated total..................................... $91 $557 $ 15
=== ==== ======
Ceiling test charges--Production............................ $-- $352 $1,035
=== ==== ======
</TABLE>
SEGMENT RESULTS OF OPERATIONS
Our business activities are segregated into four segments: Pipelines,
Merchant Energy, Field Services, and Production. These segments are strategic
business units that offer a variety of different energy products and services.
During the fourth quarter of 2000, we combined our International segment with
our Merchant Energy segment to reflect the ongoing globalization of the Merchant
Energy strategy and its operating activities. In addition, these results do not
include the impact of our merger with Coastal, which will not be reflected in
our results of operations until 2001. Results of PG&E's Texas Midstream
operations were reflected in our results as of the purchase date. We manage each
of our segments separately as each requires different technology and marketing
strategies. Since earnings on equity investments can be a significant component
of earnings in several of our segments, we evaluate segment performance based on
earnings before interest expense and taxes, or EBIT, instead of operating
income.
To the extent possible, results of operations have been reclassified to
conform to the current business segment presentation, although such results are
not necessarily indicative of the results which would have been achieved had the
revised business segment structure been in effect during those periods.
Operating revenues and expenses by segment include intersegment revenues and
expenses which are eliminated in consolidation. Because changes in energy
commodity prices have a similar impact on both our operating revenues and cost
of products sold from period to period, we believe that gross margin (revenue
less cost of sales) provides a more accurate and meaningful basis for analyzing
operating results for the Merchant Energy and the Field Services segments. For a
further discussion of the individual segments, see Item 8, Financial Statements
and Supplementary Data, Note 15.
The following table presents EBIT by segment and in total, including the
merger-related costs and asset impairment charges discussed above, for each of
the three years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Pipelines................................................... $ 822 $ 719 $ 811
Merchant Energy............................................. 563 3 28
Field Services.............................................. 102 85 76
Production.................................................. 196 (257) (936)
------ ----- -----
Segment EBIT.............................................. 1,683 550 (21)
------ ----- -----
Corporate and other expenses, net........................... (133) (359) (31)
------ ----- -----
Consolidated EBIT......................................... $1,550 $ 191 $ (52)
====== ===== =====
</TABLE>
21
<PAGE> 24
PIPELINES
Our Pipeline segment operates our interstate pipeline businesses. Each of
this segment's pipeline systems operates under a separate tariff that governs
its operations and rates. Operating results for our pipeline systems have
generally been stable because the majority of the revenues are based on fixed
demand charges. As a result, we expect changes in this aspect of our business to
be primarily driven by regulatory actions and contractual events. Commodity or
throughput-based revenues account for a smaller portion of our operating
results. These revenues vary from period to period, and system to system, and
are impacted by factors such as weather, operating efficiencies, competition
from other pipelines, and to a lesser degree, fluctuations in natural gas
prices. Results of operations of our Pipeline segment were as follows for each
of the three years ending December 31:
<TABLE>
<CAPTION>
2000 1999 1998
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues........................................ $ 1,697 $ 1,771 $ 1,696
Operating expenses........................................ (943) (1,103) (944)
Other income.............................................. 68 51 59
------- ------- -------
EBIT.................................................... $ 822 $ 719 $ 811
======= ======= =======
Total throughput (BBtu/d)....................... 11,842 11,290 11,401
======= ======= =======
</TABLE>
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Operating revenues for the year ended December 31, 2000, were $74 million
lower than the same period in 1999. This decrease was due to the impact of our
sales of the East Tennessee Pipeline and Sea Robin systems in the first quarter
of 2000, which we were required to sell under an FTC order as a condition to
completing our Sonat merger. Also contributing to the decrease was a favorable
resolution of regulatory issues in the first quarter of 1999 on TGP, lower rates
following SNG's May 2000 rate case settlement, lower revenues from contracts for
relinquished capacity on EPNG, and the elimination of the minimum bill provision
on our Elba Island facility following FERC's approval of Elba Island's
reactivation in the first quarter of 2000. Additionally, the impact of customer
settlements and contract terminations in 2000 and resolutions of customer
imbalance issues in 1999 on TGP contributed to the decrease. Partially
offsetting these decreases were higher revenues from transportation and other
services provided on each of our transmission systems due to improved average
throughput in 2000, higher realized prices on pipeline gas sales, and revenues
from the January 2000 acquisition of Crystal Gas Storage, Inc., prior to its
sale to Energy Partners in September 2000.
Operating expenses for the year ended December 31, 2000, were $160 million
lower than the same period in 1999. The decrease was due to cost efficiencies
following our merger with Sonat, lower operating costs on our East Tennessee
Pipeline and Sea Robin systems as a result of their sale in March 2000, and the
favorable impact of FERC's authorization to reactivate SNG's Elba Island
facility in the first quarter of 2000. Also contributing to the decrease was the
1999 resolution of a contested rate matter with a customer of EPNG, severance
and termination charges incurred as a result of our Sonat merger, and the
impairment of several SNG expansion projects, all occurring in 1999.
Additionally, estimated future environmental costs and write-offs of duplicate
information technology assets in 1999 on SNG following our merger with Sonat
contributed to the decrease. The decrease was partially offset by the impact of
unfavorable producer and shipper settlements on EPNG as well as revised
estimates of regulatory recoveries on EPNG and higher utility costs in 2000.
Other income for the year ended December 31, 2000 was $17 million higher
than the same period in 1999. The increase was due to higher earnings on Citrus
Corp. as a result of a one-time benefit recorded in 2000, as well as gains on
the sale of non-pipeline assets in the third quarter of 2000. The increase was
partially offset by the favorable settlement of a regulatory issue in 1999, the
elimination of an asset for the future recovery of costs of the Elba Island
facility, and a lower allowance for funds used during construction as a result
of less expansion and construction activity in 2000.
22
<PAGE> 25
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating revenues for the year ended December 31, 1999, were $75 million
higher than 1998. This increase was due to the favorable resolution of
regulatory issues during 1999 on TGP coupled with a downward revision in 1998 of
the amount of recoverable interest on TGP's GSR costs. Also contributing to the
increase were higher revenues from transportation and other services, an
increase in firm transportation revenues on the SNG system associated with
expansion projects, resolutions of TGP's customer imbalance issues, and higher
operational gas sales. These increases were partially offset by lower system
throughput on the TGP system in 1999, the favorable resolution in 1998 of a
contested rate matter on the MPC system related to its rate methodology, and
higher non-transportation revenues in 1998 on the SNG system.
Operating expenses for the year ended December 31, 1999 were $159 million
higher than 1998. The increase was due to severance and termination charges
incurred as a result of our merger with Sonat, the impairment of several SNG
expansion projects, an increase in estimated environmental costs, and write-offs
of duplicate information technology assets, all occurring in 1999. Also
contributing to the increase were higher general and administrative costs on all
systems, higher depreciation from expansion projects on SNG, and the unfavorable
1999 resolution of a contested rate matter with a customer of EPNG. Partially
offsetting these increases were revised estimates of regulatory recoveries on
EPNG.
Other income for the year ended December 31, 1999, was $8 million lower
than 1998. The decrease was primarily due to lower equity earnings on Destin
Pipeline Company in 1999, partially offset by an increase in 1999 interest
income on a Destin-related debt issuance during the latter part of 1998. We were
required to sell Destin as a result of our merger with Sonat.
MERCHANT ENERGY
Merchant Energy is a market maker involved in a wide range of activities in
the wholesale energy market place, including trading and risk management, asset
ownership and financial services. Each of the markets served by Merchant Energy
is highly competitive, and is influenced directly or indirectly by energy market
economics.
Merchant Energy's trading and risk management activities provide
sophisticated energy trading and energy management solutions for its customers
and affiliates involving primarily natural gas and power. Within its trading and
risk management operations, Merchant Energy originates transactions with its
customers to assist them with energy supply aggregation, storage and
transportation management, as well as valuation and risk management. Merchant
Energy maintains a substantial trading portfolio that balances its position risk
across multiple commodities and over seasonally fluctuating energy demands.
During 2000, U.S. energy supply and demand resulted in substantial volatility in
the energy markets that significantly impacted Merchant Energy's earnings
opportunities. This volatility is expected to continue for 2001, although not
necessarily at the same levels we experienced in 2000.
Merchant Energy is a provider of power and natural gas to the state of
California. During the latter half of 2000, and continuing into 2001, California
has experienced sharp increases in natural gas prices and wholesale power prices
due to energy shortages resulting from the concurrence of a variety of
circumstances, including unusually warm summer weather followed by high winter
demand, low gas storage levels, poor hydroelectric power conditions, maintenance
downtime of significant generation facilities, and price caps that discouraged
power movement from other nearby states into California.
The increase in power prices caused by the imbalance of natural gas and
power supply and demand coupled with electricity price caps imposed on rates
allowed to be charged to California electricity customers has resulted in large
cash deficits to the two major California utilities, Southern California Edison
and Pacific Gas and Electric. As a result, both utilities have defaulted on
payments to creditors and have accumulated substantial under collections from
customers, which has resulted in their credit ratings being downgraded in 2001
from above investment grade to below investment grade. The utilities filed for
emergency rate increases with the California Public Utilities Commission and are
working with the state authorities to restore the companies' financial
viability. We have historically been one of the largest suppliers of energy to
California,
23
<PAGE> 26
and we are actively participating with all parties in California to be a part of
a long-term, stable solution to California's energy needs. As of March 2001,
Merchant Energy believes its exposure for sales of power and gas to the state of
California, including receivables related to its interest in California power
plant investments, is approximately $50 million, net of credit reserves to
reflect market uncertainties.
Merchant Energy's asset ownership activities include global power plants
and the power facilities owned and managed on behalf of Chaparral. Its
asset-based businesses include power plants in 16 countries. Merchant Energy is
also actively involved in developing a global LNG operation. During 2000,
Merchant Energy earned $80 million in fee based revenue from Chaparral and was
reimbursed $20 million for operating expenses. We expect the 2001 fee based
revenue to increase to approximately $147 million based on the growth in the
Chaparral asset portfolio.
In the financial services area, Merchant Energy owns EnCap and Enerplus,
and conducts other energy financing activities. EnCap manages three separate oil
and natural gas investment funds in the U.S., and serves as an investment
advisor to one fund in Europe. EnCap also facilitates investment in emerging
energy companies and earns a return from these investments. In 2000, Merchant
Energy acquired Enerplus, a Canadian investment management company through which
it conducts fund management activities similar to EnCap, but in Canada. Below
are Merchant Energy's operating results and an analysis of those results for
each of the three years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Trading gross margin........................................ $ 406 $ 91 $ 71
Operating and other revenues................................ 291 119 58
Operating expenses.......................................... (264) (301) (166)
Other income................................................ 130 94 65
----- ----- -----
EBIT...................................................... $ 563 $ 3 $ 28
===== ===== =====
</TABLE>
VOLUMES
<TABLE>
<CAPTION>
2000 1999 1998
------- ------ ------
(EXCLUDES INTRASEGMENT
TRANSACTIONS)
<S> <C> <C> <C>
Physical
Natural Gas (BBtue/d)..................................... 6,899 6,713 7,089
------- ------ ------
Power (MMWh).............................................. 113,652 79,361 55,210
------- ------ ------
Petroleum (MBbls)......................................... 7,772 4,990 21,716
------- ------ ------
Financial Settlements (Bbtue/d)............................. 98,574 68,678 31,793
------- ------ ------
</TABLE>
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Trading gross margin represents revenue from physical energy commodity
sales less costs of these sales as well as results from financial trading
activities. For the year ended December 31, 2000, trading gross margin was $315
million higher than the same period in 1999. Commodity marketing and trading
margins increased due to significant price volatility in natural gas and power
markets which increased the value of our trading portfolio during 2000. Also
contributing to the increase was higher income from power transactions
originated in 2000 versus 1999. These increases were partially offset by natural
gas transactions originated in 1999.
Operating and other revenues represent all operating and other revenues,
excluding revenue from energy commodity sales. For the year ended December 31,
2000, these revenues were $172 million higher than the same period in 1999. The
increase was due to higher asset management fees earned from Chaparral, which
began operations during the fourth quarter of 1999, the consolidation of a
Brazilian power project in the latter part of 1999, and higher income on the
West Georgia power project, a seasonal peaking facility, which began operating
in June 2000. Encap's financial services activities in 2000, and the acquisition
of Enerplus in March 2000 also contributed to the increase.
24
<PAGE> 27
Operating expenses for the year ended December 31, 2000, were $37 million
lower than the same period in 1999. The decrease was due to higher
reimbursements in 2000 of general and administrative costs relating to
Chaparral, a 1999 charge to eliminate a minority investor in Sonat's marketing
joint venture following the Sonat merger, and 1999 asset writedowns and charges
to conform and consolidate accounting practices and policies with those of Sonat
following the merger. The decrease was partially offset by higher general and
administrative expenses and project development costs relating to international
projects in 2000.
Other income for the year ended December 31, 2000, was $36 million higher
than the same period in 1999. The increase was due to higher earnings from power
projects and investments, primarily CE Generation, which was acquired in March
1999, as well as the benefit realized from the formation of our East Asia Power
joint venture in March 2000. Also contributing to the increase was a settlement
received from our Indonesian project in May 2000, and higher interest income.
These increases were partially offset by lower equity earnings from investments
in various international projects, primarily our investment in East Asia Power
in the Philippines.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Trading gross margin for the year ended December 31, 1999, was $20 million
higher than the same period in 1998. Commodity marketing and trading margins
increased due to transactions originated in 1999, partially offset by a decrease
in trading margins in 1999.
Operating and other revenues for the year ended December 31, 1999, were $61
million higher than the same period in 1998. The increase was primarily due to
management fees earned from Chaparral, revenues from a Brazilian power project
consolidated during the latter part of 1999, and revenues from consolidated
power generation facilities acquired in December 1998.
Operating expenses for the year ended December 31, 1999, were $135 million
higher than the same period in 1998. The increase was due to higher operating
costs associated with an increase in power activities, operating expenses on
consolidated power generation facilities acquired in December 1998, a 1999
charge to eliminate a majority interest in Sonat's marketing joint venture
following the Sonat merger, and 1999 asset writedowns and charges to conform and
consolidate accounting practices and policies with those of Sonat following the
merger. Also contributing to the increase were higher general and administrative
costs and higher operating costs from our Brazilian power project. The increases
were partially offset by lower project development costs on international
projects in 1999.
Other income for the year ended December 31, 1999, was $29 million higher
than the same period in 1998. The increase was due to higher earnings from power
projects and investments, primarily CE Generation, higher interest income, and
1999 equity swap gains recognized on our CAPSA project. These increases were
partially offset by 1998 gains on the sale of project-related activities and
surplus power equipment.
FIELD SERVICES
Field Services provides a variety of services for the midstream component
of our operations, including gathering and treating of natural gas, processing
and fractionation of natural gas, natural gas liquids and natural gas derivative
products, such as butane, ethane, and propane. A subsidiary of Field Services
also serves as the general partner of Energy Partners, a publicly traded, master
limited partnership. As the general partner, Field Services earns a combination
of management fees and partner distributions for services rendered to Energy
Partners. Field Services attempts to balance its earnings from these activities
through a combination of contractually based and market based services.
The gathering and treating operations earn margins substantially from
fee-based services. This means revenues are the product of a market price,
usually related to the monthly natural gas price index, and the volume gathered.
During most of 2000, Field Services hedged a substantial amount of the risk
associated with the changes in natural gas prices by entering into forward
natural gas derivatives.
Processing and fractionation operations earn a margin based on both
fee-based contracts and make-whole contracts. Make-whole contracts allow us to
retain the extracted liquid products and to return to the producer
25
<PAGE> 28
a Btu equivalent amount of natural gas. During periods when natural gas and
liquid prices are volatile, Field Services may be at greater price risk under
its make-whole contracts. Make-whole contracts constitute a greater portion of
the operating contracts acquired in late December in connection with our
acquisition of PG&E's Texas Midstream operations.
Field Services' operating results and an analysis of those results are as
follows for each of the three years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Gathering and treating margin............................... $ 178 $ 162 $ 157
Processing margin........................................... 69 44 48
Other margin................................................ 2 1 3
------ ------ ------
Total gross margin................................ 249 207 208
Operating expenses.......................................... (173) (169) (146)
Other income................................................ 26 47 14
------ ------ ------
EBIT...................................................... $ 102 $ 85 $ 76
====== ====== ======
Volumes and prices
Gathering and treating
Volumes (BBtu/d)....................................... 3,952 4,279 4,172
====== ====== ======
Prices ($/MMBtu)....................................... $ 0.17 $ 0.14 $ 0.13
====== ====== ======
Processing
Volumes (inlet BBtu/d)................................. 1,065 1,032 1,014
====== ====== ======
Prices ($/MMBtu)....................................... $ 0.18 $ 0.12 $ 0.13
====== ====== ======
</TABLE>
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Total gross margin for the year ended December 31, 2000, was $42 million
higher than the same period in 1999. Gathering and treating margins increased
due to higher average gathering rates, predominantly in the San Juan Basin,
which are substantially indexed to natural gas prices and higher average
condensate prices. The higher margin in 2000 was partially offset by lower
gathering and treating volumes due to the sale of El Paso Intrastate Alabama, a
gathering system in the coal-bed methane producing regions of Alabama, to Energy
Partners in March 2000. Processing margins increased due to higher liquids
prices in 2000 and the acquisition, in April 2000, of an interest in the Indian
Basin processing assets.
Operating expenses for the year ended December 31, 2000, were $4 million
higher than the same period in 1999 due to higher depreciation and amortization
from assets transferred from EPNG to Field Services following a FERC order, as
well as the December 2000 impairment charge related to the Needle Mountain
processing facility due to unrecoverability of costs. The increase was partially
offset by the impairment of gathering assets in 1999, lower costs for labor and
benefits, and cost recoveries from managed facilities.
Other income for the year ended December 31, 2000, was $21 million lower
than the same period in 1999. The decrease was primarily due to net gains in
1999 from the sale of our interest in the Viosca Knoll gathering system to
Energy Partners in June 1999, as well as lower equity earnings in 2000 following
the sale of our interest in Viosca Knoll.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total gross margin for the year ended December 31, 1999, was $1 million
lower than the same period in 1998. Gathering and treating margins increased due
to higher volumes and average gathering rates, which are substantially indexed
to natural gas prices, partially offset by the elimination of margins on assets
in the Anadarko Basin that were sold in September 1998. Processing margins
decreased due to lower liquids prices and the sale of two processing facilities
in 1999.
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Operating expenses for the year ended December 31, 1999, were $23 million
higher than the same period in 1998. The increase was due to higher shared
services allocations in 1999, the impairment of gathering assets in the fourth
quarter of 1999, and an increase in depreciation and amortization resulting from
acquisitions.
Other income for the year ended December 31, 1999, was $33 million higher
than the same period in 1998. The increase was due to higher earnings from
investments, primarily Energy Partners, as well as a gain recorded in 1999 from
the sale of our interest in Viosca Knoll.
PRODUCTION
Production's operating results are driven by a variety of factors including
its ability to locate and develop economic reserves, extract those reserves with
minimal production costs, sell the products at attractive commodity prices, and
operate at the lowest cost level possible.
Over the past few years, Production has been successful in replacing its
production with new, relatively low cost reserves. In addition, Production has
also been successful in efficiently extracting its reserves and maintaining a
low overall cost structure. In 1998, Production restructured its business in
response to depressed market conditions and did so again in 1999 following the
Sonat merger. Both of these efforts were successful in reducing overhead and
administrative costs.
Production engages in hedging activities on its natural gas and oil
production in order to stabilize cash flows and reduce the risk of downward
commodity price movements on sales of its production. This is achieved through
natural gas and oil swaps. Typically, a higher percentage of production is
hedged in the current year and then decreases each year thereafter. Production's
hedged position is closely monitored and evaluated in an effort to achieve its
earnings objectives and reduce the risks associated with spot-market price
volatility. In 2000, realized prices for natural gas and oil sales were lower
than those that could have been realized had the production been sold at
spot-market prices. However, this hedging strategy produced a relatively stable
revenue stream that resulted in expected rates of return. For 2001, we
anticipate hedging approximately 75 percent of our production, which includes
our estimates for Coastal's 2001 production.
These factors, while not the only ones influencing results, usually impact
performance from period to period. Below are the operating results and analysis
of these results for each of the three years ending December 31.
<TABLE>
<CAPTION>
2000 1999 1998
-------- -------- --------
(IN MILLIONS)
<S> <C> <C> <C>
Natural gas................................................. $ 425 $ 380 $ 440
Oil, condensate and liquids................................. 92 90 101
Other....................................................... 5 3 (6)
-------- -------- --------
Total operating revenues.......................... 522 473 535
Operating expenses.......................................... (326) (731) (1,474)
Other income................................................ -- 1 3
-------- -------- --------
EBIT...................................................... $ 196 $ (257) $ (936)
======== ======== ========
Volumes and prices
Natural gas
Volumes (MMcf)......................................... 187,845 185,968 225,653
======== ======== ========
Average realized prices ($/Mcf)........................ $ 2.26 $ 2.05 $ 1.95
======== ======== ========
Oil, condensate, and liquids
Volumes (MBbls)........................................ 5,138 5,825 8,327
======== ======== ========
Average realized prices ($/Bbl)........................ $ 17.98 $ 15.46 $ 12.22
======== ======== ========
</TABLE>
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YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Operating revenues for the year ended December 31, 2000, were $49 million
higher than 1999. The increase was due to higher realized prices for natural gas
and oil, condensate, and liquids.
Operating expenses for the year ended December 31, 2000, were $405 million
lower than 1999. The decrease was due to full cost ceiling test charges incurred
in the first quarter of 1999, decreased 2000 labor costs as a result of an
organizational restructuring following our Sonat merger, and 1999 charges to
retain Sonat's seismic data in our production operations as a result of the
merger. The decrease was partially offset by higher depletion rates in 2000 as a
result of increased future development costs in 2000 versus 1999.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total operating revenues for the year ended December 31, 1999, were $62
million lower than 1998. The decrease in natural gas and oil, condensate, and
liquids revenues was primarily due to the sales of properties during 1998,
partially offset by an increase in realized prices in 1999. The increase in
other revenues resulted from a favorable contractual settlement in 1999.
Operating expenses for the year ended December 31, 1999, were $743 million
lower than 1998 primarily due to lower full cost ceiling test charges in 1999
versus the charges incurred in 1998, along with lower production levels in 1999.
Also contributing to the decrease were lower operating and maintenance expenses
due to property dispositions in 1998 and efficiencies created from Production's
1998 reorganization of its operations. These decreases were partially offset by
charges to retain Sonat's seismic data in our production operations as a result
of the Sonat merger.
Other income for the year ended December 31, 1999, was $2 million lower
than 1998 due primarily to a net gain on the sale of non-operating assets during
the third quarter of 1998.
CORPORATE AND OTHER EXPENSES, NET
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Corporate and other expenses for the year ended December 31, 2000, were
$226 million lower than 1999. The decrease was primarily due to higher costs
related to our merger with Sonat in 1999, partially offset by costs incurred in
2000 related to our merger with Coastal. Also offsetting the decrease were
increased funding commitments to the El Paso Energy Foundation in 2000.
We will incur additional merger-related costs in 2001 as a result of our
merger with Coastal.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Net corporate expenses for the year ended December 31, 1999, were $328
million higher than 1998 primarily due to charges in 1999 related to our merger
with Sonat including the accelerated amortization of certain employee benefits;
legal, accounting, and financial advisory costs; employee severance and
retention costs; and incremental costs incurred in combining office facilities
following the merger. This increase was partially offset by costs incurred in
1998 from the introduction of our power services activities and higher recurring
equity compensation charges in 1998.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Interest and debt expense for the year ended December 31, 2000, was $85
million higher than 1999 primarily due to $900 million of increased borrowings
under a combination of short-term and long-term programs by El Paso to fund
capital expenditures, acquisitions, and other investing activities, and $46
million of increased interest expense on borrowings from Chaparral in 2000.
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YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Interest and debt expense for the year ended December 31, 1999, was $66
million higher than 1998 primarily due to increased borrowings by El Paso of
$1.8 billion to fund capital expenditures, acquisitions, and other investing
activities offset by higher capitalized interest in 1999 from higher project
investment and development primarily in Production and Merchant Energy.
INCOME TAX EXPENSE (BENEFIT)
Income tax expense (benefit) for the years ended December 31, 2000, 1999,
and 1998, was $286 million, $(81) million, and $(170) million. These amounts
resulted in effective tax rates of 33 percent, 25 percent, and 36 percent.
Differences in our effective tax rates from the statutory tax rate of 35 percent
were primarily a result of the following factors:
- state income taxes;
- earnings from unconsolidated equity investees where we anticipate
receiving dividends;
- foreign income, not taxed in the U.S., but taxed at foreign tax rates;
- the utilization of deferred credits on loss carryovers;
- the non-deductible portion of merger-related costs; and
- non-deductible dividends on the preferred stock of a subsidiary.
For a reconciliation of the statutory rate of 35 percent to the effective
rates in each of the three years ended December 31, 2000, see Item 8, Financial
Statements and Supplementary Data, Note 4.
MINORITY INTEREST
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Minority interest for the year ended December 31, 2000, was $83 million
higher than in 1999 primarily due to a full year of costs associated with the
preferred interest in Trinity River Associates, L.L.C., formed in June 1999.
Also contributing to the increase were costs associated with a preferred
interest in Clydesdale Associates, L.P. and distributions associated with
preferred securities of El Paso Energy Capital Trust IV, both of which were
formed in May 2000.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Minority interest for the year ended December 31, 1999, was $24 million
higher than in 1998 as a result of costs associated with a preferred interest in
Trinity River Associates, L.L.C. in 1999, coupled with a full year of dividends
on preferred securities of El Paso Energy Capital Trust I issued in March 1998.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash used in our operating activities was $1,040 million for the year
ended December 31, 2000, compared to net cash provided by operating activities
of $501 million for 1999. The increase in cash used in operations was primarily
a result of cash expended in our price risk management activities as well as
higher trading receivables and payables related to the substantial growth in our
trading portfolio and higher prices in the energy commodity markets. We also had
higher interest payments in 2000 primarily related to higher long-term and
short-term debt balances, and higher 2000 income tax payments as a result of
higher state and foreign income tax payments. Partially offsetting these
increases were higher payments in 1999 for merger-related costs and activities
versus merger-related payments made in 2000, and higher cash generated in 2000
from our pipeline, field services, and production operations. In 2001, we expect
to pay significant amounts related to our Coastal merger and expect cash demands
from our expanded Merchant Energy
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<PAGE> 32
activities to continue. Offsetting this should be higher cash generated from our
expanded operations following our merger with Coastal.
CASH FROM INVESTING ACTIVITIES
Net cash used in our investing activities was $1,553 million for the year
ended December 31, 2000. Our investing activities principally consisted of
additions to joint ventures and equity investments, including an increase in our
Chaparral equity investment, the purchase of an additional 18.5% interest in an
Argentine company, CAPSA, the purchase of an investment in a Korean power
company, Korea Independent Energy Corporation (formerly Hanwha Energy Co., Ltd),
and a note receivable from Quanta Investors, L.L.C., a company formed to hold
various telecommunications assets. Other investing activities in 2000 included
the acquisitions of PG&E's Texas Midstream operations, Crystal Gas Storage,
Inc., and Enerplus Global Management. We also purchased the All-American
pipeline assets, an interest in the Indian Basin gas processing plant assets,
and had expenditures for expansion and construction projects. Cash inflows from
investment related activities included proceeds from the sales of our East
Tennessee pipeline system, Sea Robin pipeline system, El Paso Intrastate-Alabama
pipeline system, our one-third interest in the Destin pipeline system, and the
West Georgia Generating Company. We also received proceeds from the formation of
our East Asia Power joint venture and the repayment of a note receivable by
Chaparral.
CASH FROM FINANCING ACTIVITIES
Net cash provided by our financing activities was $2,736 million for the
year ended December 31, 2000. Cash provided from our financing activities
included revolving credit borrowings, the issuance of long-term debt, the sale
of an interest in Clydesdale Associates, L.P., the issuance of preferred
securities of El Paso Energy Capital Trust IV, and notes payable to Chaparral.
During 2000, we repaid short-term borrowings, paid dividends, and retired
long-term debt.
LIQUIDITY
We rely on cash generated from internal operations as our primary source of
liquidity, supplemented by our available credit facilities and commercial paper
programs. The availability of borrowings under our credit agreements is subject
to specified conditions, which we believe we currently meet. These conditions
include compliance with the financial covenants and ratios required by our
agreements, absence of default under these agreements, and continued accuracy of
our representations and warranties (including the absence of any material
adverse changes since the specified dates).
We expect that future funding for our working capital needs, capital
expenditures, acquisitions, other investing activities, long-term debt
retirements, payments of dividends and other financing expenditures will be
provided by internally generated funds, commercial paper issuances, available
capacity under existing credit facilities, and the issuance of new long-term
debt, trust securities, or equity. For a discussion of our financing
arrangements, see Item 8, Financial Statements and Supplementary Data, Note 9.
COMMITMENTS AND CONTINGENCIES
See Item 8, Financial Statements and Supplementary Data, Note 11, for a
discussion of our commitments and contingencies.
At December 31, 2000, we had capital and investment commitments of $1.2
billion primarily relating to our production, pipeline, and international power
activities. Our other planned capital and investment projects are discretionary
in nature, with no substantial capital commitments made in advance of the actual
expenditures.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 8, Financial Statements and Supplementary Data, Note 1, for a
discussion of new accounting pronouncements we have not yet adopted.
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RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.
With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf:
WE OPERATE IN HIGHLY COMPETITIVE INDUSTRIES.
Most of the natural gas and natural gas liquids we transport, gather,
process and store are owned by third parties. As a result, the volume of natural
gas and natural gas liquids involved in these activities depends on the actions
of those third parties, and is beyond our control. Further, the following
factors, most of which are beyond our control, may unfavorably impact our
ability to maintain or increase current transmission, storage, gathering,
processing, and sales volumes and rates, to renegotiate existing contracts as
they expire or to remarket unsubscribed capacity:
- future weather conditions, including those that favor hydroelectric
generation or other alternative energy sources;
- price competition;
- drilling activity and supply availability;
- expiration of significant contracts; and
- service area competition, especially due to current excess pipeline
capacity into California and the Midwest.
If we are unable to compete with services offered by other energy
enterprises which may be larger, offer more services, and possess greater
resources, our future profitability may be negatively impacted.
THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST
BE RENEGOTIATED PERIODICALLY.
Substantially all of our pipeline subsidiaries' revenues are generated
under natural gas transportation contracts which expire periodically and must be
renegotiated and extended or replaced. Although we actively pursue the
renegotiation, extension and/or replacement of these contracts, we cannot assure
you that we will be able to extend or replace these contracts when they expire
or that the terms of any renegotiated contracts will be as favorable as the
existing contracts.
In particular, our ability to extend and/or replace transportation
contracts could be harmed by factors we cannot control, including:
- the proposed construction by other companies of additional pipeline
capacity in markets served by our interstate pipelines;
- changes in state regulation of local distribution companies, which may
cause them to negotiate short-term contracts;
- reduced demand due to higher natural gas prices;
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<PAGE> 34
- the availability of alternative energy sources or supply points; and
- the viability of our expansion projects.
If we are unable to renew, extend or replace these contracts or if we renew
them on less favorable terms, we may suffer a material reduction in our revenues
and earnings.
FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.
If natural gas prices in the supply basins connected to our pipeline
systems are higher than prices in other natural gas producing regions,
especially Canada, our ability to compete with other transporters may be
negatively impacted. Revenues generated by our gathering and processing
contracts depend on volumes and rates, both of which can be affected by the
prices of natural gas and natural gas liquids. The success of our gathering and
processing operations in the offshore Gulf of Mexico is subject to continued
development of additional oil and natural gas reserves in the vicinity of our
facilities and our ability to access additional reserves to offset the natural
decline from existing wells connected to our systems. A decline in energy prices
could precipitate a decrease in these development activities and could cause a
decrease in the volume of reserves available for gathering and processing
through our offshore facilities. Fluctuations in energy prices, which may impact
gathering rates and investments by third parties in the development of new oil
and natural gas reserves connected to our gathering and processing facilities,
are caused by a number of factors, including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation facilities;
- energy legislation;
- federal and state taxes, if any, on the sale or transportation of natural
gas and natural gas liquids; and
- abundance of supplies of alternative energy sources.
If there are reductions in the average volume of the natural gas and
natural gas liquids we transport, gather and process for a prolonged period, our
results of operations and financial position could be significantly, negatively
affected.
THE RATES WE ARE ABLE TO CHARGE OUR CUSTOMERS MAY BE REDUCED BY GOVERNMENTAL
AUTHORITIES.
Our pipeline businesses are regulated by the FERC and various state and
local regulatory agencies. In particular, the FERC generally limits the rates we
are permitted to charge our customers for interstate natural gas transportation
and, in some cases, sales of natural gas. If the rates we are permitted to
charge our customers for use of our regulated pipelines are lowered, the
profitability of our pipeline businesses may be reduced.
THE SUCCESS OF OUR OIL AND NATURAL GAS EXPLORATION AND PRODUCTION BUSINESSES IS
DEPENDENT ON FACTORS WHICH CANNOT BE PREDICTED WITH CERTAINTY.
The performance of our exploration and production businesses is dependent
upon a number of factors that we cannot control. These factors include:
- fluctuations in crude oil and natural gas prices;
- the results of future drilling activity;
- our ability to identify and precisely locate prospective geologic
structures and to drill and successfully complete wells in those
structures in a timely manner;
- our ability to expand our leased land positions in desirable areas, which
often are subject to intensely competitive leasing conditions;
- risks incident to operations of natural gas and oil wells; and
- future drilling, production and development costs, including drilling rig
rates.
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ESTIMATES OF OIL AND NATURAL GAS RESERVES MAY CHANGE.
Actual production, revenues, taxes, development expenditures, and operating
expenses with respect to our reserves will likely vary from our estimates of
proved reserves of oil and natural gas, and those variances may be material. The
process of estimating oil and natural gas reserves is complex, requiring
significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering, and economic data for each reservoir or deposit. As a
result, these estimates are inherently imprecise. Actual future production, oil
and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves may vary
substantially from our estimates. In addition, we may be required to revise the
reserve information, downward or upward, based upon production history, results
of future exploration and development, prevailing oil and natural gas prices and
other factors, many of which will be beyond our control.
THE SUCCESS OF OUR POWER GENERATION AND MARKETING ACTIVITIES DEPENDS ON MANY
FACTORS, SOME OF WHICH MAY BE BEYOND OUR CONTROL.
The success of our international and domestic power projects and power
marketing activities, and the amount of the related performance-based management
fee paid to us in connection with the Electron financing structure, could be
adversely affected by factors beyond our control, including:
- alternative sources and supplies of energy becoming available due to new
technologies and interest in self generation and cogeneration;
- uncertain regulatory conditions resulting from the ongoing deregulation
of the electric industry in the United States and in foreign
jurisdictions;
- our ability to negotiate successfully and enter into, restructure or
recontract advantageous long-term power purchase agreements;
- the possibility of a reduction in the projected rate of growth in
electricity usage as a result of factors such as regional economic
conditions and the implementation of conservation programs;
- the inability of customers to pay amounts owed under power purchase
agreements; and
- the increasing price volatility due to deregulation and changes in
commodity trading practices.
OUR TELECOMMUNICATIONS BUSINESS STRATEGY MAY NOT BE SUCCESSFUL.
Our experience in the telecommunications industry is limited, and we cannot
assure you that our telecommunications strategy will be successful. Our success
depends in part on the evolution of telecommunications as a commodity and our
ability to integrate and adapt our facilities and services to keep pace with
advances in communications technologies and the new and improved devices and
services that result from these changes. In addition, the market for fiber optic
capacity and telecommunications services is rapidly evolving, and although we
expect demand for these services to grow, we cannot assure you that this growth
will occur. Additionally, the price of fiber optic capacity is expected to
continue to decline sharply because of the increase in newly installed fiber
optic capacity coming on the market and rapid fiber optic equipment technology
improvements. Further, a variety of critical issues, including security,
reliability, ease and cost of access, creation of a liquid trading market,
uncertain governmental regulation, and quality of service remain unresolved and
may adversely affect our business. We cannot assure you, therefore, that our
telecommunications strategy will be successful.
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WE CANNOT ASSURE YOU THAT WE AND COASTAL WILL BE SUCCESSFULLY COMBINED INTO A
SINGLE ENTITY.
If we cannot successfully combine our operations with Coastal, we may
experience a material adverse effect on our business, financial condition, or
results of operations. Our merger with Coastal involves combining two companies
that have previously operated separately. The combining of our companies
involves a number of risks, including:
- the diversion of management's attention to the combining of operations;
- difficulties in combining operations and systems;
- difficulties in assimilating and retaining employees;
- challenges in keeping customers; and
- potential adverse short-term effects on operating results and financial
position.
Among the factors considered by the board of directors of each company in
approving the merger agreement were the opportunities for economies of scale and
scope, opportunities for growth and operating efficiencies that could result
from the merger. Although we expect our combined company to achieve significant
annual savings in operating costs as a result of the merger, we may not be able
to maintain the levels of operating efficiency that we each previously achieved
or might achieve if we remain separate. Because of difficulties in combining
operations, we may not be able to achieve the cost savings and other
size-related benefits that we hope to achieve after the merger.
OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES.
Some of our non-regulated subsidiaries use futures and option contracts
traded on the New York Mercantile Exchange, over-the-counter options and price
and basis swaps with other natural gas merchants and financial institutions.
These instruments are intended to reduce our exposure to short-term volatility
in changes in energy commodity prices. We could, however, incur financial losses
in the future as a result of volatility in the market values of the underlying
commodities, or if one of our counterparties fails to perform under a contract.
Furthermore, because the valuation of these financial instruments can involve
estimates, changes in the assumptions underlying these estimates can occur,
changing our valuation of these instruments and potentially resulting in
financial losses. For additional information concerning our derivative financial
instruments, see item 7A, Quantitative and Qualitative Disclosures About Market
Risks and Item 8, Financial Statements and Supplementary Data, Note 6.
ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE.
Our ability to grow will depend, in part, upon our ability to identify and
complete attractive acquisition and investment opportunities. Opportunities for
growth through acquisitions and investments in joint ventures, and the future
operating results and success of these acquisitions and joint ventures within
and outside the United States may be subject to the effects of, and changes in
United States and foreign:
- trade and monetary policies;
- laws and regulations;
- political and economic developments;
- inflation rates;
- taxes; and
- operating conditions.
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OUR FOREIGN INVESTMENTS INVOLVE SPECIAL RISKS.
Our activities in areas outside the U.S. are subject to the risks inherent
in foreign operations, including:
- loss of revenue, property and equipment as a result of hazards such as
expropriation, nationalization, wars, insurrection and other political
risk;
- the effects of currency fluctuations and exchange controls, such as
devaluations of the foreign currencies and other economic problems; and
- changes in laws, regulations, and policies of foreign governments,
including those associated with changes in the governing parties.
COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR
ESTIMATES.
Our current and former operations involve management of regulated materials
and are subject to various environmental laws and regulations. These laws and
regulations obligate us to clean up various sites at which petroleum, chemicals,
low-level radioactive substances or other regulated materials may have been
disposed of or released. Some of these sites have been designated Superfund
sites by the EPA under the Comprehensive Environmental Response, Compensation
and Liability Act. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.
It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:
- the difficulty of estimating clean up costs;
- the uncertainty in quantifying liability under environmental laws that
impose joint and several liability on all potentially responsible
parties;
- the nature of environmental laws and regulations; and
- the possible introduction of future environmental laws and regulations.
Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties. For additional
information concerning our environmental matters, see Item 8, Financial
Statements and Supplementary Data, Note 11.
OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.
Our exploration, production, transportation, gathering, and processing
operations are subject to the inherent risks normally associated with those
operations, including explosions, pollution, the release of toxic substances,
fires, and other hazards, each of which could result in damage to or destruction
of our facilities or damages to persons and property. If any of these events
were to occur, we could suffer substantial losses.
While we maintain insurance against these types of risks to the extent and
in amounts that we believe are reasonable, our financial condition and
operations could be adversely affected if a significant event occurs that is not
fully covered by insurance.
THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EL PASO
TENNESSEE PIPELINE CO.
The amount of the actual and contingent liabilities we assumed in our
merger with El Paso Tennessee in 1996 could vary substantially from the amounts
we estimated, which were based upon assumptions which could prove to be
inaccurate. If new Tenneco Inc. or Newport News Shipbuilding Inc. (organizations
created and distributed to Tenneco Inc. shareholders prior to our acquisition of
Tenneco Inc.'s energy businesses in December 1996) were unable or unwilling to
pay their respective liabilities, a court could require us, under legal theories
which may or may not be applicable to the situation, to assume responsibility
for those obligations. If we were required to assume these obligations, it could
have a material adverse effect on our financial condition, results of operations
or cash flows.
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THERE REMAIN POTENTIAL FEDERAL INCOME TAX LIABILITIES RELATED TO THE ACQUISITION
OF EL PASO TENNESSEE
PIPELINE CO.
In connection with our acquisition of El Paso Tennessee and the
distributions made by El Paso Tennessee prior to its acquisition, the IRS issued
a private letter ruling to old Tenneco Inc. (now known as El Paso Tennessee), in
which it ruled that for United States federal income tax purposes the
distributions would be tax-free to old Tenneco Inc. and, except to the extent
cash was received in lieu of fractional shares, to its then existing
stockholders; the merger would constitute a tax-free reorganization; and that
other transactions effected in connection with the merger and distribution would
be tax-free. If the distributions were not to qualify as tax-free, then a
corporate level federal income tax would be assessed to the consolidated group
of which old Tenneco Inc. was the common parent. This corporate level federal
income tax would be payable by El Paso Tennessee. Under limited circumstances,
however, new Tenneco Inc. and Newport News Shipbuilding Inc. have agreed to
indemnify El Paso Tennessee for a defined portion of such tax liabilities.
WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS.
Our business and operating results can be harmed by factors such as the
availability or cost of capital, changes in interest rates, changes in the tax
rates due to new tax laws, changes in the structured finance market, market
perceptions of us or the natural gas and energy industry, or our credit ratings.
WE ARE SUBJECT TO FOREIGN CURRENCY EXCHANGE RISK.
Fluctuations in the value of the dollar as it rises and falls daily on
foreign currency exchanges can have a negative effect on our businesses and
operating results.
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<PAGE> 39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We utilize derivative financial instruments to manage market risks
associated with energy commodities and interest and foreign currency exchange
rates. Our market risks are monitored by our corporate risk management committee
that operates independently from our business segments that create or actively
manage these risk exposures to ensure compliance with our overall stated risk
management policies as approved by our Board of Directors.
TRADING COMMODITY PRICE RISK
Our Merchant Energy segment is exposed to market risks inherent in the
financial instruments it uses for trading energy and energy related commodities.
Merchant Energy records its energy trading activities, including transportation
capacity and storage at fair value. Changes in fair value are reflected in our
income statement. Merchant Energy's policy is to manage commodity price risks
through a variety of financial instruments, including:
- exchange-traded futures contracts involving cash settlements;
- forward contracts involving cash settlements or physical delivery of an
energy commodity;
- swap contracts which require payment to (or receipts from) counterparties
based on the difference between fixed and variable prices for the
commodity;
- exchange-traded and over-the-counter options; and
- other contractual arrangements.
Merchant Energy manages its market risk, subject to parameters established
by our corporate risk management committee. Comprehensive risk management
processes, policies, and procedures have been established to monitor and control
its market risk. Our risk management committee also continually reviews these
policies to ensure they are responsive to changing business conditions.
Merchant Energy measures the risk in its commodity and energy related
contracts on a daily basis utilizing a Value-at-Risk model to determine the
maximum potential one-day unfavorable impact on its earnings, due to normal
market movements, and monitors its risk in comparison to established thresholds.
The Value-at-Risk computations capture a significant portion of the exposure
related to option positions, and utilize historical price movements over a
specified period to project future price movements in the energy markets.
Merchant Energy also utilizes other measures to provide additional assurance
that the risks in its commodity and energy related contracts are being properly
monitored on a daily basis, including sensitivity analysis, position limit
control and credit risk management.
Based on a confidence level of 95 percent and a one-day holding period,
Merchant Energy's estimated potential one-day unfavorable impact on income
before income taxes and minority interest, as measured by Value-at-Risk, related
to contracts held for trading purposes was approximately $19 million, $3 million
and $3 million at December 31, 2000, 1999, and 1998. The increase in
Value-at-Risk during 2000 reflects the significant increase in our commodity
trading activities during the period. In 2000, Merchant Energy's highest,
lowest, and average estimated potential one day unfavorable impact on income
before taxes and minority interest, as measured by Value-at-Risk were $19
million, $2 million and $9 million. In the fourth quarter of 2000, Merchant
Energy also began managing asset based commodity transactions under the same
Value-at-Risk methodology utilized for trading purposes. The potential one-day
unfavorable impact on income before income taxes and minority interest related
to these asset based commodity transactions as measured by Value-at-Risk was $10
million at December 31, 2000. In 2000, the highest, lowest and average estimated
one-day unfavorable impact on income before income taxes and minority interest
for the asset based commodity transactions, as measured by Value-at-Risk, were
$10 million, $5 million, and $8 million. The average value represents the
average of the 2000 month end values. The high and low valuations represent the
highest and lowest month end values during 2000. Actual losses could exceed
those measured by Value-at-Risk.
37
<PAGE> 40
NON-TRADING COMMODITY PRICE RISK
We mitigate market risk associated with significant physical transactions,
including natural gas, crude oil and natural gas liquids production through the
use of non-trading financial instruments, including forward contracts and swaps.
Merchant Energy hedges a portion of the commodity risk for Production and Field
Services by facilitating derivative financial instruments with third parties.
The estimated potential one-day unfavorable impact on income before income
taxes and minority interest, as measured by Value-at-Risk, related to our
non-trading commodity activities was insignificant at December 31, 2000, 1999,
and 1998.
INTEREST RATE RISK
Many of our debt related financial instruments and project financing
arrangements are sensitive to market fluctuations in interest rates. We mitigate
exposure to interest rate risk through the use of non-trading derivative
financial instruments, including interest rate and equity swaps.
In August 1999, we entered an interest rate swap agreement on a notional
amount of $600 million with a termination date of July 2001. We swapped the
fixed interest rate on our $600 million aggregate principal Senior Notes due
2001 for a floating 3 month LIBOR plus 0.1475 percent rate. We accounted for
this transaction using accrual accounting. In November 2000, we terminated the
swap. The termination of this swap did not materially impact our financial
statements.
In March 1997, we purchased a 10.5 percent interest in CAPSA for
approximately $57 million and entered into an equity swap for an additional 18.5
percent ownership. Under the equity swap, we paid interest to a counterparty, on
a quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus
0.85 percent. In exchange, we received 18.5 percent of CAPSA's dividends. In
February 1999, we extended the term of the swap and modified the notional amount
to $103 million at a rate of LIBOR plus 1.75 percent. In May 2000, we exercised
our right to terminate the swap and purchased the counterparty's 18.5 percent
ownership interest in CAPSA for approximately $127 million. During the term of
this swap, we reflected changes in the market value of the equity swap in our
income statement. The termination of the swap did not materially impact our
financial statements.
The table below shows cash flows and related weighted average interest
rates of our interest bearing securities, by expected maturity dates. As of
December 31, 2000, the carrying amounts of short-term borrowings are
representative of fair values because of the short-term maturity of these
instruments. The fair value of the long-term debt has been estimated based on
quoted market prices for the same or similar issues.
<TABLE>
<CAPTION>
DECEMBER 31, 2000 DECEMBER 31, 1999
------------------------------------------------------------------------ ---------------------
EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS
------------------------------------------------------------------------ CARRYING
2001 2002 2003 2004 2005 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE
------ ---- ---- ---- ---- ---------- ------ ------------- -------- ----------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES:
Short-term debt -- variable
rate......................... $1,426 $1,426 $1,426 $1,251 $1,251
Average interest rate.... 5.6%
Long-term debt, including
current portion -- fixed
rate......................... $1,032 $522 $240 $ 71 $291 $4,482 $6,638 $6,722 $5,315 $5,204
Average interest rate.... 7.7% 8.4% 7.4% 9.8% 7.6% 7.6%
Notes payable to unconsolidated
affiliates -- fixed rate... $ 84 $ 90 $ 51 $ 10 $ 12 $ 6 $ 253 $ 276
Average interest rate.... 7.4% 7.4% 7.4% 7.4% 7.4% 7.4%
Notes payable to unconsolidated
affiliates -- variable
rate..................... $ 313 $ 174 $ 487 $ 487
Average interest rate.... 7.3% 10.9%
COMPANY-OBLIGATED PREFERRED
SECURITIES:
El Paso Energy Capital Trust
I............................ $ 325 $ 325 $ 579 $ 325 $ 327
Average interest rate.... 4.8%
El Paso Energy Capital Trust
IV........................... $300 $ 300 $ 300
Average interest rate.... 6.2%
</TABLE>
38
<PAGE> 41
FOREIGN CURRENCY EXCHANGE RATE RISK
We manage our exposure to changes in foreign currency exchange rates by
entering into derivative financial instruments, principally foreign currency
forward purchase and sale contracts. Our primary exposure relates to changes in
foreign currency rates on certain of our merchant activities outside the U.S.
not denominated or adjusted to U.S. dollars. The following table summarizes the
notional amounts, average settlement rates, and fair value for foreign currency
forward purchase and sale contracts as of December 31, 2000:
<TABLE>
<CAPTION>
NOTIONAL AMOUNT FAIR VALUE
IN FOREIGN AVERAGE IN
CURRENCY SETTLEMENT U.S. DOLLARS
(IN MILLIONS) RATES (IN MILLIONS)
--------------- ---------- -------------
<S> <C> <C> <C> <C>
Canadian Dollars Purchase................................ 1,095 0.673 $(3)
Sell.................................... 441 0.686 6
---
$ 3
===
</TABLE>
The following table summarizes foreign currency forward purchase and sale
contracts by expected maturity dates along with annual anticipated cash flow
impacts as of December 31, 2000:
<TABLE>
<CAPTION>
EXPECTED MATURITY DATES
-----------------------------------------------------
2001 2002 2003 2004 2005 THEREAFTER TOTAL
---- ---- ---- ---- ---- ---------- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Canadian Dollars Purchase......................... $(1) $(2) $(1) $-- $-- $ 1 $(3)
Sell............................. 3 2 1 -- -- -- 6
--- --- --- --- --- --- ---
Net cash flow effect............. $ 2 $-- $-- $-- $-- $ 1 $ 3
=== === === === === === ===
</TABLE>
EQUITY RISK
Through Merchant Energy's financial services unit, we manage and invest in
private investment funds as well as privately placed securities of both
privately and publicly held companies. We account for these investments using
investment company accounting. As a result, these holdings are measured at their
fair value with changes in fair value recorded in our income statement. The fair
value of these investments are determined based on estimates of amounts that
would be realized if these securities were sold. Below are the fair values of
our investments subject to equity risks at December 31, 2000 and 1999, as well
as the impact of a ten percent increase or decrease in the fair values of those
investments for each period presented:
<TABLE>
<CAPTION>
2000 1999
------------------------------------ ------------------------------------
IMPACT OF IMPACT OF IMPACT OF IMPACT OF
10 PERCENT 10 PERCENT 10 PERCENT 10 PERCENT
FAIR VALUE INCREASE DECREASE FAIR VALUE INCREASE DECREASE
---------- ---------- ---------- ---------- ---------- ----------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Investment funds............... $ 7 $ 1 $(1) $ 4 $-- $--
Securities..................... 54 5 (5) 7 1 (1)
Other.......................... 1 -- -- 1 -- --
--- --- --- --- --- ---
Total................ $62 $ 6 $(6) $12 $ 1 $(1)
=== === === === === ===
</TABLE>
39
<PAGE> 42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Operating revenues
Transportation............................................ $ 1,420 $ 1,564 $ 1,530
Energy commodities........................................ 19,696 8,582 7,744
Gathering and processing.................................. 476 324 141
Other..................................................... 358 239 145
------- ------- -------
21,950 10,709 9,560
------- ------- -------
Operating expenses
Cost of natural gas and other products.................... 18,882 8,245 7,027
Operation and maintenance................................. 913 835 956
Merger-related costs and asset impairment charges......... 91 557 15
Ceiling test charges...................................... -- 352 1,035
Depreciation, depletion, and amortization................. 589 608 624
Taxes, other than income taxes............................ 144 145 138
------- ------- -------
20,619 10,742 9,795
------- ------- -------
Operating income(loss)...................................... 1,331 (33) (235)
------- ------- -------
Other income
Earnings from unconsolidated affiliates................... 127 95 73
Other, net................................................ 92 129 110
------- ------- -------
219 224 183
------- ------- -------
Income (loss) before interest, income taxes, and other
charges................................................... 1,550 191 (52)
------- ------- -------
Interest and debt expense................................... 538 453 387
Minority interest........................................... 144 61 37
Income tax expense (benefit)................................ 286 (81) (170)
------- ------- -------
968 433 254
------- ------- -------
Income (loss) before extraordinary items and cumulative
effect of accounting change............................... 582 (242) (306)
Extraordinary items, net of income taxes.................... 70 -- --
Cumulative effect of accounting change, net of income
taxes..................................................... -- (13) --
------- ------- -------
Net income (loss)........................................... $ 652 $ (255) $ (306)
======= ======= =======
Basic earnings (loss) per common share
Income (loss) before extraordinary items and cumulative
effect of accounting change............................. $ 2.53 $ (1.06) $ (1.35)
Extraordinary items, net of income taxes.................. 0.30 -- --
Cumulative effect of accounting change, net of income
taxes................................................... -- (0.06) --
------- ------- -------
Net income (loss)......................................... $ 2.83 $ (1.12) $ (1.35)
======= ======= =======
Diluted earnings (loss) per common share
Income (loss) before extraordinary items and cumulative
effect of accounting change............................. $ 2.44 $ (1.06) $ (1.35)
Extraordinary items, net of income taxes.................. 0.29 -- --
Cumulative effect of accounting change, net of income
taxes................................................... -- (0.06) --
------- ------- -------
Net income (loss)......................................... $ 2.73 $ (1.12) $ (1.35)
======= ======= =======
Basic average common shares outstanding..................... 230 228 226
======= ======= =======
Diluted average common shares outstanding................... 243 228 226
======= ======= =======
</TABLE>
See accompanying notes.
40
<PAGE> 43
EL PASO CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
2000 1999
------- -------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents................................. $ 688 $ 545
Accounts and notes receivable, net of allowance of $111 in
2000 and $33 in 1999
Customer................................................ 3,639 986
Unconsolidated affiliates............................... 270 366
Other................................................... 422 310
Inventory................................................. 167 74
Assets from price risk management activities.............. 4,281 233
Other..................................................... 609 400
------- -------
Total current assets............................... 10,076 2,914
Property, plant, and equipment, net......................... 11,659 10,265
Investments in unconsolidated affiliates.................... 2,858 2,177
Assets from price risk management activities................ 1,638 413
Other....................................................... 1,214 898
------- -------
Total assets....................................... $27,445 $16,667
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts and notes payable
Trade................................................... $ 3,339 $ 994
Unconsolidated affiliates............................... 397 122
Other................................................... 416 542
Short-term borrowings (including current maturities of
long-term debt)......................................... 2,458 1,343
Liabilities from price risk management activities......... 2,881 197
Current deferred credits.................................. 527 143
Other..................................................... 449 362
------- -------
Total current liabilities.......................... 10,467 3,703
------- -------
Debt
Long-term debt, less current maturities................... 5,606 5,223
Noncurrent notes payable to unconsolidated affiliates..... 343 --
------- -------
5,949 5,223
------- -------
Deferred credits and other
Liabilities from price risk management activities......... 898 95
Deferred income taxes..................................... 2,149 1,737
Noncurrent deferred credits............................... 771 730
Other..................................................... 686 539
------- -------
4,504 3,101
------- -------
Commitments and contingencies
Securities of subsidiaries
Company-obligated preferred securities of consolidated
trusts.................................................. 625 325
Minority interests........................................ 2,331 1,368
------- -------
2,956 1,693
------- -------
Stockholders' equity
Common stock, par value $3 per share; authorized
750,000,000 shares; issued 243,318,833 shares in 2000
and 238,542,335 shares in 1999.......................... 730 716
Additional paid-in capital................................ 1,619 1,367
Retained earnings......................................... 1,670 1,207
Accumulated other comprehensive income.................... (57) (29)
Treasury stock (at cost) 8,538,358 shares in 2000 and
8,947,565 shares in 1999................................ (268) (273)
Unamortized compensation.................................. (125) (41)
------- -------
Total stockholders' equity......................... 3,569 2,947
------- -------
Total liabilities and stockholders' equity......... $27,445 $16,667
======= =======
</TABLE>
See accompanying notes.
41
<PAGE> 44
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss)......................................... $ 652 $ (255) $ (306)
Adjustments to reconcile net income (loss) to net cash
from operating activities
Depreciation, depletion, and amortization............... 589 608 624
Deferred income tax expense (benefit)................... 328 (44) (194)
Extraordinary items..................................... (120) -- --
Undistributed earnings in equity investees.............. (68) (52) (60)
Ceiling test charges.................................... -- 352 1,035
Non-cash portion of merger-related costs and asset impairment charges... 11 380 --
Other................................................... (51) (35) (40)
Working capital changes, net of non-cash transactions
Accounts and notes receivable........................ (2,555) (271) 481
Inventory............................................ (10) 4 15
Change in price risk management activities, net...... (1,787) (204) (40)
Accounts payable..................................... 1,960 132 (391)
Other working capital changes........................ 100 (101) 39
Other................................................... (89) (13) (130)
------- ------- -------
Net cash provided by (used in) operating
activities....................................... (1,040) 501 1,033
------- ------- -------
Cash flows from investing activities
Purchases of property, plant, and equipment............... (1,336) (1,086) (1,137)
Additions to investments.................................. (1,387) (832) (689)
Cash paid for acquisitions, net of cash received.......... (524) (165) (373)
Net proceeds from the sale of assets...................... 728 33 389
Proceeds from sale of investments......................... 295 112 163
Change in cash deposited in escrow related to an equity
investee................................................ 24 (101) --
Repayment (advances) of notes receivable from
unconsolidated affiliates............................... 647 (262) --
------- ------- -------
Net cash used in investing activities.............. (1,553) (2,301) (1,647)
------- ------- -------
Cash flows from financing activities
Net borrowings (repayments) of commercial paper and
short-term notes........................................ (256) 156 288
Revolving credit borrowings............................... 1,145 878 810
Revolving credit repayments............................... (715) (1,253) (1,017)
Payments to retire long-term debt......................... (127) (343) (289)
Net proceeds from the issuance of long-term debt.......... 897 1,781 691
Net proceeds from issuance of Company-obligated preferred
securities.............................................. 293 -- 317
Issuances (repurchases) of common stock................... 110 24 (20)
Dividends paid............................................ (189) (184) (209)
Increase in notes payable to unconsolidated affiliates.... 583 222 --
Net proceeds from issuance of minority interests in
subsidiaries ........................................... 995 960 --
Other..................................................... -- -- 2
------- ------- -------
Net cash provided by financing activities.......... 2,736 2,241 573
------- ------- -------
Increase (decrease) in cash and cash equivalents............ 143 441 (41)
Cash and cash equivalents
Beginning of period....................................... 545 104 145
------- ------- -------
End of period............................................. $ 688 $ 545 $ 104
======= ======= =======
</TABLE>
See accompanying notes.
42
<PAGE> 45
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Common stock, $3.00 par:
Balance at beginning of year............... 239 $ 716 236 $ 707 234 $ 702
Issuance of common stock, net of related
costs................................... 1 3 1 3 -- 1
Compensation related issuances............. 3 11 3 9 2 4
Retirement of Sonat treasury shares........ (1) (3)
--- ------ --- ------ --- ------
Balance at end of year.................. 243 730 239 716 236 707
--- ------ --- ------ --- ------
Additional paid-in capital:
Balance at beginning of year............... 1,367 1,288 1,229
Issuance of common stock, net of related
costs................................... 37 30 8
Compensation related issuances............. 177 90 30
Tax benefit of equity plans................ 42 13 10
Retirement of Sonat treasury shares........ (61)
Other...................................... (4) 7 11
------ ------ ------
Balance at end of year.................. 1,619 1,367 1,288
------ ------ ------
Retained earnings:
Balance at beginning of year............... 1,207 1,669 2,186
Net income (loss).......................... 652 (255) (306)
Dividends ($0.824, $0.800, and $0.765 per
share).................................. (189) (207) (211)
------ ------ ------
Balance at end of year.................. 1,670 1,207 1,669
------ ------ ------
Accumulated other comprehensive income:
Balance at beginning of year............... (29) (12) (4)
Cumulative translation adjustment.......... (30) (12) (7)
Other...................................... 2 (5) (1)
------ ------ ------
Balance at end of year.................. (57) (29) (12)
------ ------ ------
Treasury stock, at cost:
Balance at beginning of year............... (9) (273) (5) (150) (4) (112)
Issuance of treasury stock, net of related
cost.................................... -- 2
Stock repurchases.......................... (1) (37)
Compensation related issuances............. -- 3 (5) (182) -- (1)
Retirement of Sonat treasury shares........ 1 59
--- ------ --- ------ --- ------
Balance at end of year.................. (9) (268) (9) (273) (5) (150)
--- ------ --- ------ --- ------
Unamortized compensation:
Balance at beginning of year............... (41) (65) (81)
Restricted stock activity, net............. (84) (43) 16
Early vesting of equity plans.............. 67
------ ------ ------
Balance at end of year.................. (125) (41) (65)
--- ------ --- ------ --- ------
Total stockholders' equity................... 234 $3,569 230 $2,947 231 $3,437
=== ====== === ====== === ======
Comprehensive income (loss).................. $ 624 $ (272) $ (314)
====== ====== ======
</TABLE>
See accompanying notes.
43
<PAGE> 46
EL PASO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. We account for investments in companies
where we have the ability to exert significant influence, but not control, over
operating and financial policies using the equity method. Our consolidated
financial statements for previous periods include reclassifications that were
made to conform to the current year presentation. Those reclassifications have
no impact on reported net income or stockholders' equity.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues, and expenses
and disclosure of contingent assets and liabilities that exist at the date of
the financial statements. Our actual results are likely to differ from those
estimates.
Accounting for Regulated Operations
Our interstate natural gas systems are subject to the jurisdiction of FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. Each system operates under separate FERC approved tariffs which establish
rates, terms and conditions under which each system provides services to its
customers. Our businesses that are subject to the regulations and accounting
requirements of FERC have followed the accounting requirements of Statement of
Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation, which may differ from the accounting requirements
of our non-regulated entities. Transactions that have been recorded differently
as a result of regulatory accounting requirements include the capitalization of
an equity return component on regulated capital projects, employee related
benefits, and other costs and taxes included in, or expected to be included in,
future rates, including costs to refinance debt.
When the accounting method followed is required by or allowed by the
regulatory authority for rate-making purposes, the method conforms to the
generally accepted accounting principle of matching costs with the revenues to
which they apply.
Cash and Cash Equivalents
We consider short-term investments purchased with an original maturity of
less than three months to be cash equivalents.
Inventory
Our inventory consists of materials and supplies, natural gas in storage
for non-trading purposes, and optic fiber being constructed for sale to, or
exchange with, third parties. We value these inventories at the lower of cost or
market with cost determined using the average cost method.
44
<PAGE> 47
Property, Plant, and Equipment
Regulated. Our regulated property, plant, and equipment is recorded at its
original cost of construction or, upon acquisition, the cost to the entity that
first placed the asset in service. We capitalize direct costs, like labor and
materials, and indirect costs, like overhead and allowance for funds used during
construction. We capitalize the major units of property replacements or
improvements and expense the minor ones.
When applicable, we use the composite (group) method to depreciate
regulated property, plant, and equipment. Assets with similar lives and other
characteristics are grouped and depreciated as one asset. We apply the
depreciation rate, approved in our rates, to the total cost of the group, until
its net book value equals its salvage value. Currently, our depreciation rates
vary from 1 to 33 percent. These rates depreciate the related assets over 2 to
36 years. We re-evaluate depreciation rates each time we redevelop our
transportation rates.
When we retire regulated property, plant, and equipment, we charge
accumulated depreciation and amortization for the original cost, plus the cost
of retirement (the cost to remove, sell, or dispose), less its salvage value. We
do not recognize a gain or loss unless we sell an entire operating unit. We
include gains or losses on dispositions of operating units in income.
Non-Regulated. We record our non-regulated property, plant, and equipment
at its original cost of construction or, upon acquisition, at the fair value of
the assets acquired. We capitalize all direct and indirect costs of the project,
including interest costs on related debt.
We depreciate these properties over their estimated useful lives using a
straight line or composite method. The annual depreciation rates are as follows:
<TABLE>
<S> <C>
Gathering and processing systems......................... 2.5% to 20.0%
Power facilities......................................... 2.0% to 33.0%
Transportation equipment................................. 2.5% to 10.0%
Buildings and improvements............................... 2.5% to 20.0%
Office and miscellaneous equipment....................... 10.0% to 33.0%
</TABLE>
When we retire non-regulated properties, we reduce property, plant, and
equipment for its original cost, less accumulated depreciation, and salvage. Any
remaining amount is charged to income.
General. At December 31, 2000 and 1999, we had approximately $875 million
and $597 million construction work in progress included in our property, plant,
and equipment.
We evaluate impairment of our regulated and non-regulated property, plant,
and equipment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable in accordance with SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of.
Natural Gas and Oil Properties
We use the full cost method to account for our natural gas and oil
properties. Under the full cost method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration, and development of
natural gas and oil reserves are capitalized. These capitalized costs include
the costs of all unproved properties, internal costs directly related to
acquisition and exploration activities, and capitalized interest.
We amortize these costs using a unit of production method over the life of
our proved reserves. We exclude unevaluated properties from our amortization
base, until we make a determination as to the existence of proved reserves. Our
total capitalized costs are limited to a ceiling of the present value of future
net revenues, discounted at 10 percent, plus the lower of cost or fair market
value of unproved properties. If these discounted revenues are not equal to or
greater than total capitalized costs, we are required to write-down our
45
<PAGE> 48
capitalized costs to this level. In 1999 and 1998, we determined that
capitalized costs exceeded the ceiling test limits by a total of $352 million
and $1,035 million. These write-downs are included in our income statement as
ceiling test charges.
We treat the sale of natural gas and oil properties as an adjustment to
cost of these properties. We do not recognize a gain or loss on these sales,
unless the properties sold is significant.
Intangible Assets
Intangible assets consist primarily of goodwill arising as a result of
mergers and acquisitions. We amortize these intangible assets using the
straight-line method over periods ranging from 5 to 40 years. Our accumulated
amortization of intangible assets was $101 million and $62 million as of
December 31, 2000 and 1999. We evaluate impairment of goodwill in accordance
with SFAS No. 121. Under this methodology, when an event occurs to suggest that
impairment may have occurred, we evaluate the undiscounted net cash flows of the
underlying asset or entity. If these cash flows are not sufficient to recover
the value of the underlying asset or entity plus the goodwill amount, these cash
flows are discounted at a risk-adjusted rate with any difference recorded as a
charge to our income statement.
Revenue Recognition
Our regulated businesses recognize revenues from natural gas transportation
in the period the service is provided. Reserves are provided on revenues
collected that may be subject to refund. Revenues on services other than
transportation are recorded when they are earned.
Our non-regulated businesses record revenues at various points when they
are earned, including when deliveries of the physical commodities are made, or
in the period services are provided. See the discussion of price risk management
activities below for our revenue recognition policies on our trading activities.
In the fourth quarter of 2000, we implemented Emerging Issues Task Force
Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent,
which provides guidance on the gross versus net presentation of revenues and
expenses. As a result of adoption, revenues and related costs increased by $87
million, $128 million, and $60 million for 2000, 1999, and 1998. These
reclassifications had no impact on net income or earnings per share.
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate. We
expense amounts that relate to existing conditions caused by past operations,
and which do not contribute to current or future revenue generation. We record
liabilities when environmental assessments indicate that remediation efforts are
probable and the costs can be reasonably estimated. Estimates of our liabilities
are based upon currently available facts, existing technology and presently
enacted laws and regulations taking into consideration the likely effects of
inflation and other societal and economic factors, and include estimates of
associated legal costs. These amounts also consider prior experience in
remediating contaminated sites, other companies' clean-up experience and data
released by the EPA or other organizations. They are subject to revision in
future periods based on actual costs or new circumstances, and are included in
our balance sheet at their undiscounted amounts. We evaluate recoveries
separately from the liability and, when recovery is assured, we record and
report an asset separately from the associated liability in our financial
statements.
Price Risk Management Activities
We utilize derivative financial instruments to manage market risks
associated with commodities we sell, interest rates, and foreign currency
exchange rates. We engage in both trading and non-trading commodity price risk
management activities.
46
<PAGE> 49
Our trading activities consist of services provided to the energy sector,
primarily related to natural gas and power. Our energy trading activities,
including transportation capacity and storage, are accounted for using the
mark-to-market method of accounting. We conduct our trading activities through a
variety of financial instruments, including:
- exchange traded futures contracts involving cash settlement;
- forward contracts involving cash settlement or physical delivery of an
energy commodity;
- swap contracts, which require us to make payments to (or receive payments
from) counterparties based on the difference between fixed and variable
prices for the commodity;
- exchange-traded and over-the-counter options; and
- other contractual arrangements.
Under the mark-to-market method of accounting, commodity and energy related
contracts are reflected at quoted or estimated market value with resulting gains
and losses included in our income statement. Net gains or losses recognized in a
period result primarily from the impact of price movements on transactions
originating in that or previous periods. Assets and liabilities resulting from
mark-to-market accounting are included in our balance sheets and are classified
according to their term to maturity. We reflect receivables and payables that
arise upon the actual settlement of these contracts separately from price risk
management activities in our balance sheet as trade receivables or payables.
Cash inflows and outflows associated with these price risk management activities
are recognized in operating cash flows as transactions are settled. During the
years ended December 31, 2000 and 1999, we recognized gross margins from our
trading activities of $406 million and $91 million.
The market value of commodity and energy related contracts reflects our
best estimate, and considers factors including closing exchange and
over-the-counter quotations, time value, and volatility factors underlying these
contracts. The values are adjusted to reflect the potential impact of
liquidating our position in an orderly manner over a reasonable period of time
under present market conditions and to reflect other types of risks, including
model risk, credit risk and operational risks. In the absence of quoted market
prices, we utilize other valuation techniques to estimate fair value. The use of
these techniques requires us to make estimations of future prices and other
variables, including market volatility, price correlation, and market liquidity.
Changes in these estimates could have a significant impact on our market
valuations and could materially impact our estimates.
Derivative and other financial instruments are also utilized in connection
with non-trading activities. We enter into forwards, swaps, and other contracts
to hedge the impact of market fluctuations on assets, liabilities, or other
contractual commitments. Hedge accounting is applied only if the derivative
reduces the risk of the underlying hedged item, is designated as a hedge at its
inception, and is expected to result in financial impacts which are inversely
correlated to those of the item being hedged. If correlation ceases to exist,
hedge accounting is terminated and mark-to-market accounting is applied. Changes
in the market value of hedged transactions are deferred until the gain or loss
on the hedged item is recognized. Derivatives held for non-trading purposes are
recorded as gains or losses in operating income and cash inflows and outflows
are recognized in operating cash flows as transactions are settled. See Note 6
for a further discussion of our price risk management activities.
Income Taxes
We report income taxes based on income reported on our tax returns along
with a provision for deferred income taxes. Deferred income taxes reflect the
estimated future tax consequences of differences between the financial statement
and tax bases of assets and liabilities and carryovers at each year end. We
account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based upon our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision in future periods based on new facts
or circumstances.
47
<PAGE> 50
Comprehensive Income (Loss)
Comprehensive income (loss) is determined based on net income (loss),
adjusted for changes in accumulated other comprehensive income.
Treasury Stock
We account for treasury stock using the cost method and report it in our
balance sheet as a reduction to stockholders' equity. Treasury stock sold or
issued is valued on a first-in, first-out basis. Included in treasury stock at
December 31, 2000, and 1999, were 1.36 million shares of common stock that were
reserved for use under several of our benefit plans, as well as approximately
5.8 million shares of common stock which were held in a trust under our deferred
compensation programs.
Stock-Based Compensation
We apply the provisions of Accounting Principles Board Opinion No. 25 and
its related interpretations in accounting for our stock compensation plans.
Accordingly, compensation expense is not recognized for stock options unless the
options were granted at an exercise price lower than market on the grant date.
We use fixed and variable plan accounting for our fixed and variable
compensation plans.
Cumulative Effect of Accounting Change
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-Up
Activities. The statement defined start-up activities and required start-up and
organization costs be expensed as incurred. In addition, it required that any
such cost that existed on the balance sheet be expensed upon adoption of the
pronouncement. We adopted the pronouncement effective January 1, 1999, and
reported a charge of $13 million, net of income taxes, as a cumulative effect of
an accounting change.
Accounting for Derivative Instruments and Hedging Activities
In June of 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June of 1999, the FASB
extended the adoption date of SFAS No. 133 through the issuance of SFAS No. 137,
Deferral of the Effective Date of SFAS 133. In June 2000, the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, which also amended SFAS No. 133. SFAS No. 133, and its amendments
and interpretations, establishes accounting and reporting standards for
derivative instruments, including derivative instruments embedded in other
contracts, and derivative instruments used for hedging activities. It requires
that we measure all derivative instruments at their fair value, and classify
them as either assets or liabilities on our balance sheet, with a corresponding
offset to income or other comprehensive income depending on their designation,
their intended use, or their ability to qualify as hedges under the standard.
We adopted SFAS No. 133 on January 1, 2001, and applied the standard to all
derivative instruments that existed on that date, except for derivative
instruments embedded in other contracts. As provided for in SFAS No. 133, we
applied the provisions of the standard to derivative instruments embedded in
other contracts issued, acquired, or substantially modified after December 31,
1998.
We use a variety of derivative instruments to conduct both energy trading
activities and to hedge risks associated with commodity prices, foreign
currencies and interest rates. The derivative instruments we use in commodity
trading activities are recorded at their fair value in our financial statements
under the provisions of Emerging Issues Task Force Issue No. 98-10, Accounting
for Contracts Involved in Energy Trading and Risk Management Activities. As a
result, SFAS No. 133 did not impact our accounting for these instruments.
Based on commodity prices, interest rates, and foreign currency exchange
rates existing at December 31, 2000, we will reflect the impact of our adoption
of SFAS No. 133 as of January 1, 2001, by recording a cumulative effect
transition adjustment as a charge to other comprehensive income of
48
<PAGE> 51
$821 million, net of income taxes, a reduction of assets of $37 million, and an
increase in liabilities of $784 million. This represents the fair value of our
derivative instruments designated as cash flow hedges. The majority of the
initial charge relates to the hedging of forecasted sales of natural gas we
expect to produce through the end of 2001.
Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities
In September 2000, the FASB issued SFAS No. 140, Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities, which
replaces SFAS No. 125. This statement revises the standards for accounting for
securitizations and other transfers of financial assets and collateral and
requires certain disclosures, but carries over most of SFAS No. 125's provisions
without reconsideration. This standard has various effective dates, the earliest
of which is for fiscal years ending after December 15, 2000. This pronouncement
will not have a material effect on our financial statements.
2. MERGERS AND ACQUISITIONS
Coastal
In January 2001, we merged with Coastal. We accounted for the transaction
as a pooling of interests and converted each share of Coastal common stock and
Class A common stock on a tax-free basis into 1.23 shares of our common stock.
We exchanged Coastal's outstanding convertible preferred stock for our common
stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. The total value of the
transaction was approximately $24 billion, including $7 billion of assumed debt
and preferred equity. In the merger, we issued approximately 271 million shares
of our common stock, including 4 million shares in exchange for Coastal stock
options.
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; petroleum refining, marketing and distribution; chemicals
production; power production; and coal mining. Coastal owns interests in
approximately 18,000 miles of natural gas pipelines extending across the
midwestern and the Rocky Mountain areas of the United States and has proved
reserves of 3.6 Tcfe. Coastal also has international and domestic interests in
natural gas and oil producing properties, power production plants, and crude oil
refining facilities.
Presented below are the unaudited pro forma results of this merger as if it
had occurred on
January 1, 1998:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
------- ------- -------
(IN MILLIONS, EXCEPT PER
SHARE AMOUNTS)
<S> <C> <C> <C>
Operating Results Data:
Operating revenues(1)....................................... $49,268 $27,332 $23,773
Income from continuing operations........................... 1,236 257 176
Basic earnings per common share from continuing operations
available to common stockholders.......................... 2.50 0.52 0.35
Diluted earnings per common share from continuing operations
available to common stockholders.......................... 2.43 0.52 0.34
Basic average common shares outstanding..................... 494 490 487
Diluted average common shares outstanding................... 513 497 495
</TABLE>
- ---------------
(1) Operating revenues include an adjustment to conform the presentation of
Coastal's petroleum trading activities to our manner of presentation.
Texas Midstream Operations
In December 2000, we completed our purchase of PG&E's Texas Midstream
operations. The total value of the transaction was $887 million, including
assumed debt of approximately $527 million. The transaction was accounted for as
a purchase and is included in our Field Services segment.
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<PAGE> 52
The operations acquired consisted of 7,500 miles of intrastate natural gas
transmission and natural gas liquids pipelines that transport approximately 2.8
Bcf/d, nine natural gas processing and fractionation plants that currently
process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. In
March 2001, we sold some of these acquired natural gas liquids transportation
and several fractionation assets to Energy Partners for approximately $133
million.
Sonat
In October 1999, we completed our merger with Sonat, a diversified energy
holding company engaged in domestic oil and natural gas exploration and
production, the transmission and storage of natural gas, and natural gas and
power marketing. In the merger, one share of our common stock was issued in
exchange for each share of Sonat common stock. Total common shares issued in the
merger were approximately 110 million. The transaction was valued at
approximately $7 billion based on our closing stock price on October 25, 1999.
The merger was accounted for as a pooling of interests.
Divestitures
During 2000, we completed the sales of East Tennessee Natural Gas Company,
Sea Robin Pipeline Company and our one-third interest in Destin Pipeline Company
to comply with a Federal Trade Commission order related to our merger with
Sonat. Proceeds from the sales were approximately $616 million and we recognized
an extraordinary gain of $89 million, net of income taxes of $60 million. In
December 2000, we sold our interest in Oasis Pipeline Company to comply with a
Federal Trade Commission order. We incurred a loss on this transaction of
approximately $19 million, net of income taxes. We recorded the gains and losses
on these sales as extraordinary items in our income statement.
As a result of our merger with Coastal, we will be required by the Federal
Trade Commission to sell our Midwestern system, a pipeline system in the
midwest. Total estimated proceeds from the sale are $90 million, resulting in an
estimated gain of $50 million, before income taxes. We expect to complete this
sale in the second quarter of 2001.
Additionally, in the first quarter of 2001, Energy Partners sold its
interests in several offshore assets. These sales consisted of interests in
seven natural gas pipeline systems, a dehydration facility, and two offshore
platforms. Proceeds from the sales of these assets were approximately $135
million and resulted in a loss to the partnership of approximately $23 million.
As consideration for these sales, we committed to pay Energy Partners a series
of payments totaling $29 million. This amount, as well as our proportional share
of the losses on the sale of the partnership's assets, will be recorded as a
charge in our income statement in the first quarter of 2001.
We do not anticipate the impact from these sales to be material to our
ongoing financial position, operating results, or cash flows.
3. MERGER-RELATED COSTS AND ASSET IMPAIRMENT CHARGES
Merger-Related Costs
During 2000, 1999, and 1998, we incurred merger-related charges related to
our mergers with Coastal, Sonat, and our merger in 1998 with Zilkha Energy
Company. These charges included the following:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------------
2000 1999 1998
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Employee severance, retention and transition costs.......... $31 $303 $--
Transaction costs........................................... 44 62 --
Merger-related asset impairments............................ -- 78 --
Other....................................................... 5 72 15
--- ---- ---
$80 $515 $15
=== ==== ===
</TABLE>
50
<PAGE> 53
Employee severance, retention and transition costs include direct payments
to, and benefit costs for severed employees and early retirees that occurred as
a result of merger-related workforce consolidations within our operating
segments and the elimination of redundant positions within our merged
operations. These costs included actual severance payments and costs for pension
and post-retirement benefits settled and curtailed under existing benefit plans.
Retention charges include payments to employees who were retained following the
merger and payments to employees to satisfy contractual obligations. Transition
costs relate to costs to relocate employees and costs for severed and retired
employees arising after their severance date to transition their jobs into the
ongoing workforce. The unpaid portion of these charges was $7 million at
December 31, 2000, and $76 million at December 31, 1999.
Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our mergers.
Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, redundant facilities and assets whose
value was impaired as a result of decisions on the strategic direction of our
combined operations following each of our mergers.
Other costs primarily consist of charges to conform accounting policies and
practices, integrate facilities, and retain seismic data in our production
operations.
In conjunction with the Coastal merger, we issued approximately 4.4 million
shares of common stock in exchange for Coastal options. This resulted in a
charge of approximately $278 million that will be recorded in the first quarter
of 2001. On January 30, we announced a workforce reduction and consolidation.
The restructuring resulted in the reduction of 3,285 full-time positions through
terminations and early retirement. A majority of the total charges connected
with the restructuring will be recorded in the first quarter of 2001 and are
estimated to be approximately $890 million.
Asset Impairment Charges
During 2000 and 1999, we incurred asset impairment charges of $11 million
and $42 million. The 2000 charge resulted from Field Services' impairment of its
Needle Mountain processing facility in Arizona due to unrecoverability of costs.
The 1999 charges consisted of impairments of regulatory assets that were not
recoverable based on the settlement of SNG's rate case.
4. INCOME TAXES
The following table reflects the components of income tax expense (benefit)
included in income (loss) before extraordinary items and cumulative effect of
accounting change for the three years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
----- ---- -----
(IN MILLIONS)
<S> <C> <C> <C>
Current
Federal................................................... $(119) $(44) $ 25
State..................................................... (19) (4) (6)
Foreign................................................... 7 11 5
----- ---- -----
(131) (37) 24
----- ---- -----
Deferred
Federal................................................... 377 (51) (210)
State..................................................... 43 8 17
Foreign................................................... (3) (1) (1)
----- ---- -----
417 (44) (194)
----- ---- -----
Total income tax expense (benefit)................ $ 286 $(81) $(170)
===== ==== =====
</TABLE>
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<PAGE> 54
Our tax expense (benefit), included in income (loss) before extraordinary
items and cumulative effect of accounting change, differs from the amount
computed by applying the statutory federal income tax rate of 35 percent for the
following reasons at December 31:
<TABLE>
<CAPTION>
2000 1999 1998
---- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Tax expense (benefit) at the statutory federal rate of
35%....................................................... $304 $(113) $(167)
Increase (decrease)
State income tax, net of federal income tax benefit....... 16 3 7
Dividend exclusion........................................ (26) (14) (7)
Non-deductible portion of merger-related costs............ 11 29 --
Foreign income taxed at different rates, not subject to
U.S. tax............................................... (19) (9) (8)
Deferred credit on loss carryover......................... (18) -- --
Preferred stock dividends of a subsidiary................. 9 9 9
Other..................................................... 9 14 (4)
---- ----- -----
Income tax expense (benefit)................................ $286 $ (81) $(170)
==== ===== =====
Effective tax rate.......................................... 33% 25% 36%
==== ===== =====
</TABLE>
The following are the components of our net deferred tax liability at
December 31:
<TABLE>
<CAPTION>
2000 1999
------ ------
(IN MILLIONS)
<S> <C> <C>
Deferred tax liabilities
Property, plant, and equipment............................ $2,657 $2,364
Investments in unconsolidated affiliates.................. 272 91
Price risk management activities.......................... 244 17
Regulatory and other assets............................... 657 469
------ ------
Total deferred tax liability...................... 3,830 2,941
------ ------
Deferred tax assets
U.S. net operating loss and tax credit carryovers......... 487 364
Accrual for regulatory issues............................. 247 272
Employee benefit and deferred compensation obligations.... 197 211
Other liabilities......................................... 723 492
Valuation allowance....................................... (3) (6)
------ ------
Total deferred tax asset.......................... 1,651 1,333
------ ------
Net deferred tax liability.................................. $2,179 $1,608
====== ======
</TABLE>
52
<PAGE> 55
At December 31, 2000, the portion of the cumulative undistributed earnings
of our foreign subsidiaries and foreign corporate joint ventures on which we
have not recorded U.S. income taxes was approximately $178 million. Since these
earnings have been or are intended to be indefinitely reinvested in foreign
operations, no provision has been made for any U.S. taxes or foreign withholding
taxes that may be applicable upon actual or deemed repatriation. If a
distribution of such earnings were to be made, we might be subject to both
foreign withholding taxes and U.S. income taxes, net of any allowable foreign
tax credits or deductions. However, an estimate of these taxes is not
practicable. For these same reasons, we have not recorded a provision for U.S.
income taxes on the foreign currency translation adjustment recorded in other
comprehensive income.
The tax benefit associated with the exercise of non-qualified stock options
and the vesting of restricted stock as well as restricted stock dividends,
reduced taxes payable by $42 million in 2000, $13 million in 1999 and $10
million in 1998. These benefits are included in additional paid-in capital in
our balance sheets.
As of December 31, 2000, we had capital loss carryovers of $21 million for
which the carryover period ends in 2001, alternative minimum tax credits of $71
million that carryover indefinitely, and $2 million of general business credit
carryovers for which the carryover periods end at various times in the years
2006 through 2017. Usage of these carryovers is subject to the limitations
provided under Sections 382 and 383 of the Internal Revenue Code as well as the
separate return limitation year rules of IRS regulations. The table below
presents the details of our net operating loss carryover periods.
<TABLE>
<CAPTION>
CARRYOVER PERIOD
------------------------------------------------
2002 - 2011 - 2016 -
2001 2010 2015 2020 TOTAL
---- ------ -------- -------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Net operating loss........................... -- $74 $253 $835 $1,162
</TABLE>
We recorded a valuation allowance to reflect the estimated amount of
deferred tax assets which we may not realize due to the expiration of net
operating loss and tax credit carryovers. As of December 31, 2000 and 1999,
approximately $1 million and $4 million, respectively, of the valuation
allowance relates to net operating loss carryovers of an acquired company. The
remainder of the allowance relates to general business credit carryovers. With
the exception of $2 million, any tax benefits subsequently recognized from the
reversal of the allowance will be allocated to additional acquisition cost
assigned to utility plant.
Prior to 1999, our subsidiary, El Paso Tennessee Pipeline Co., and its
subsidiaries filed a separate consolidated federal income tax return from our
consolidated return. On January 1, 1999, as a result of a 1998 tax-free internal
reorganization, El Paso Tennessee and its subsidiaries joined our consolidated
federal income tax group. The subsidiaries of Sonat Inc. joined our consolidated
federal income tax group on October 26, 1999, after our merger. After the
Coastal merger, we will file a consolidated federal income tax return with
Coastal.
In connection with our acquisition of El Paso Tennessee, we entered into a
tax sharing agreement with Newport News Shipbuilding Inc., new Tenneco Inc., and
El Paso Tennessee. This tax sharing agreement provides, among other things, for
the allocation among the parties of tax assets and liabilities arising prior to,
as a result of and subsequent to the distributions of new Tenneco Inc. and
Newport News Shipbuilding Inc. to the shareholders of old Tenneco Inc. (now
known as El Paso Tennessee).
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<PAGE> 56
5. EARNINGS PER SHARE
We calculated basic and diluted earnings per share amounts as follows.
<TABLE>
<CAPTION>
2000 1999 1998
--------------- -------- --------
BASIC DILUTED BASIC(1) BASIC(1)
----- ------- -------- --------
(IN MILLIONS, EXCEPT PER
COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Income (loss) before extraordinary items and cumulative
effect of accounting change.............................. $ 582 $ 582 $ (242) $ (306)
Interest on trust preferred securities................... -- 10 -- --
----- ----- ------ ------
Adjusted income (loss) before extraordinary items and
cumulative effect of accounting change................ 582 592 (242) (306)
Extraordinary items, net of income taxes................. 70 70 -- --
Cumulative effect of accounting change, net of income
taxes................................................. -- -- (13) --
----- ----- ------ ------
Adjusted net income (loss)................................. $ 652 $ 662 $ (255) $ (306)
===== ===== ====== ======
Average common shares outstanding.......................... 230 230 228 226
Effect of diluted securities
Stock options............................................ -- 5 -- --
Trust preferred securities............................... -- 8 -- --
----- ----- ------ ------
Average common shares outstanding.......................... 230 243 228 226
===== ===== ====== ======
Earnings (loss) per common share
Adjusted income (loss) before extraordinary items and
cumulative effect of accounting change................ $2.53 $2.44 $(1.06) $(1.35)
Extraordinary items, net of income taxes................. 0.30 0.29 -- --
Cumulative effect of accounting change, net of income
taxes................................................. -- -- (0.06) --
----- ----- ------ ------
Adjusted net income (loss)............................... $2.83 $2.73 $(1.12) $(1.35)
===== ===== ====== ======
</TABLE>
- ---------------
(1) The addition of potential average common shares outstanding for 1999 and
1998 is antidilutive and would have reduced the loss per share.
6. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
Fair Value of Financial Instruments
The carrying amounts and estimated fair values of our financial instruments
at December 31 are as follows:
<TABLE>
<CAPTION>
2000 1999
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Balance sheet financial instruments:
Long-term debt, including current maturities...... $6,638 $ 6,722 $5,315 $5,204
Notes payable to unconsolidated affiliates........ 740 763 -- --
Company-obligated preferred securities of
subsidiaries.................................... 625 879 325 327
Trading instruments
Futures contracts............................... 137 137 (24) (24)
Option contracts(1)............................. (118) (118) 264 264
Swap and forward contracts...................... 1,153 1,153 (65) (65)
Equity swap....................................... -- -- 10 10
Other financial instruments:
Non-trading instruments
Commodity swap and forward contracts............ $ -- $(1,214) $ -- $ (17)
Commodity futures contracts..................... -- -- -- 2
Foreign currency forward purchases.............. -- 3 -- 4
Interest rate swap agreements................... -- -- -- 4
</TABLE>
- ---------------
(1) Excludes transportation capacity, tolling agreements, and natural gas in
storage held for trading purposes since these do not constitute financial
instruments.
54
<PAGE> 57
As of December 31, 2000, and 1999, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term nature of these
instruments. The fair value of long-term debt with variable interest rates
approximates its carrying value because of the market based nature of the debt's
interest rates. We estimated the fair value of debt with fixed interest rates
based on quoted market prices for the same or similar issues. We estimated the
fair value of all derivative financial instruments based on quoted market
prices, current market conditions, estimates we obtained from third-party
brokers or dealers, or amounts derived using valuation models.
Trading Commodity Activities
The fair value of commodity and energy related contracts entered into for
trading purposes as of December 31, 2000 and 1999, and the average fair value of
those instruments are set forth below.
<TABLE>
<CAPTION>
AVERAGE FAIR
VALUE FOR THE
YEAR ENDED
ASSETS LIABILITIES DECEMBER 31,(1)
------ ----------- ---------------
(IN MILLIONS)
<S> <C> <C> <C>
2000
Futures contracts................................. $ 137 $ -- $266
Option contracts.................................. 2,135 (1,594) 589
Swap and forward contracts........................ 3,647 (2,185) 518
1999
Futures contracts................................. $ 2 $ (26) $(12)
Option contracts.................................. 455 (35) 184
Swap and forward contracts........................ 189 (231) 93
</TABLE>
- ---------------
(1) Computed using the net asset (liability) balance at each month end.
Notional Amounts and Terms
The notional amounts and terms of our energy commodity financial
instruments at December 31, 2000, and 1999 are set forth below (natural gas
volumes are in trillions of British thermal units, power volumes are in millions
of megawatt hours, liquids volumes are in millions of barrels, weather volumes
are in thousands of degree days, and energy capacity volumes are in millions of
kilowatt hours):
<TABLE>
<CAPTION>
FIXED PRICE FIXED PRICE MAXIMUM
PAYOR RECEIVER TERMS IN YEARS
----------- ----------- --------------
<S> <C> <C> <C>
2000
Energy Commodities:
Natural gas...................................... 34,305 29,895 27
Power............................................ 133 143 20
Liquids(1)....................................... 8 8 6
Weather.......................................... 133 135 --
Energy capacity.................................. 22 29 13
1999
Energy Commodities:
Natural gas...................................... 26,457 24,565 26
Power............................................ 30 41 20
Liquids(1)....................................... 8 8 7
</TABLE>
- ---------------
(1) Liquids include crude oil, condensate and natural gas liquids.
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<PAGE> 58
The notional amount and terms of foreign currency forward purchases and
sales at December 31, 2000 and 1999, were as follows:
<TABLE>
<CAPTION>
NOTIONAL VOLUME
------------------------- MAXIMUM
BUY SELL TERM IN YEARS
----------- ----------- --------------
<S> <C> <C> <C>
2000
Foreign Currency (in millions)
Canadian Dollars.............................. 1,095 441 8
1999
Foreign Currency (in millions)
Canadian Dollars.............................. 296 194 9
British Pounds................................ -- 28 9
</TABLE>
Notional amounts reflect the volume of transactions but do not represent
the actual amounts exchanged by the parties. As a result, notional amounts are
an incomplete measure of our exposure to market or credit risks. The maximum
terms in years detailed above are not indicative of likely future cash flows as
these positions may be offset or cashed-out in the commodity and currency
markets based on our risk management needs and liquidity in those markets.
The weighted average maturity of our entire portfolio of price risk
management activities was approximately two years as of December 31, 2000, and
six years as of December 31, 1999.
Market and Credit Risks
We serve a diverse customer group that generates a need for a variety of
financial structures, products and terms. This diversity requires us to manage,
on a portfolio basis, the resulting market risks inherent in these transactions
subject to parameters established by our risk management committee. We monitor
market risks through a risk control committee operating independently from the
units that create or actively manage these risk exposures to ensure compliance
with our stated risk management policies.
We measure and adjust the risk in our portfolio in accordance with
mark-to-market and other risk management methodologies which utilize forward
price curves in the energy markets to estimate the size and probability of
future potential exposure.
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We maintain credit policies with regard to our counterparties to
minimize overall credit risk. These policies require an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances (including cash in advance, letters of
credit, and guarantees), and the use of standardized agreements that allow for
the netting of positive and negative exposures associated with a single
counterparty. The counterparties associated with our assets from price risk
management activities are summarized as follows:
<TABLE>
<CAPTION>
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF
DECEMBER 31, 2000
---------------------------------------------------
INVESTMENT BELOW
GRADE(1) INVESTMENT GRADE TOTAL(2)
------------------- ---------------- --------
(IN MILLIONS)
<S> <C> <C> <C>
Energy marketers............................. $2,459 $ 8 $2,467
Financial institutions....................... 1,161 -- 1,161
Oil and natural gas producers................ 613 -- 613
Natural gas and electric utilities........... 1,496 54 1,550
Industrials.................................. 98 2 100
Municipalities............................... 17 -- 17
Other........................................ 10 1 11
------ --- ------
Total assets from price risk
management activities............. $5,854 $65 $5,919
====== === ======
</TABLE>
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<PAGE> 59
<TABLE>
<CAPTION>
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF
DECEMBER 31, 1999
---------------------------------------------------
INVESTMENT BELOW
GRADE(1) INVESTMENT GRADE TOTAL(2)
------------------- ---------------- --------
(IN MILLIONS)
<S> <C> <C> <C>
Energy marketers............................. $226 $ 1 $227
Financial institutions....................... 21 -- 21
Oil and natural gas producers................ 26 -- 26
Natural gas and electric utilities........... 251 2 253
Industrials.................................. 15 -- 15
Municipalities............................... 64 -- 64
Other........................................ 40 -- 40
---- --- ----
Total assets from price risk
management activities............. $643 $ 3 $646
==== === ====
</TABLE>
- ---------------
(1)Investment Grade is primarily determined using publicly available credit
ratings along with consideration of collateral, which encompass standby
letters of credit, parent company guarantees and property interest, including
natural gas and oil reserves. Included in Investment Grade are counterparties
with a minimum Standard & Poor's or Moody's rating of BBB- or Baa3,
respectively, or minimum implied (through internal credit analysis) Standard
& Poor's equivalent rating of BBB-.
(2)We had one customer in 2000 and four customers in 1999 that comprised greater
than 5 percent of assets from price risk management activities. Each of these
customers have investment grade ratings.
This concentration of counterparties may impact our overall exposure to
credit risk, either positively or negatively, in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions. Based
on our policies, risk exposure, and reserves, we do not anticipate a material
adverse effect on our financial position, operating results, or cash flows as a
result of counterparty nonperformance.
Non-Trading Price Risk Management Activities
We also utilize derivative financial instruments for non-trading activities
to mitigate market price risk associated with significant physical transactions.
Non-trading commodity activities are accounted for using hedge accounting
provided they meet hedge accounting criteria. Non-trading activities are
conducted through exchange traded futures contracts, swaps, and forward
agreements with third parties.
At December 31, 2000 and 1999, the notional amounts and terms of contracts
held for purposes other than trading were as follows:
<TABLE>
<CAPTION>
2000 1999
-------------------------- --------------------------
NOTIONAL NOTIONAL
VOLUME VOLUME
---------- MAXIMUM ---------- MAXIMUM
BUY SELL TERM IN YEARS BUY SELL TERM IN YEARS
--- ---- ------------- --- ---- -------------
<S> <C> <C> <C> <C> <C> <C>
Commodity
Natural Gas (TBtu)....................... 115 519 12 22 548 13
Power (MMWh)............................. 64 35 2 -- -- --
Liquids (MMBbls)......................... -- 2 1 -- 1 2
</TABLE>
In August 1999, we entered an interest rate swap agreement with a notional
amount of $600 million and a termination date of July 2001. In the agreement, we
swapped the fixed interest rate on our July 1999 $600 million aggregate
principal Senior Notes due 2001, for a floating three month LIBOR plus a margin
of 14.75 basis points. Total interest expense was less than $1 million in 2000
and 1999, as a result of this swap agreement. In November 2000, we terminated
this swap. The termination of this swap did not have a material impact on our
financial results.
In May 2000, we terminated our equity swap transaction associated with an
additional 18.5 percent of CAPSA's outstanding stock and purchased the
counterparty's 18.5 percent interest in CAPSA for approximately $127 million.
CAPSA is a privately held Argentine company engaged in power generation and
natural gas and oil production. Under the swap, we paid interest to the
counterparty, on a quarterly basis, on a
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<PAGE> 60
notional amount of $103 million at a rate of LIBOR plus 1.75 percent. In
exchange, we received dividends, if any, on the CAPSA stock to the extent of the
counterparty's equity interest of 18.5 percent. We also fully participated in
the market appreciation or depreciation of the underlying investment whereby we
realized appreciation or funded any depreciation attributable to the actual sale
of the stock upon termination or expiration of the swap transaction. The
termination of this swap did not have a material impact on our financial
results.
We also face credit risk with respect to our non-trading activities, and
take similar measures as in our trading activities to mitigate this risk. Based
upon our policies and risk exposure, we do not anticipate a material effect on
our financial position, operating results or cash flows resulting from
counterparty non-performance.
7. INVENTORY
Our inventory consisted of the following at December 31:
<TABLE>
<CAPTION>
2000 1999
----- -----
(IN MILLIONS)
<S> <C> <C>
Materials and supplies...................................... $ 78 $71
Natural gas in storage...................................... 58 2
Work in progress -- Fiber................................... 31 1
---- ---
Total............................................. $167 $74
==== ===
</TABLE>
8. PROPERTY, PLANT, AND EQUIPMENT
Our property, plant, and equipment consisted of the following at December
31:
<TABLE>
<CAPTION>
2000 1999
------- -------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost
Pipelines................................................. $ 7,997 $ 8,126
Power facilities.......................................... 351 516
Gathering and processing systems.......................... 2,545 1,220
Production................................................ 5,932 5,415
Corporate and Other....................................... 248 196
------- -------
17,073 15,473
Less accumulated depreciation, depletion, and
amortization.............................................. 7,777 7,657
------- -------
9,296 7,816
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,363 2,449
------- -------
Total property, plant, and equipment, net................... $11,659 $10,265
======= =======
</TABLE>
Additional acquisition cost assigned to utility plant represents the excess
of allocated purchase costs over historical costs of these facilities. These
costs are amortized on a straight-line basis over the remaining lives of the
facilities and we do not recover these excess costs in our rates.
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<PAGE> 61
9. DEBT AND OTHER CREDIT FACILITIES
The average interest rate on our short-term borrowings was 7.4% and 6.6% at
December 31, 2000 and 1999. We had the following short-term borrowings,
including current maturities of long-term debt, at December 31:
<TABLE>
<CAPTION>
2000 1999
------ ------
(IN MILLIONS)
<S> <C> <C>
Short-term credit facility.................................. $ 455 $ --
Commercial paper............................................ 961 1,216
Other credit facilities..................................... 10 35
Current maturities of long-term debt........................ 1,032 92
------ ------
$2,458 $1,343
====== ======
</TABLE>
Our long-term debt outstanding consisted of the following at December 31:
<TABLE>
<CAPTION>
2000 1999
------ ------
(IN MILLIONS)
<S> <C> <C>
Long-term debt
El Paso Corporation
Senior notes, 6.625% through 7.375%, due 2001 through
2012.................................................. $1,700 $1,100
Notes, 6.625% through 9.0%, due 2001 through 2030...... 1,500 1,200
Variable rate senior note due 2001, average interest
for 2000 of 7.11% and 6.35% for 1999.................. 100 100
El Paso Tennessee
Notes, 7.25% through 10.0%, due 2008 through 2025...... 51 51
Debentures, 6.5% through 10.375%, due 2000 through
2005.................................................. 36 42
Tennessee Gas Pipeline
Debentures, 6.0% through 7.625%, due 2011 through
2037.................................................. 1,386 1,386
El Paso Natural Gas
Notes, 6.75% through 7.75%, due 2002 through 2003...... 415 415
Debentures, 7.5% and 8.625%, due 2022 and 2026......... 460 460
Southern Natural Gas
Notes, 6.125% through 8.875%, due 2001 through 2008.... 500 500
EPEC Corporation
Senior Note, 9.625%, due 2001.......................... 13 13
DeepTech International
Senior note, 12.0%, due 2000........................... -- 82
Field Services
Notes, 7.41% through 11.5% due 2001 through 2012....... 511 --
Other..................................................... 1 4
------ ------
6,673 5,353
Less: Unamortized discount................................ 35 38
Current maturities.................................. 1,032 92
------ ------
Long-term debt, less current maturities................... $5,606 $5,223
====== ======
</TABLE>
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<PAGE> 62
Aggregate maturities of the principal amounts of long-term debt for the
next 5 years and in total thereafter are as follows:
<TABLE>
<CAPTION>
(IN MILLIONS)
-------------
<S> <C>
2001........................................................ $1,032
2002........................................................ 520
2003........................................................ 241
2004........................................................ 69
2005........................................................ 289
Thereafter.................................................. 4,522
------
Total long-term debt, including current
maturities....................................... $6,673
======
</TABLE>
Other Financing Arrangements
As of December 31, 2000, we have a $2 billion, 364-day renewable credit and
competitive advance facility and a $1 billion, 3-year revolving credit and
competitive advance facility. These facilities replaced our $1,250 million and
our $750 million revolving credit facilities in August 2000. EPNG and TGP are
also designated borrowers under these facilities. The interest rate for these
facilities varies and was LIBOR plus 50 basis points on December 31, 2000. No
amounts were outstanding under these facilities as of December 31, 2000.
In October 2000, we established a $30 million multi-currency revolving
credit facility. The 364-day facility allows us access to U.S. Dollars, English
Pounds, German Marks, Norwegian Kroner, and Euros. The interest rate for this
facility varies and was LIBOR plus 50 basis points on December 31, 2000. No
amounts were outstanding at December 31, 2000.
In December 2000, we established a $700 million floating rate bridge
facility for use in connection with our acquisition of PG&E's Texas Midstream
operations. As of December 31, 2000, $455 million was outstanding under this
facility. As part of our acquisition, we assumed approximately $527 million in
debt, and in February 2001, we borrowed the balance of this facility and
redeemed $340 million of the debt assumed.
We use a commercial paper program to manage our short-term cash
requirements. Under the program we can borrow up to $1 billion. In addition, TGP
and EPNG have the ability to individually borrow up to $1 billion each.
As of March 2001, TGP has $200 million and SNG has $100 million under shelf
registration statements on file with the Securities and Exchange Commission.
The availability of borrowings under our credit agreements is subject to
specified conditions, which we believe we currently meet. These conditions
include compliance with the financial covenants and ratios required by such
agreements, absence of default under such agreements, and continued accuracy of
the representations and warranties contained in such agreements (including the
absence of any material adverse changes). All of our senior debt issues have
been given investment grade ratings by Standard & Poor's and Moody's.
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<PAGE> 63
Other Financial Activities
Our significant long-term debt issuances and retirements during 2000 and
1999 were as follows:
ISSUANCES
<TABLE>
<CAPTION>
NET
DATE COMPANY TYPE OF ISSUE INTEREST RATE PRINCIPAL PROCEEDS(1) DUE DATE
---- ------- ------------- ------------- --------- ------------ --------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
2000
October El Paso Medium-term notes 8.05% $300 $296 2030
December El Paso Medium-term notes 7.38% 300 298 2012
December El Paso Medium-term notes 6.95% 300 297 2007
1999
May El Paso Senior notes 6.75% $500 $495 2009
July El Paso Senior notes 6.625% 600 596 2001
July El Paso Senior notes Variable 100 100 2001
July Sonat Notes 7.625% 600 590 2011
</TABLE>
- ---------------
(1) Net proceeds were primarily used to repay short-term borrowings and for
general corporate purposes.
RETIREMENTS
<TABLE>
<CAPTION>
DATE COMPANY INTEREST RATE DUE DATE AMOUNT
- ---- ------- ------------- -------- -------------
(IN MILLIONS)
<S> <C> <C> <C> <C>
2000
July DeepTech International 12.00% 2000 $ 82
1999
August Sonat 9.50% 1999 $100
September El Paso Natural Gas 9.45% 1999 47
October Mojave Pipeline Company Variable 1999 107
November Bear Creek Capital Corporation 8.16% 1999 34
</TABLE>
In addition, we established and drew upon a $250 million non-committed line
of credit in January 2000. In March 2000, we repaid this facility.
In May 2000, we issued preferred securities of a consolidated trust, El
Paso Energy Capital Trust IV. Proceeds of approximately $293 million, net of
issuance costs, were used for general corporate purposes. We also received
approximately $984 million from a third-party investor in 2000 as a result of
the sale of a preferred interest in Clydesdale Associates, L.P., a consolidated
joint venture. In 1999, we received net proceeds of $960 million from a
third-party investor as a result of the sale of a preferred interest in Trinity
River Associates, L.L.C., a consolidated joint venture. The proceeds from these
issuances were used to repay short-term debt and for other corporate purposes.
For a further discussion of these transactions, See Note 10, Securities of
Subsidiaries.
In November 2000, we terminated an interest rate swap with a notional
amount of $600 million and a termination date of July 2001. The swap was
originally put into place to swap the 6.625% fixed interest rate on our July
1999, $600 million aggregate principal Senior Notes due 2001 with a variable
interest rate. The termination of the swap did not have a material impact on our
financial results.
In October 1999, Mojave Pipeline Company terminated its associated interest
rate swap at a cost of approximately $5 million.
We also entered into various financing transactions with unconsolidated
affiliates. See Note 17, Investments in Unconsolidated Affiliates, for a further
discussion of these transactions.
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<PAGE> 64
Financing Activities in 2001
In February 2001, SNG issued $300 million aggregate principal amount 7.35%
Notes due 2031. Proceeds of approximately $297 million, net of issuance costs,
were used to pay off $100 million of SNG's 8.875% Notes due 2001, and for
general corporate purposes. Also in February 2001, we issued approximately $1.8
billion zero coupon convertible debentures due 2021, with a yield to maturity of
4%. Proceeds of approximately $784 million, net of issuance costs, were used to
repay short-term borrowings and for general corporate purposes. These debentures
are convertible into 8,456,589 shares of our common stock which is based on a
conversion rate of 4.7872 shares per $1,000 principal amount at maturity. This
rate was equivalent to an initial conversion price of $94.604 per share of our
common stock.
In March 2001, we issued E550 million (approximately $510 million) of euro
notes at 5.75% due 2006. Proceeds of approximately $505 million, net of issuance
costs, were used to repay short-term debt and for general corporate purposes. To
reduce our exposure to foreign currency risk, we entered into a swap transaction
exchanging the euro note for a $510 million U.S. dollar denominated obligation
with a fixed interest rate of 6.61% for the five year term of the note.
10. SECURITIES OF SUBSIDIARIES
Company-obligated Preferred Securities
In March 1998, we formed El Paso Energy Capital Trust I which issued 6.5
million of 4 3/4% trust convertible preferred securities for $325 million ($317
million, net of issuance costs). We own all of the Common Securities of Trust I.
We used the net proceeds from the preferred securities to pay down our
commercial paper. Trust I exists for the sole purpose of issuing preferred
securities and investing the proceeds in 4 3/4% convertible subordinated
debentures due 2028, their sole asset. We guarantee Trust I's preferred
securities. Trust I's preferred securities are reflected as company-obligated
preferred securities of consolidated trusts in our balance sheet. Distributions
paid on the preferred securities are included as minority interest in our income
statement.
Trust I's preferred securities are non-voting (except in limited
circumstances), pay quarterly distributions at an annual rate of 4 3/4%, carry a
liquidation value of $50 per security plus accrued and unpaid distributions and
are convertible into our common shares at any time prior to the close of
business on March 31, 2028, at the option of the holder at a rate of 1.2022
common shares for each Trust I Preferred Security (equivalent to a conversion
price of $41.59 per common share), subject to adjustment in certain
circumstances.
In May 2000, we formed El Paso Energy Capital Trust IV which issued $300
million ($293 million, net of issuance costs) of preferred securities to a third
party investor. These preferred securities pay cash distributions at a floating
rate equal to the three-month LIBOR plus 75 basis points. As of December 31,
2000, the floating rate was 7.49%. These preferred securities must be redeemed
by Trust IV no later than November 30, 2003. Proceeds from the sale of the
securities were used by Trust IV to purchase a series of our floating rate
senior debentures whose yield and maturity terms mirror those of Trust IV's
preferred securities. The sole assets of Trust IV are these floating rate senior
debentures. We guarantee all obligations of Trust IV related to its preferred
securities. At the time Trust IV issued the preferred securities, we also agreed
to issue $300 million of equity securities, including, but not limited to, our
common stock in one or more public offerings prior to May 31, 2003.
Minority Interests
Trinity River. During 1999, we formed Sabine River Investors, L.L.C., a
wholly owned limited liability company, and other separate legal entities, to
generate funds to invest in capital projects and other assets. Through Sabine,
we contributed $250 million of equity capital to Trinity River Associates,
L.L.C., and a third-party investor contributed $980 million. The third-party
investor is entitled to an adjustable preferred return derived from Trinity's
net income. Trinity used the proceeds to invest in a note receivable from Sabine
collateralized by selected assets. We have the option to acquire the
third-party's interest in Trinity at any time prior to June 2004. If we do not
exercise this option or if the agreement is not extended, Trinity's note
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<PAGE> 65
receivable from Sabine will mature and a portion of the proceeds will be used by
Trinity to redeem the third-party interest in Trinity. The assets, liabilities,
and operations of Sabine, Trinity, and other entities involved in the
transaction are included in our consolidated financial statements.
Clydesdale. In May 2000, we formed Clydesdale Associates, L.P., a limited
partnership, and several other separate legal entities to generate funds to
invest in capital projects and other assets. Initially, we contributed $55
million of equity capital into Clydesdale and a third-party investor contributed
$250 million. In December 2000, we contributed an additional $200 million into
Clydesdale and a third-party investor contributed an additional $750 million.
The third-party investor is entitled to an adjustable preferred return derived
from Clydesdale's net income. Clydesdale used the proceeds to invest in a note
receivable with us. The third-party's contributions are collateralized by
production properties, rental income from real estate assets, and notes
receivable from us. We have the option to acquire the third-party's interest in
Clydesdale at any time prior to May 2005. If we do not exercise this option, or
if the agreement is not extended, the note receivable will mature and a portion
of the proceeds will be used to redeem the third-party interest in Clydesdale.
The assets, liabilities, and operations of the entities involved in this
transaction are included in our consolidated financial statements.
Preferred Stock of Subsidiary. In November 1996, El Paso Tennessee
Pipeline Co. issued 6 million shares of 8.25% cumulative preferred stock with a
par value of $50 per share for $296 million (net of issuance costs). The
preferred stock is redeemable, at the option of El Paso Tennessee, after
December 31, 2001, at a redemption price equal to $50 per share, plus dividends
accrued and unpaid up to the date of redemption. During 2000, 1999, and 1998,
dividends of approximately $25 million were paid each year on the preferred
stock.
11. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
On August 19, 2000, a main transmission line owned and operated by EPNG
ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve
individuals at the site were fatally injured. Eleven lawsuits brought on behalf
of the twelve deceased persons have been filed against EPNG and EPEC for damages
for personal injuries and wrongful death -- three in state district court in
Harris County, Texas (Diane Heady, et al v. EPEC and EPNG, filed September 7,
2000; Richard Heady v. EPEC and EPNG, filed February 15, 2001; Geneva Smith v.
EPEC and EPNG, filed October 23, 2000), two in federal district court in
Albuquerque, New Mexico (Dawson v. EPEC and EPNG, filed November 8, 2000;
Jennifer Smith v. EPEC and EPNG, filed August 29, 2000), and six in state
district court in Carlsbad, New Mexico (Chapman, as Personal Representative of
the Estate of Amy Smith Heady, v. EPEC, EPNG, and John Cole, filed February 9,
2001; and Chapman v. EPEC, EPNG and John Cole; Green v. EPEC, EPNG, and John
Cole; Rackley, as Personal Representative of the Estate of Glenda Gail Sumler,
v. EPEC, EPNG, and John Cole; and Rackley, as Personal Representative of the
Estate of Amanda Sumler Smith, v. EPEC, EPNG, and John Cole, all filed March 16,
2001). In March 2001, we settled all claims in the Heady cases. Payments for
these four claimants will be fully covered by insurance. The National
Transportation Safety Board is conducting an investigation into the facts and
circumstances concerning the possible causes of the rupture.
In August 2000, the Liquidating Trustee in the bankruptcy of Power
Corporation of America (PCA) sued El Paso Merchant Energy, and several other
power traders, in the U.S. Bankruptcy Court in Connecticut, claiming El Paso
Merchant Energy improperly cancelled its contracts with PCA during the summer of
1998. The trustee alleges we breached contracts damaging PCA in the amount of
$120 million. We have entered into a joint defense agreement with the other
defendants. This matter will be mediated in the second quarter of 2001. In a
related matter, PCA appealed the FERC's ruling that power marketers such as EPME
did not have to give 60 days notice to cancel its power contracts under the
Federal Power Act. PCA has appealed this decision to the United States Court of
Appeals. Oral arguments were heard in January 2001 and we are awaiting the
Court's decision.
In late 2000, we and several of our subsidiaries, including El Paso Natural
Gas Company and El Paso Merchant Energy, were named as defendants in four
purported class action lawsuits filed in state court in
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<PAGE> 66
California. (Continental Forge Co. v. Southern California Gas Co., et al, Los
Angeles; Berg v. Southern California Gas Co., et al, Los Angeles; John Phillip
v. El Paso Merchant Energy, et al, San Diego; John WHK Phillip v. El Paso
Merchant Energy, et al, San Diego.) Two of these cases, filed in Los Angeles,
contend generally that our entities conspired with other unrelated companies to
create artificially high prices for natural gas in California; the other two
cases, filed in San Diego, assert that our companies used Merchant Energy's
acquisition of capacity on the EPNG pipeline to manipulate the market for
natural gas in California. We have remanded each of these cases to the federal
courts in California and have filed motions to dismiss in the San Diego actions.
On March 20, 2001, two additional lawsuits, The City of Los Angeles, et. al. v.
Southern California Gas Company, et. al. and The City of Long Beach, et. al. v.
Southern California Gas Company et. al. were filed in a Los Angeles County
Superior Court. These cases seek monetary damages against us and several of our
subsidiaries and make similar allegations to the Continental Forge and Berg
cases discussed above.
In 1999, a number of our subsidiaries were named defendants in actions
brought by Jack Grynberg on behalf of the U.S. Government under the False Claims
Act. Generally, these complaints allege an industry-wide conspiracy to under
report the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. These matters have been consolidated for pretrial purposes. (In re:
Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming.)
A number of our subsidiaries are named defendants in an action styled
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint, once transferred to the same court handling the Grynberg
complaint, has been sent back to the Kansas State Court for further proceedings.
In February 1998, the United States and the State of Texas filed in a U.S.
District Court a Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) cost recovery action against fourteen companies,
including some of our current and former affiliates, related to the Sikes
Disposal Pits Superfund Site located in Harris County, Texas. The suit claims
that the United States and the State of Texas have spent over $125 million in
remediating Sikes, and seeks to recover that amount plus interest from the
defendants to the suit. The EPA has recently indicated that it may seek an
additional amount up to $30 million plus interest in indirect costs from the
defendants under a new cost allocation methodology. Defendants are challenging
this allocation policy. Although an investigation relating to Sikes is ongoing,
we believe that the amount of material, if any, disposed at Sikes by our former
affiliates was small, possibly de minimis. However, the plaintiffs have alleged
that the defendants are each jointly and severally liable for the entire
remediation costs and have also sought a declaration of liability for future
response costs such as groundwater monitoring.
TGP is a party in proceedings involving federal and state authorities
regarding the past use of a lubricant containing polychlorinated biphenyls
(PCBs) in its starting air systems. TGP has executed a consent order with the
EPA governing the remediation of some compressor stations and is working with
the EPA and the relevant states regarding those remediation activities. TGP is
also working with the Pennsylvania and New York environmental agencies regarding
remediation and post-remediation activities at the Pennsylvania and New York
stations.
In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court alleging that TGP discharged pollutants into the waters of
the state and disposed of PCBs without a permit. The agency sought an injunction
against future discharges, an order to remediate or remove PCBs, and a civil
penalty. TGP entered into agreed orders with the agency to resolve many of the
issues raised in the original allegations, received water discharge permits from
the agency for its Kentucky compressor stations, and continues to work to
resolve the remaining issues. The relevant Kentucky compressor stations are
being characterized and remediated under a consent order with the EPA.
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<PAGE> 67
We are also a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of our
business.
While the outcome of the matters discussed above cannot be predicted with
certainty, we do not expect the ultimate resolution of these matters will have a
material adverse effect on our financial position, operating results, or cash
flows.
Environmental
We are subject to extensive federal, state, and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of December 31, 2000, we had a reserve of approximately $274 million
for expected remediation costs, including approximately $257 million for
associated onsite, offsite and groundwater technical studies, and approximately
$17 million for other costs which we anticipate incurring through 2027. In
addition, we expect to make capital expenditures for environmental matters of
approximately $103 million in the aggregate for the years 2001 through 2007.
These expenditures primarily relate to compliance with air regulations.
Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances, including those on the EPA
List of Hazardous Substances, at compressor stations and other facilities it
operates. While conducting this project, TGP has been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders, to ensure that its efforts meet regulatory
requirements.
In May 1995, following negotiations with its customers, TGP filed a
Stipulation and Agreement (the Environmental Stipulation) with FERC that
established a mechanism for recovering a substantial portion of the
environmental costs identified in its internal project. The Environmental
Stipulation was effective July 1, 1995, and as of December 31, 1999, all amounts
have been collected from customers. Refunds may be required to the extent actual
eligible expenditures are less than amounts collected.
We have been designated and have received notice that we could be
designated, or have been asked for information to determine whether we could be
designated as a Potentially Responsible Party (PRP) with respect to 29 sites
under the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund) or state equivalents. We sought to resolve our liability
as a PRP at these Superfund sites through indemnification by third parties
and/or settlements which provide for payment of our allocable share of
remediation costs. As of December 31, 2000, we have estimated our share of the
remediation costs at these sites to be between $59 million and $194 million and
have provided reserves that we believe are adequate for such costs. Since the
clean-up costs are estimates and are subject to revision as more information
becomes available about the extent of remediation required, and because in some
cases we have asserted a defense to any liability, our estimates could change.
Moreover, liability under the federal Superfund statute is joint and several,
meaning that we could be required to pay in excess of our pro rata share of
remediation costs. Our understanding of the financial strength of other PRPs has
been considered, where appropriate, in the determination of our estimated
liabilities. We presently believe that the costs associated with these Superfund
sites will not have a material adverse effect on our financial position,
operating results, or cash flows.
It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations, and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe the recorded
reserves are adequate. For a further discussion of specific environmental
matters, see Legal Proceedings above.
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<PAGE> 68
Rates and Regulatory Matters
In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint alleging that El Paso Natural Gas' sale of capacity to Merchant Energy
was anti-competitive and an abuse of the affiliate relationship under FERC's
policies. The CPUC served data requests to us, which have been either
substantially answered or contested. In August 2000, the CPUC filed a motion
requesting that the contract between EPNG and Merchant Energy be terminated.
Other parties in the proceedings have requested that the original complaint be
set for hearings and that Merchant Energy pay back any profits it has earned
under the contract. The matter is pending at FERC.
In February 2001, EPNG completed its open season on 1,221 MMcf/d of
capacity held by Merchant Energy through May 2001 and all the capacity was
re-subscribed. Contracts were awarded to 30 different entities, including 271
MMcf/d to Merchant Energy, all at published tariff rates under contracts with
durations from 17 months to 15 years.
While we cannot predict with certainty the final outcome or the timing of
the resolution of all of our rates and regulatory matters, we believe the
ultimate resolution of these issues will not have a material adverse effect on
our financial position, results of operations, or cash flows.
Capital Commitments and Purchase Obligations
At December 31, 2000, we had capital and investment commitments of $1.2
billion primarily relating to our production, pipeline, and international power
activities. Our other planned capital and investment projects are discretionary
in nature, with no substantial capital commitments made in advance of the actual
expenditures. In connection with the financing commitments on one of our joint
ventures, TGP has entered into unconditional purchase obligations for products
and services totaling $122 million at December 31, 2000. TGP's annual
obligations under these agreements are $21 million for the years 2001, 2002,
2003, 2004 and 2005, and $17 million in total thereafter.
Operating Leases
We lease property, facilities and equipment under various operating leases.
In 1995, El Paso New Chaco Company (EPNC) entered into an unconditional lease
for the Chaco Plant. The lease term expires in 2002, at which time EPNC has an
option, and an obligation upon the occurrence of various events, to purchase the
plant for a price sufficient to pay the amount of the $77 million construction
financing, plus interest and other expenses. If EPNC does not purchase the plant
at the end of the lease term, it has an obligation to pay a residual guaranty
amount equal to approximately 87 percent of the amount financed, plus interest.
We unconditionally guaranteed all obligations of EPNC under this lease.
Minimum annual rental commitments at December 31, 2000, were as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
<S> <C>
2001..................................................... $ 41
2002..................................................... 34
2003..................................................... 27
2004..................................................... 26
2005..................................................... 27
Thereafter............................................... 59
----
Total............................................. $214
====
</TABLE>
Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $14 million due in the future under noncancelable
subleases.
66
<PAGE> 69
Rental expense on our operating leases for the years ended December 31,
2000, 1999, and 1998 was $58 million, $37 million, and $39 million.
Guarantees
At December 31, 2000, we had parental guarantees of approximately $2
billion in connection with our international development activities and various
other projects, including approximately $1 billion associated with our
investments in unconsolidated affiliates as discussed in Note 17. We believe
that these parties will be able to perform under the guaranteed transactions,
that no payments will be required or losses incurred by us under these
guarantees. We also had outstanding letters of credit of approximately $233
million at December 31, 2000. At December 31, 1999, parental guarantees totaled
approximately $1 billion and outstanding letters of credit were $170 million.
12. RETIREMENT BENEFITS
Pension Benefits
Prior to January 1, 1997, we maintained a defined benefit pension plan that
covered substantially all of our employees. Pension benefits were based on years
of credited service and final five year average compensation, subject to maximum
limitations as defined in that plan. Effective January 1, 1997, the plan was
amended to provide benefits determined by a cash balance formula and to include
employees added as a result of our merger with El Paso Tennessee and other
acquisitions prior to 1997. Employees who were pension plan participants on
December 31, 1996, receive the greater of cash balance benefits or prior plan
benefits accrued through December 31, 2001.
Following our merger with Sonat, we offered an early retirement incentive
program to Sonat employees who were at least 50 years of age with 10 years of
service as of December 31, 1999, and who terminated employment by June 30, 2000.
Total charges as a result of the early retirement program were approximately $8
million.
Effective January 1, 2000, the Sonat pension plan was merged into our
pension plan. Sonat employees who were participants in the Sonat pension plan on
the Sonat merger effective date receive the greater of cash balance benefits or
the Sonat plan benefits accrued through December 31, 2004.
Other Postretirement Benefits
We provide postretirement medical benefits for certain closed groups of
retired employees of EPNG, El Paso Tennessee, and Sonat, and limited
postretirement life insurance benefits for current and retired employees. Other
postretirement employee benefits (OPEB) are prefunded to the extent such costs
are recoverable through rates.
Under our early retirement incentive program for Sonat employees and
employees of PG&E's Texas Midstream operations, participating eligible employees
were allowed to keep postretirement medical and life benefits commencing at the
later of age 55 or retirement. Total charges associated with the Sonat incentive
program and the elimination of retiree benefits for future retirees were $29
million and were accrued as of December 31, 1999. The total liabilities for the
PG&E group were $8 million and were accrued as of December 31, 2000. Medical
benefits for these closed groups of retirees may be subject to deductibles,
co-payment provisions, and other limitations and dollar caps on the amount of
employer costs. We have reserved the right to change these benefits.
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<PAGE> 70
The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for pension benefits and other postretirement benefits as of and
for the twelve month period ended September 30:
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
2000 1999 2000 1999
------- ------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning of period................. $ 859 $ 953 $ 489 $ 494
Service cost.............................................. 18 21 -- 2
Interest cost............................................. 62 57 35 33
Participant contributions................................. -- -- 10 8
Plan amendments........................................... -- (18) -- (13)
Settlements, curtailments and special termination
benefits............................................... -- 3 -- 6
Acquisition of PG&E's Texas Midstream operations.......... -- -- 8 --
Actuarial (gain) or loss.................................. 6 (92) (22) 24
Benefits paid............................................. (94) (65) (64) (65)
------ ------ ----- -----
Benefit obligation at end of period....................... $ 851 $ 859 $ 456 $ 489
====== ====== ===== =====
Change in plan assets
Fair value of plan assets at beginning of period.......... $1,158 $1,126 $ 126 $ 112
Actual return on plan assets.............................. 128 90 11 9
Employer contributions.................................... 23 7 70 62
Participant contributions................................. -- -- 10 8
Benefits paid............................................. (94) (65) (64) (65)
------ ------ ----- -----
Fair value of plan assets at end of period................ $1,215 $1,158 $ 153 $ 126
====== ====== ===== =====
Reconciliation of funded status
Funded status at end of period............................ $ 364 $ 299 $(303) $(363)
Fourth quarter contributions and income................... 2 31 16 15
Unrecognized net actuarial gain........................... (232) (246) (28) (3)
Unrecognized net transition obligation.................... (1) -- 39 46
Unrecognized prior service cost........................... (42) (46) (10) (11)
------ ------ ----- -----
Prepaid (accrued) benefit cost at December 31,............ $ 91 $ 38 $(286) $(316)
====== ====== ===== =====
</TABLE>
Included in the pension benefits information are plans in which the
projected benefit obligation and accumulated benefit obligation for pension
plans with accumulated benefit obligations in excess of plan assets were $37
million and $31 million as of December 31, 2000, and $57 million and $53 million
as of December 31, 1999.
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<PAGE> 71
The current liability portion of the postretirement benefits was $46
million as of December 31, 2000 and 1999, respectively. Benefit obligations are
based upon actuarial estimates as described below.
<TABLE>
<CAPTION>
PENSION BENEFITS POSTRETIREMENT BENEFITS
-------------------- ------------------------
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2000 1999 1998 2000 1999 1998
----- ----- ---- ------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Benefit cost for the plans includes the following
components
Service cost.................................... $ 18 $ 23 $ 22 $ -- $ 2 $ 2
Interest cost................................... 62 65 64 35 33 33
Expected return on plan assets.................. (113) (104) (96) (7) (8) (6)
Amortization of net actuarial gain.............. (10) (2) (2) -- (1) (2)
Amortization of transition obligation........... 2 2 -- 7 10 11
Amortization of prior service cost.............. (4) (2) (2) (1) (1) (1)
Settlements, curtailment, and special
termination benefits......................... -- 1 (1) -- 29 6
----- ----- ---- ---- --- ---
Net benefit cost................................ $ (45) $ (17) $(15) $ 34 $64 $43
===== ===== ==== ==== === ===
</TABLE>
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
---------------- ---------------
2000 1999 2000 1999
------ ----- ----- -----
<S> <C> <C> <C> <C>
Weighted average assumptions
Discount rate........................................... 7.75% 7.50% 7.75% 7.50%
Expected return on plan assets.......................... 10.00% 9.98% 7.50% 7.50%
Rate of compensation increase........................... 4.50% 4.64% N/A N/A
</TABLE>
Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 10 percent in 2000, gradually decreasing to 6 percent by
the year 2008. Assumed health care cost trends have a significant effect on the
amounts reported for other postretirement benefit plans. A one-percentage point
change in assumed health care cost trends would have the following effects:
<TABLE>
<CAPTION>
2000 1999
----- -----
(IN MILLIONS)
<S> <C> <C>
One Percentage Point Increase
Aggregate of Service Cost and Interest Cost............... $ 1 $ 2
Accumulated Postretirement Benefit Obligation............. $ 19 $ 23
One Percentage Point Decrease
Aggregate of Service Cost and Interest Cost............... $ (1) $ (2)
Accumulated Postretirement Benefit Obligation............. $(18) $(21)
</TABLE>
Retirement Savings Plan
We maintain a defined contribution plan covering all of our employees. We
match 75 percent of participant basic contributions of up to 6 percent, with the
matching contribution being made in our stock. Prior to our Sonat merger, Sonat
matched 100 percent of participant basic contributions of up to 6 percent.
Amounts expensed under the plan were approximately $14 million, $16 million and
$16 million for the years ended December 31, 2000, 1999, and 1998, respectively.
13. CAPITAL STOCK
We have 50,000,000 shares of authorized preferred stock, par value $0.01
per share, none of which have been issued, but of which 7,500,000 shares have
been designated as Series A Junior Participating Preferred Stock and reserved
for issuance pursuant to our preferred stock purchase rights plan.
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<PAGE> 72
14. STOCK-BASED COMPENSATION
During 2000, 1999, and 1998, we granted stock options under various stock
option plans. We account for these plans using Accounting Principles Board
Opinion No. 25 and its related Interpretations. In 1995, the Financial
Accounting Standards Board issued SFAS No. 123, Accounting for Stock-Based
Compensation which, if fully adopted, changes the methods companies use in
determining expense related to their stock option plans. Adoption of the expense
recognition provisions of SFAS No. 123 was optional and we elected not to apply
its provisions. However, we are required to present the following pro forma
disclosures as if we had adopted SFAS No. 123.
Under our existing stock option plans, we are authorized to issue shares of
common stock to employees and non-employee directors pursuant to awards granted
as incentive stock options (intended to qualify under Section 422 of the
Internal Revenue Code), non-qualified stock options, restricted stock, stock
appreciation rights (SARs), phantom stock options, and performance units. We
have reserved approximately 53 million shares of common stock for issuance
pursuant to existing and future stock awards. As of December 31, 2000,
approximately 27 million shares remained unissued.
Non-qualified Stock Options
We granted non-qualified stock options to our employees in 2000, 1999, and
1998. These stock options have contractual terms of 10 years and generally vest
after completion of one to five years of continuous employment from the grant
date. We also granted options to non-employee members of the Board of Directors
at fair market value on the grant date that are exercisable immediately. Under
the terms of certain plans, we may grant SARs to certain holders of stock
options. SARs are subject to the same terms and conditions as the related stock
options. As of December 31, 2000, we have no SARs outstanding.
A summary of the status of our stock options as of December 31, 2000, 1999,
and 1998 is presented below:
<TABLE>
<CAPTION>
STOCK OPTIONS
------------------------------------------------------------------------
2000 1999 1998
---------------------- ---------------------- ----------------------
WEIGHTED WEIGHTED WEIGHTED
# SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE
UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE
OPTIONS PRICES OPTIONS PRICES OPTIONS PRICES
----------- -------- ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the
year............................ 22,511,704 $32.80 15,331,658 $25.46 13,198,433 $22.86
Granted......................... 1,065,110 $41.35 9,639,750 $41.02 3,651,550 $32.34
Exercised....................... 3,648,752 $25.99 2,092,953 $18.26 1,262,775 $17.77
Forfeited....................... 263,911 $38.44 366,751 $31.15 255,550 $27.99
---------- ---------- ----------
Outstanding at end of year........ 19,664,151 $34.43 22,511,704 $32.80 15,331,658 $25.46
========== ========== ==========
Exercisable at end of year........ 12,431,102 $30.51 12,996,454 $26.71 8,486,647 $22.35
========== ========== ==========
</TABLE>
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions:
<TABLE>
<CAPTION>
ASSUMPTION: 2000 1999 1998
----------- ---- ---- ----
<S> <C> <C> <C>
Expected Term in Years...................................... 7 7 5
Expected Volatility......................................... 23.9% 21.9% 20.3%
Expected Dividends.......................................... 3.0% 3.0% 3.0%
Risk-Free Interest Rate..................................... 5.0% 6.3% 4.6%
</TABLE>
The Black-Scholes weighted average fair value of options granted during
2000, 1999 and 1998 was $10.16, $11.42, and $7.00, respectively.
70
<PAGE> 73
Options outstanding as of December 31, 2000 are summarized below:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- -----------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE
EXERCISE PRICES AT 12/31/00 CONTRACTUAL LIFE EXERCISE PRICE AT 12/31/00 EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 7.15 to $21.40 3,468,451 3.6 $15.93 3,468,451 $15.93
$21.41 to $35.70 5,119,933 6.2 $30.32 4,644,633 $29.90
$35.71 to $42.90 9,531,247 8.7 $41.08 2,980,798 $41.01
$42.91 to $71.50 1,544,520 6.9 $48.61 1,337,220 $47.02
---------- ----------
$ 7.15 to $71.50 19,664,151 7.0 $34.43 12,431,102 $30.51
========== ==========
</TABLE>
Pro Forma Net Income and Net Income Per Common Share
Had the compensation expense for our stock-based compensation plans been
determined applying the provisions of SFAS No. 123, our net income and net
income per common share for 2000, 1999, and 1998 would approximate the pro forma
amounts below:
<TABLE>
<CAPTION>
DECEMBER 31, 2000 DECEMBER 31, 1999 DECEMBER 31, 1998
----------------------- ----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
SFAS No. 123 charge, pretax..... $ -- $ 95 $ -- $ 160 $ -- $ 63
APB No. 25 charge, pretax....... $ 38 $ -- $ 145 $ -- $ 51 $ --
Net income (loss)............... $ 652 $ 614 $ (255) $ (267) $ (306) $ (313)
Basic earnings (loss) per common
share......................... $2.83 $2.66 $(1.12) $(1.17) $(1.35) $(1.39)
Diluted earnings (loss) per
common share.................. $2.73 $2.57 $(1.12) $(1.17) $(1.35) $(1.39)
</TABLE>
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards granted
prior to the 1995 fiscal year.
Restricted Stock
Under our various stock-based compensation plans, a limited number of
shares of restricted common stock may be granted at no cost to certain key
officers and employees. These shares carry voting and dividend rights; however,
sale or transfer of the shares is restricted. These restricted stock awards vest
over a specific period of time and/or if we achieve certain performance targets.
Restricted stock awards representing 0.4 million, 1.4 million, and 0.6 million
shares were granted during 2000, 1999, and 1998, respectively, with a weighted
average grant date fair value of $34.82, $35.10, and $32.40 per share,
respectively. At December 31, 2000, 1.5 million shares of restricted stock were
outstanding. The value of these shares is determined based on the fair market
value on the date performance targets are achieved, and this value is charged to
compensation expense ratably over the required service or restriction period.
For 2000, 1999, and 1998, these charges totaled $13 million, $69 million, and
$29 million. Included in deferred compensation at December 31, 2000, is $69
million related to options that will be converted at the holders election into
common stock at the end of their vesting period. These options met all
performance targets in December 2000.
Performance Units and Phantom Stock Options
We award eligible employees phantom stock options that are payable in cash.
We also award eligible employees and officers performance units that are payable
in cash or stock at the end of the vesting period. The final value of the
performance units may vary according to the plan under which they are granted,
but is usually based on our common stock price at the end of the vesting period.
The value of the performance units is charged ratably to compensation expense
over the vesting period with periodic adjustments to account for the fluctuation
in the market price of our stock. Amounts charged to compensation expense in
2000, 1999, and 1998 were $25 million, $30 million, and $13 million. Included in
the 1999 amount is $22 million related to the
71
<PAGE> 74
accelerated vesting of the performance units due to the change in control
resulting from the merger with Sonat. In March 2001, we paid our phantom stock
options, resulting in a charge of $51 million.
Employee Stock Purchase Program
In October 1999, we implemented an employee stock purchase plan under
Section 423 of the Internal Revenue Code. The plan allows participating
employees the right to purchase common stock on a quarterly basis at 85 percent
of the lower of the market price at the beginning of the plan period or at the
end of each calendar quarter. Two million shares of common stock are authorized
for issuance under this plan. We issued 346,332 shares at $32.33 per share in
2000, and 139,842 shares at $33.10 per share in 1999. Funds we receive may be
used for general corporate purposes. However, we record a liability for the
withholdings not yet applied towards the purchase of common stock. We bear all
expenses associated with administering the plan, except for costs, including any
applicable taxes, associated with the participants' sale of common stock.
15. SEGMENT INFORMATION
Our business activities are segregated into four segments: Pipelines,
Merchant Energy, Field Services, and Production. These segments are strategic
business units that offer a variety of different energy products and services.
We manage each segment separately as each business requires different technology
and marketing strategies. During 2000, we combined our International and
Merchant Energy segments to reflect the ongoing globalization of Merchant
Energy's strategy and its operating activities. All prior periods have been
restated to reflect the current year presentation.
Our Pipeline segment provides natural gas transmission services in the U.S.
We conduct our activities through five wholly owned and two partially owned
interstate systems along with a liquified natural gas terminalling facility and
various natural gas storage facilities.
Our Merchant Energy segment is involved in a broad range of activities in
the energy marketplace, including asset ownership, trading and risk management
and financial services. We buy, sell, and trade natural gas, power, crude oil,
refined products, coal and other energy commodities throughout the world, and
own or have interests in 64 power generation plants in 16 countries.
Our Field Services segment provides natural gas gathering, storage,
products extraction, fractionation, dehydration, purification, compression and
intrastate transmission services. Field Services' assets are located in some of
the most prolific and active production areas in the U.S., including the San
Juan Basin, east and south Texas, Louisiana and the Gulf of Mexico.
Our Production segment is engaged in the exploration for and the
acquisition, development, and production of natural gas, oil and natural gas
liquids in the major producing basins of the United States. Production has
onshore and coal seam operations and properties in 11 states and offshore
operations and properties in federal and state waters in the Gulf of Mexico. We
also have exploration and production rights in Turkey.
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<PAGE> 75
The accounting policies of the individual segments are the same as those
described in Note 1. Since earnings on equity investments can be a significant
component of earnings in several of our segments, we evaluate segment
performance based on earnings before interest and taxes (EBIT) instead of
operating income. To the extent practicable, results of operations for the years
ended December 31, 1999 and 1998 have been reclassified to conform to the
current business segment presentation, although such results are not necessarily
indicative of the results which would have been achieved had the revised
business segment structure been in effect during that period.
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000
-----------------------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES PRODUCTION OTHER(1) TOTAL
--------- -------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic................................. $1,549 $18,464 $ 598 $ 298 $ 3 $20,912
Foreign.................................. -- 1,038 -- -- -- 1,038
Intersegment revenue....................... 148 19 85 224 (476) --
Merger-related costs and asset impairment
charges.................................. -- -- 11 80 91
Depreciation, depletion, and
amortization............................. 244 27 67 212 39 589
Operating income (loss).................... 754 433 76 196 (128) 1,331
Other income (loss)........................ 68 130 26 -- (5) 219
Earnings (loss) before interest and
taxes.................................... 822 563 102 196 (133) 1,550
Extraordinary items, net of income taxes... 89 -- (19) -- -- 70
Assets
Domestic................................. 8,833 9,758 3,241 1,819 1,862 25,513
Foreign.................................. -- 1,932 -- -- -- 1,932
Capital expenditures and investments in
unconsolidated affiliates................ 493 941 439 484 1,059 3,416
Total investments in unconsolidated
affiliates............................... 510 1,910 374 7 57 2,858
</TABLE>
- ---------------
(1) Includes Corporate and eliminations as well as telecommunications which has
not had significant activity.
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
-----------------------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES PRODUCTION OTHER(1) TOTAL
--------- -------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic................................. $1,720 $7,893 $ 388 $ 108 $ 9 $10,118
Foreign.................................. -- 591 -- -- -- 591
Intersegment revenue....................... 51 36 78 365 (530) --
Merger-related costs and asset impairment
charges.................................. 90 67 8 31 361 557
Ceiling test charges....................... -- -- -- 352 -- 352
Depreciation, depletion, and
amortization............................. 275 47 60 210 16 608
Operating income (loss).................... 668 (91) 38 (258) (390) (33)
Other income............................... 51 94 47 1 31 224
Earnings (loss) before interest and
taxes.................................... 719 3 85 (257) (359) 191
Assets
Domestic................................. 8,919 2,103 1,457 1,393 1,459 15,331
Foreign.................................. -- 1,336 -- -- -- 1,336
Capital expenditures and investments in
unconsolidated affiliates................ 455 1,239 121 365 30 2,210
Total investments in unconsolidated
affiliates............................... 618 1,274 266 6 13 2,177
</TABLE>
- ---------------
(1) Includes Corporate and eliminations.
73
<PAGE> 76
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
-----------------------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES PRODUCTION OTHER(1) TOTAL
--------- -------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic................................. $1,608 $7,181 $ 212 $ 174 4 $ 9,179
Foreign.................................. -- 381 -- -- 381
Intersegment revenue....................... 88 22 65 361 (536) --
Merger-related costs and asset impairment
charges.................................. -- -- -- 15 -- 15
Ceiling test charges....................... -- -- -- 1,035 -- 1,035
Depreciation, depletion, and
amortization............................. 255 17 49 292 11 624
Operating income (loss).................... 752 (37) 62 (939) (73) (235)
Other income............................... 59 65 14 3 42 183
Earnings (loss) before interest and
taxes.................................... 811 28 76 (936) (31) (52)
Assets
Domestic................................. 8,659 1,564 1,461 1,544 573 13,801
Foreign.................................. -- 654 -- -- -- 654
Capital expenditures and investments in
unconsolidated affiliates................ 401 582 453 581 22 2,039
Total investments in unconsolidated
affiliates............................... 517 480 87 6 14 1,104
</TABLE>
- ---------------
(1) Includes Corporate and eliminations.
The reconciliations of EBIT to income (loss) before extraordinary items and
the cumulative effect of accounting change are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
----------------------
2000 1999 1998
------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Total EBIT for segments..................................... $1,550 $ 191 $ (52)
Interest and debt expense................................... 538 453 387
Minority interest........................................... 144 61 37
Income tax expense (benefit)................................ 286 (81) (170)
------ ----- -----
Income (loss) before extraordinary items and
cumulative effect of accounting change.......... $ 582 $(242) $(306)
====== ===== =====
</TABLE>
Prior to the current year, we had no customers whose revenues exceeded 10
percent of our total revenues. In 2000, Merchant Energy had revenues of $2.1
billion from subsidiaries of Enron Corp. We did not have revenues in excess of
10 percent with any other customer in 2000.
16. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
<TABLE>
<CAPTION>
2000 1999 1998
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Interest paid............................................... $591 $421 $386
Income tax payments (refunds)............................... 29 9 (86)
</TABLE>
See Notes 2 and 17, for a discussion of the non-cash investing transactions
related to our acquisitions.
74
<PAGE> 77
17. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES (UNAUDITED)
We hold investments in various unconsolidated affiliates which are
accounted for using the equity method of accounting. Our principal equity method
investees are international pipelines, interstate pipelines, power generation
plants, and gathering systems. Our investment balance includes unamortized
purchase price differences of $415 million and $105 million as of December 31,
2000 and 1999, that are being amortized over the remaining life of the
unconsolidated affiliate's underlying assets. Our investments in and advances to
our unconsolidated affiliates are as follows:
<TABLE>
<CAPTION>
NET
OWNERSHIP YEAR ENDED
INTEREST DECEMBER 31,
DECEMBER 31, ----------------
2000 2000 1999
------------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Bolivia to Brazil Pipeline........................... 8% $ 53 $ 45
CAPSA/CAPEX.......................................... 45% 282 145
CE Generation........................................ 50% 354 334
Chaparral............................................ 20% 268 373
Citrus Corporation................................... 50% 474 422
East Asia Power...................................... 46% 118 144
Energy Partners...................................... 30% 368 280
Korea Independent Energy Corporation................. 50% 108 --
Photon Investors..................................... 42% 136 --
Porto Velho.......................................... 50% 99 --
Samalayuca Power..................................... 40% 93 130
Other................................................ various 562 564
------ ------
$2,915 $2,437
====== ======
</TABLE>
Our equity earnings (losses) from our unconsolidated affiliates are as
follows:
<TABLE>
<CAPTION>
2000 1999 1998
---- ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Bolivia to Brazil Pipeline................................. $ -- $ 4 $ --
CAPSA/CAPEX................................................ 4 3 --
CE Generation.............................................. 35 24 --
Chaparral.................................................. (5) (8) --
Citrus Corporation......................................... 51 25 24
East Asia Power............................................ (32) -- --
Energy Partners............................................ 20 18 1
Porto Velho................................................ 1 -- --
Samalayuca Power........................................... 17 17 11
Other...................................................... 36 12 37
==== ====== ======
$127 $ 95 $ 73
==== ====== ======
</TABLE>
Summarized financial information of our proportionate share of our
unconsolidated affiliates is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
2000 1999 1998
------- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating results data:
Revenues and other income................................. $1,118 $930 $579
Costs and expenses........................................ 952 814 492
Income from continuing operations......................... 166 116 87
Net income................................................ 127 95 73
</TABLE>
75
<PAGE> 78
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
2000 1999
------ ------
(IN MILLIONS)
<S> <C> <C>
Financial position data:
Current assets............................................ $1,064 $ 589
Non-current assets........................................ 7,812 5,197
Short-term debt........................................... 311 249
Other current liabilities................................. 635 321
Long-term debt............................................ 2,676 2,505
Other non-current liabilities............................. 2,922 608
Minority interest......................................... 36 9
Equity in net assets...................................... 2,296 2,094
</TABLE>
The following table shows revenues and charges from our unconsolidated
affiliates:
<TABLE>
<CAPTION>
2000 1999 1998
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Natural gas sales........................................... $104 -- --
Power purchases............................................. 43 -- --
Management fee income....................................... 81 20 --
Reimbursement for costs..................................... 44 17 4
Interest income............................................. 10 5 --
Interest expense............................................ 49 2 --
</TABLE>
Chaparral Investors
During 1999, we contributed approximately $120 million of equity capital
and assets to a newly formed limited liability company, Chaparral. A third-party
financial investor contributed approximately $123 million on which they earn a
preferred return. In connection with this transaction, Chaparral formed a wholly
owned subsidiary, Mesquite. Merchant Energy manages both Chaparral and Mesquite.
In January 2000, we acquired an additional interest in Chaparral in exchange for
a $160 million contingent interest promissory note. The maturity date of the
note is the earlier of December 2019, or upon the occurrence of events specified
in the note. The note carries a variable interest rate not to exceed 12.75
percent. At December 31, 1999, we had a note payable of $121 million to
Chaparral which was payable upon demand and carried a variable interest rate
which was 6.4%. This note was repaid in 2000. We also had a note receivable from
Mesquite which had a balance of $262 million at December 31, 1999. This note was
payable on demand and had a variable rate which was 8.3%. This note was repaid
by Mesquite in 2000. During 2000, we issued a note payable to Mesquite. The note
is payable on demand and had a balance of $241 million at a rate of 7.3% as of
December 31, 2000.
During the first quarter of 2000, Chaparral completed its acquisitions of
several domestic non-utility generation assets including equity interests in
eleven natural gas-fired combined generation facilities in California, two
natural gas-fired electric generation plants located in Dartmouth, Massachusetts
and Pawtucket, Rhode Island, and all the outstanding shares of Bonneville
Pacific Corporation, which owns a 50 percent interest in a power generation
facility. Chaparral also acquired several operating companies which provide the
services required to operate and maintain these newly acquired facilities and a
natural gas service company which provides fuel procurement services to eight of
Chaparral's natural gas-fired combined generation facilities in California.
Chaparral acquired these assets from us in exchange for notes payable in the
amount of $385 million. In March 2000, Chaparral's third-party investor
increased its overall investment in Chaparral by $1,027 million. The proceeds
were used by Chaparral to repay $647 million of notes from us, to make a $278
million contribution to a trust as provided in the Chaparral agreement, to
invest in a note with us, and to fund transaction costs. Also, in March 2000, we
issued mandatorily convertible preferred stock to a trust we control. Upon the
occurrence of certain negative events, the trustee of the trust may be required
to remarket this preferred stock on terms that are designed to generate $1
billion to distribute to the third party investor.
76
<PAGE> 79
Under our management agreement with Chaparral, we earn a performance based
management fee. We are also reimbursed for expenses we incur on behalf of
Chaparral. For 2000, our management fee related to Chaparral was $100 million
and this fee included an $80 million performance-based component and a $20
million reimbursement for costs we incurred on behalf of Chaparral. This fee was
collected and recognized ratably throughout the year as management services were
provided.
We also sell natural gas and buy power from qualifying power facilities
owned by Chaparral.
Photon Investors
During 2000, we contributed $44 million of equity capital and assets to a
newly formed limited liability company, Photon Investors, L.L.C., which acquires
and holds telecommunications assets. A third-party financial investor
contributed $60 million on which they earn a preferred return. In connection
with this transaction, Photon formed a wholly owned subsidiary, Quanta
Investors, L.L.C. Our subsidiary manages both Photon and Quanta. During 2000, we
entered into a credit agreement with Quanta, with a commitment by us to lend up
to $500 million, of which approximately $94 million was advanced and outstanding
at December 31, 2000. These amounts are evidenced by a subordinated promissory
note, payable on the earlier of Quanta's liquidation date or any date agreed by
the parties to the note. We also have a demand note payable to Quanta with a
balance of approximately $61 million at December 31, 2000. Both the credit
agreement and the demand note carry a variable interest rate, which was 9.57%
per annum during 2000. Our investment in Photon is being accounted for using the
equity method of accounting.
El Paso Energy Partners
During the third quarter of 2000, Energy Partners completed a public
offering of 4.6 million common units. The offering reduced our common units
ownership interest from 32.5 percent to 27.8 percent. This transaction had no
effect on our general partner interest or our non-managing member interest.
Also, in the third quarter, we received $170 million of Series B preference
units in exchange for the transfer of natural gas storage businesses of Crystal
Gas Storage, Inc., our wholly owned subsidiary, to Energy Partners. These
preference units accrue dividends at a rate of 10 percent on a cumulative basis,
and are redeemable at the option of Energy Partners.
In the first quarter of 2001, as a result of our merger with Coastal,
Energy Partners sold its interest in several offshore assets. These sales
consisted of interests in seven natural gas pipeline systems, a dehydration
facility and two offshore platforms. Proceeds from these sales were
approximately $135 million and resulted in a loss to the partnership of
approximately $23 million. As consideration for these sales, we committed to pay
Energy Partners a series of payments totaling $29 million. This amount, as well
as our proportional share of the losses on the sale of the partnership's assets,
will be recorded as a charge in our income statement in the first quarter of
2001.
77
<PAGE> 80
18. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below.
<TABLE>
<CAPTION>
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
2000
Operating revenues(1)..................................... $7,543 $7,025 $4,250 $3,132
Merger-related costs and asset impairment charges......... 45 -- 46 --
Operating income.......................................... 383 296 320 332
Income before extraordinary items......................... 146 137 134 165
Extraordinary items, net of income taxes.................. (19) -- -- 89
Net income................................................ 127 137 134 254
Basic earnings (loss) per common share
Income before extraordinary items....................... $ 0.63 $ 0.59 $ 0.58 $ 0.72
Extraordinary items, net of income taxes................ (0.08) -- -- 0.39
------ ------ ------ ------
Net income.............................................. $ 0.55 $ 0.59 $ 0.58 $ 1.11
====== ====== ====== ======
Diluted earnings (loss) per common share
Income before extraordinary items....................... $ 0.61 $ 0.57 $ 0.56 $ 0.70
Extraordinary items, net of income taxes................ (0.08) -- -- 0.37
------ ------ ------ ------
Net income.............................................. $ 0.53 $ 0.57 $ 0.56 $ 1.07
====== ====== ====== ======
</TABLE>
<TABLE>
<CAPTION>
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1999
Operating revenues(1)..................................... $2,464 $3,296 $2,647 $2,302
Merger-related costs and asset impairment charges......... 364 58 131 4
Ceiling test charges...................................... -- -- -- 352
Operating income (loss)................................... (141) 144 117 (153)
Income (loss) before cumulative effect of accounting
change.................................................. (178) 39 38 (141)
Cumulative effect of accounting change, net of income
taxes................................................... -- -- -- (13)
Net income (loss)......................................... (178) 39 38 (154)
Basic earnings (loss) per common share
Income (loss) before cumulative effect of accounting
change................................................ $(0.78) $ 0.17 $ 0.17 $(0.62)
Cumulative effect of accounting change, net of income
taxes................................................. -- -- -- (0.06)
------ ------ ------ ------
Net income (loss)....................................... $(0.78) $ 0.17 $ 0.17 $(0.68)
====== ====== ====== ======
Diluted earnings (loss) per common share
Income (loss) before cumulative effect of accounting
change................................................ $(0.78) $ 0.17 $ 0.17 $(0.62)
Cumulative effect of accounting change, net of income
taxes................................................. -- -- -- (0.06)
------ ------ ------ ------
Net income (loss)....................................... $(0.78) $ 0.17 $ 0.17 $(0.68)
====== ====== ====== ======
</TABLE>
- ---------------
(1) In the fourth quarter of 2000, we restated operating revenues for 1999 and
2000 due to the implementation of Emerging Issues Task Force Issue No.
99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. For
the first, second, and third quarters of 2000, operating revenues increased
by $26 million, $23 million, and $38 million. For the first, second, third
and fourth quarters of 1999, operating revenues increased by $23 million,
$50 million, $34 million and $21 million. These adjustments had no impact on
net income (loss) or earnings per share.
78
<PAGE> 81
19. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)
At December 31, 2000, we had leases for approximately 2.7 million net acres
in 11 states, including Louisiana, New Mexico, Texas, Oklahoma, and Arkansas, as
well as the Gulf of Mexico. We also have exploration and production rights in
Turkey.
Capitalized costs relating to natural gas and oil producing activities and
related accumulated depreciation, depletion, and amortization were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
2000 1999
------ ------
(IN MILLIONS)
<S> <C> <C>
Natural gas and oil properties:
Costs subject to amortization............................. $5,795 $5,285
Costs not subject to amortization......................... 135 130
------ ------
5,930 5,415
Less accumulated depreciation, depletion, and
amortization.............................................. 4,412 4,154
------ ------
$1,518 $1,261
====== ======
</TABLE>
Costs incurred in natural gas and oil producing activities, whether
capitalized or expensed, were as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
2000 1999 1998
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Property acquisition costs:
Proved properties......................................... $ 74 $ 3 $ 2
Unproved properties....................................... 41 45 48
Exploration costs........................................... 100 139 156
Development costs........................................... 269 178 375
---- ---- ----
Total costs....................................... $484 $365 $581
==== ==== ====
</TABLE>
Presented below is an analysis of the capitalized costs of natural gas and
oil properties by year of expenditure that are not being amortized as of
December 31, 2000, pending determination of proved reserves. Capitalized
interest of $9 million, $12 million, and $2 million for the years ended December
31, 2000, 1999, and 1998 is included in the presentation below.
<TABLE>
<CAPTION>
CUMULATIVE COSTS EXCLUDED FOR CUMULATIVE
BALANCE YEARS ENDED DEC. 31 BALANCE
------------- --------------------- -------------
DEC. 31, 2000 2000 1999 1998 DEC. 31, 1997
------------- ----- ----- ----- -------------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Acquisition................................ $ 80 $45 $ 7 $19 $9
Exploration................................ 55 28 19 8 --
---- --- --- --- --
$135 $73 $26 $27 $9
==== === === === ==
</TABLE>
Projects presently excluded from amortization are in various stages of
evaluation. The majority of these costs are expected to be included in the
amortization calculation in the years 2001 through 2004. Total amortization
expense per Mcfe, including ceiling test charges, was $0.97, $2.54, and $4.81 in
2000, 1999 and 1998. Excluding ceiling test charges, amortization expense would
have been $0.95 and $1.06 per Mcfe in 1999 and 1998.
79
<PAGE> 82
Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in these reserves,
were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
GAS LIQUIDS GAS LIQUIDS GAS LIQUIDS
(BCF) (MBBLS) (BCF) (MBBLS) (BCF) (MBBLS)
----- ------- ----- ------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Proved (developed and undeveloped)
reserves, net:
Beginning of year.................... 1,271 30,438 1,423 29,717 2,161 72,882
Revisions of previous estimates...... (46) (814) (65) (336) (349) (12,816)
Extensions, discoveries, and other
additions......................... 437 4,966 188 10,599 119 1,688
Purchases of reserves in place....... 78 1,043 34 117 6 --
Sales of reserves in place........... -- -- (123) (3,834) (288) (23,710)
Production........................... (188) (5,138) (186) (5,825) (226) (8,327)
----- ------ ----- ------ ----- -------
End of year....................... 1,552 30,495 1,271 30,438 1,423 29,717
===== ====== ===== ====== ===== =======
Proved developed reserves:
Beginning of year.................... 967 19,713 1,123 24,743 1,558 45,225
===== ====== ===== ====== ===== =======
End of year.......................... 1,061 18,640 967 19,713 1,123 24,743
===== ====== ===== ====== ===== =======
</TABLE>
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 our control. The reserve
data represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner.
The significant changes to reserves, other than purchases, sales or
production, are due to reservoir performance in existing fields and from
drilling additional wells in existing fields. There have been no major
discoveries or other events, favorable or adverse, that may be considered to
have caused a significant change in the estimated proved reserves since December
31, 2000.
Results of operations from producing activities by fiscal year were as
follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
2000 1999 1998
----- ----- -------
(IN MILLIONS)
<S> <C> <C> <C>
Net revenues:
Sales to external customers............................ $ 298 $ 108 $ 174
Affiliated sales....................................... 224 365 361
----- ----- -------
Total.......................................... 522 473 535
Production costs......................................... (74) (98) (91)
Depreciation, depletion, and amortization................ (212) (210) (292)
Ceiling test charges..................................... -- (352) (1,035)
----- ----- -------
Results of operations from producing activities before
tax.................................................... 236 (187) (883)
Income tax (expense) benefit............................. (77) 71 315
----- ----- -------
Results of operations from producing activities
(excluding corporate overhead and interest costs)...... $ 159 $(116) $ (568)
===== ===== =======
</TABLE>
80
<PAGE> 83
The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
2000 1999 1998
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Future cash inflows................................... $16,923 $ 3,421 $ 3,124
Future production and development costs............... (2,130) (1,056) (1,028)
Future income tax expenses............................ (4,870) (458) (317)
------- ------- -------
Future net cash flows................................. 9,923 1,907 1,779
10% annual discount for estimated timing of cash
flows............................................... (3,870) (656) (617)
------- ------- -------
Standardized measure of discounted future net cash
flows............................................... $ 6,053 $ 1,251 $ 1,162
======= ======= =======
</TABLE>
For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using year-end
market natural gas and oil prices. We may receive amounts different than the
standardized measure of discounted cash flow for a number of reasons, including
price changes and the effects of our hedging activities.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
2000 1999 1998
------- ----- -------
(IN MILLIONS)
<S> <C> <C> <C>
Sales and transfers of natural gas and oil produced, net
of production costs................................... $ (448) $(375) $ (444)
Net changes in prices and production costs.............. 5,398 297 (394)
Extensions, discoveries and improved recovery, less
related costs......................................... 2,352 262 72
Changes in estimated future development costs........... (422) 9 36
Development costs incurred during the period............ 180 58 182
Revisions of previous quantity estimates................ (283) (73) (413)
Accretion of discount................................... 153 127 269
Net change in income taxes.............................. (2,673) (166) 379
Purchases of reserves in place.......................... 443 37 4
Sales of reserves in place.............................. -- (174) (469)
Changes in production rates (timing) and other.......... 102 87 (259)
------- ----- -------
$ 4,802 $ 89 $(1,037)
======= ===== =======
</TABLE>
81
<PAGE> 84
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
El Paso Corporation:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14.(a) 1. present fairly, in all material respects, the
consolidated financial position of El Paso Corporation as of December 31, 2000
and 1999, and the consolidated results of its operations and its cash flows for
each of the three years in the period ended December 31, 2000, in conformity
with accounting principles generally accepted in the United States of America.
In addition, in our opinion, the financial statement schedule listed in the
index appearing under Item 14.(a) 2. presents fairly, in all material respects,
the information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and the financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and the
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 20, 2001
82
<PAGE> 85
SCHEDULE II
EL PASO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998
(IN MILLIONS)
<TABLE>
<CAPTION>
CHARGED
BALANCE AT TO COSTS CHARGED BALANCE
BEGINNING AND TO OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
2000
Allowance for doubtful accounts............... $33 $ 92 $(1) $(13)(a) $111
Allowance for price risk management
activities................................. 39 157 -- (3)(b) 193
Valuation allowance on deferred tax assets.... 6 -- -- (3) 3
1999
Allowance for doubtful accounts............... $32 $ 10 $(2) $ (7)(a) $ 33
Allowance for price risk management
activities................................. 28 21 -- (10)(b) 39
Valuation allowance on deferred tax assets.... 5 -- 1 -- 6
1998
Allowance for doubtful accounts............... $52 $ -- $ 6 $(26)(a) $ 32
Allowance for price risk management
activities................................. 25 23 -- (20)(b) 28
Valuation allowance on deferred tax assets.... 19 -- 4 (18)(c) 5
</TABLE>
- ---------------
(a)Primarily accounts written off.
(b)Primarily liquidation of positions on which allowance was established.
(c)$11 million of this deduction was credited to additional paid-in capital for
the utilization of Zilkha Energy Company's net operating loss (NOL)
carryforward and $7 million was credited to deferred tax assets for a waiver
of Gulf States Gas Pipeline Company's NOL carryforward.
83
<PAGE> 86
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information under the captions "Proposal No. 1 -- Election of
Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our
proxy statement for the 2001 Annual Meeting of Stockholders is incorporated
herein by reference. Information regarding our executive officers is presented
in Item 1, Business, of this Form 10-K under the caption "Executive Officers of
the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in our
proxy statement for the 2001 Annual Meeting of Stockholders is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF MANAGEMENT
Information appearing under the caption "Security Ownership of Certain
Beneficial Owners and Management" in our proxy statement for the 2001 Annual
Meeting of Stockholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. Financial statements.
Our consolidated financial statements are included in Part II, Item 8 of
this report:
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Statements of Income...................... 40
Consolidated Balance Sheets............................ 41
Consolidated Statements of Cash Flows.................. 42
Consolidated Statements of Stockholders' Equity........ 43
Notes to Consolidated Financial Statements............. 44
Report of Independent Accountants...................... 82
2. Financial statement schedules and supplementary information
required to be submitted.
Schedule II -- Valuation and qualifying accounts....... 83
Schedules other than that listed above are omitted
because they are not applicable.
3. Exhibit list............................................. 86
</TABLE>
84
<PAGE> 87
(b) REPORTS ON FORM 8-K:
- We filed a current report on Form 8-K, dated October 18, 2000 filing
exhibits in connection with an offering of medium term notes pursuant to
a Registration Statement on Form S-3.
- We filed a current report on Form 8-K, dated December 6, 2000, updating
pro forma financial statements relating to the proposed merger with The
Coastal Corporation.
- We filed a current report on Form 8-K, dated December 8, 2000, filing
exhibits in connection with an offering of medium term notes pursuant to
a Registration Statement on Form S-3.
- We filed a current report on Form 8-K, dated December 19, 2000, filing
exhibits in connection with an offering of medium term notes pursuant to
a Registration Statement on Form S-3.
- We filed a current report on Form 8-K, dated January 3, 2001, announcing
the completion of our acquisition of PG&E's Texas Midstream operations.
- We filed a current report on Form 8-K, dated January 29, 2001, announcing
the completion of our merger with The Coastal Corporation.
- We filed a current report on Form 8-K, dated February 5, 2001, announcing
the completion of our merger with The Coastal Corporation and the
exchange and issuance of shares of El Paso.
- We filed a current report on Form 8-K, dated February 6, 2001, announcing
our name change to El Paso Corporation.
- We filed a current report on Form 8-K, dated February 14, 2001,
announcing several events including the opening of a New European Trading
floor, the Purchase of Texas Midstream Operations, Recent Developments on
California, the Approval of a Dividend Increase, the Announcement of
Record Earnings, the Completion of Post Merger Restructuring, and our
2001 Analysts Meetings.
- We filed a current report on Form 8-K/A, dated February 21, 2001
announcing information on debt issuances and clarifying items contained
in the February 14, 2001 Form 8-K.
- We filed a current report on Form 8-K, dated February 23, 2001 announcing
plans to offer a private offering of zero coupon convertible debentures,
convertible into El Paso common stock.
- We filed a current report on Form 8-K, dated March 2, 2001, announcing
our combined operating results for the first 30 days following our merger
with Coastal.
85
<PAGE> 88
EL PASO CORPORATION
EXHIBIT LIST
DECEMBER 31, 2000
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
2 -- Agreement and Plan of Merger, dated January 17, 2000, by
and among El Paso, El Paso Merger Company and The Coastal
Corporation (Exhibit 1 to Schedule 13D filed by El Paso
on January 26, 2000, File No. 5-55241).
3.A -- Restated Certificate of Incorporation of El Paso as filed
with the Delaware Secretary of State on February 7, 2001
(Exhibit 3.A to El Paso's Form 8-K, filed February 14,
2001).
3.B -- Restated By-laws of El Paso (Exhibit 3.B to El Paso's
Form 8-K dated February 14, 2001).
4.A -- Amended and Restated Shareholder Rights Agreement,
between El Paso and BankBoston, N.A., dated January 20,
1999 (Exhibit 1 to El Paso's Registration Statement on
Form 8-A/A Amendment No. 1, filed January 29, 1999, File
No. 1-14365).
4.B -- Indenture dated as of May 10, 1999, by and between the
Registrant and The Chase Manhattan Bank, as Trustee
(Exhibit 4.1 to El Paso Form 8-K dated May 10, 1999, File
No. 1-14365).
*4.C -- Fifth Supplemental Indenture dated as of February 28,
2001, by and between El Paso and The Chase Manhattan
Bank, as Trustee, including the form of Zero Coupon
Convertible Debenture due February 28, 2001.
*4.D -- Form of Purchase Contract Agreement between The Coastal
Corporation and The Bank of New York as Purchase Contract
Agent and First Supplement to the Purchase Agreement
dated as of January 29, 2001 among The Coastal
Corporation, El Paso and The Bank of New York, as
Purchase Contract Agent.
10.A -- $2,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A. and
ABN Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.A to El Paso's 2000 Third
Quarter 10-Q).
10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A., ABN
Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.B to El Paso's 2000 Third
Quarter 10-Q).
*10.B.1 -- $700,000,000 3-Month Revolving Credit Facility Agreement
dated as of December 21, 2000 among El Paso, the several
banks and other financial institutions, The Chase
Manhattan Bank, as administrative agent for the Lenders
and Chase Securities Inc. as lead arranger and book
manager.
</TABLE>
86
<PAGE> 89
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.C -- Omnibus Compensation Plan dated January 1, 1992;
Amendment No. 1 effective as of April 1, 1998; Amendment
No. 2 effective as of August 1, 1998; Amendment No. 3
effective as of December 3, 1998; and Amendment No. 4
effective as of January 20, 1999 (Exhibit 10.C to El
Paso's 1998 10-K).
+10.D -- 1995 Incentive Compensation Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.D to El
Paso's 1998 10-K).
+10.E -- 1995 Compensation Plan for Non-Employee Directors,
Amended and Restated effective as of August 1, 1998
(Exhibit 10.H to El Paso's 1998 Third Quarter 10-Q);
Amendment No. 1, effective March 9, 1999, (Exhibit 10.E.1
to El Paso's 1999 Second Quarter 10-Q) and Amendment No.
2, effective as of July 16, 1999 (Exhibit 10.E.2 to El
Paso's 1999 Second Quarter 10-Q).
+10.F -- Stock Option Plan for Non-Employee Directors, Amended and
Restated effective as of January 20, 1999 (Exhibit 10.F
to El Paso's 1998 10-K) and Amendment No. 1, effective as
of July 16, 1999 (Exhibit 10.F.1 to El Paso's 1999 Second
Quarter 10-Q).
+10.G -- 1995 Omnibus Compensation Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.J to El Paso's
1998 Third Quarter 10-Q); Amendment No. 1, effective as
of December 3, 1998; and Amendment No. 2, effective as of
January 20, 1999 (Exhibit 10.G.1 to El Paso's 1998 10-K).
+10.H -- Supplemental Benefits Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.H to El
Paso's 1998 10-K), and Amendment No. 1 effective as of
January 1, 2000 (Exhibit 10.H.1 to El Paso's 2000 Second
Quarter 10-Q).
+10.I -- Senior Executive Survivor Benefit Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.M to
El Paso's 1998 Third Quarter 10-Q).
+10.J -- Deferred Compensation Plan, Amended and Restated
effective as of December 3, 1998. (Exhibit 10.J to El
Paso's 1998 10-K), and Amendment No. 1 effective as of
January 1, 2000 (Exhibit 10.K.1 to El Paso's 2000 Second
Quarter 10-Q).
+10.K -- Key Executive Severance Protection Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.O to
El Paso's 1998 Third Quarter 10-Q).
+10.L -- Director Charitable Award Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.P to the El
Paso's 1998 Third Quarter 10-Q).
+10.M -- Strategic Stock Plan, Amended and Restated effective as
of December 31, 1999 (Exhibit 10.1 to El Paso's Form S-8
filed January 14, 2000).
+10.N -- Domestic Relocation Policy, effective November 1, 1996
(Exhibit 10.Q to EPNG's Form 10-K, filed March 20, 1998,
File No. 1-2700).
*+10.O -- Employment Agreement, Amended and Restated effective as
of February 1, 2001, between El Paso and William A. Wise.
+10.Q -- Promissory Note dated May 30, 1997, made by William A.
Wise to El Paso (Exhibit 10.R to EPNG's Form 10-Q, filed
May 15, 1998, File No. 1-2700 ("EPNG's 1998 First Quarter
10-Q"); Amendment to Promissory Note dated November 20,
1997 (Exhibit 10.R to EPNG's 1998 First Quarter 10-Q).
+10.R -- Executive Award Plan of Sonat Inc., amended and restated
effective as of July 23, 1998, as amended May 27, 1999
(Exhibit 10.R to El Paso's 1999 Third Quarter 10-Q);
Termination of the Executive Award Plan of Sonat Inc.
(Exhibit 10.K.1 to El Paso's 2000 Second Quarter 10-Q).
</TABLE>
87
<PAGE> 90
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.S -- Letter Agreement dated February 22, 1991, between EPNG
and Britton White Jr. (Exhibit 10.V to the El Paso's 1998
Third Quarter 10-Q).
+10.T -- El Paso Employee Stock Purchase Plan, effective as of
January 20, 1999 (Exhibit 10.1 to El Paso's Form S-8,
filed May 20, 1999, File No. 333-78949); Amendment No. 1,
effective as of May 24, 1999.
*+10.T.1 -- Amendment No. 2 to the El Paso Employee Stock Purchase
Plan effective as of October 1, 1999; Amendment No. 3 to
the Employee Stock Purchase Plan effective as of March
14, 2000 and Amendment No. 4 to the Employee Stock
Purchase Plan effective as of January 1, 2001.
+10.U -- Omnibus Plan for Management Employees Amended and
Restated effective as of December 3, 1999 (Exhibit 10.1
to El Paso's Form S-8 filed January 14, 2000, File No.
333-94719) and Amendment No. 1 effective as of December
1, 2000 (Exhibit 10.1 to El Paso's Form S-8 filed
December 18, 2000).
+10.V -- 1999 Omnibus Incentive Compensation Plan, dated January
20, 1999 (Exhibit 10.1 to El Paso's Form S-8 filed May
20, 1999).
*+10.W -- Employment Letter dated June 16, 1999, between El Paso
and Ralph Eads.
*+10.X -- Termination and Consulting Agreement dated October 25,
1999, between El Paso and Ronald L. Kuehn Jr.
*10.Y -- Form of Stock Pledge Agreement, dated February 1, 2001,
by and between El Paso and the named executives therein;
and Form of Promissory Note dated February 1, 2001, in
favor of El Paso by named executives therein; and listing
of certain executive participants.
*+10.Z -- Professional Services Agreement dated January 16, 2001 by
and between El Paso and David A. Arledge.
*21 -- Subsidiaries of El Paso.
*23 -- Consent of Independent Accountants.
</TABLE>
UNDERTAKING
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph
(4)(iii), to furnish to the Securities and Exchange Commission upon request all
constituent instruments defining the rights of holders of our long-term debt and
our consolidated subsidiaries not filed herewith for the reason that the total
amount of securities authorized under any of such instruments does not exceed 10
percent of our total consolidated assets.
88
<PAGE> 91
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Corporation has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized
on the 21st day of March 2001.
EL PASO CORPORATION
Registrant
By /s/ WILLIAM A. WISE
-----------------------------------
William A. Wise
Chairman of the Board,
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
El Paso Corporation and in the capacities and on the dates indicated:
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ WILLIAM A. WISE Chairman of the Board, March 21, 2001
- ----------------------------------------------------- President, Chief Executive
(William A. Wise) Officer and Director
/s/ H. BRENT AUSTIN Executive Vice President and March 21, 2001
- ----------------------------------------------------- Chief Financial Officer
(H. Brent Austin)
/s/ JEFFREY I. BEASON Senior Vice President and March 21, 2001
- ----------------------------------------------------- Controller (Chief Accounting
(Jeffrey I. Beason) Officer)
/s/ BYRON ALLUMBAUGH Director March 21, 2001
- -----------------------------------------------------
(Byron Allumbaugh)
/s/ DAVID A. ARLEDGE Director March 21, 2001
- -----------------------------------------------------
(David A. Arledge)
/s/ JOHN M. BISSELL Director March 21, 2001
- -----------------------------------------------------
(John M. Bissell)
/s/ JUAN CARLOS BRANIFF Director March 21, 2001
- -----------------------------------------------------
(Juan Carlos Braniff)
/s/ JAMES F. GIBBONS Director March 21, 2001
- -----------------------------------------------------
(James F. Gibbons)
/s/ ANTHONY W. HALL JR. Director March 21, 2001
- -----------------------------------------------------
(Anthony W. Hall Jr.)
/s/ RONALD L. KUEHN, JR. Director March 21, 2001
- -----------------------------------------------------
(Ronald L. Kuehn, Jr.)
</TABLE>
89
<PAGE> 92
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ J. CARLETON MACNEIL JR. Director March 21, 2001
- -----------------------------------------------------
(J. Carleton MacNeil Jr.)
/s/ THOMAS R. MCDADE Director March 21, 2001
- -----------------------------------------------------
(Thomas R. McDade)
/s/ MALCOLM WALLOP Director March 21, 2001
- -----------------------------------------------------
(Malcolm Wallop)
/s/ JOE B. WYATT Director March 21, 2001
- -----------------------------------------------------
(Joe B. Wyatt)
</TABLE>
90
<PAGE> 93
EXHIBIT INDEX
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
2 -- Agreement and Plan of Merger, dated January 17, 2000, by
and among El Paso, El Paso Merger Company and The Coastal
Corporation (Exhibit 1 to Schedule 13D filed by El Paso
on January 26, 2000, File No. 5-55241).
3.A -- Restated Certificate of Incorporation of El Paso as filed
with the Delaware Secretary of State on February 7, 2001
(Exhibit 3.A to El Paso's Form 8-K, filed February 14,
2001).
3.B -- Restated By-laws of El Paso (Exhibit 3.B to El Paso's
Form 8-K dated February 14, 2001).
4.A -- Amended and Restated Shareholder Rights Agreement,
between El Paso and BankBoston, N.A., dated January 20,
1999 (Exhibit 1 to El Paso's Registration Statement on
Form 8-A/A Amendment No. 1, filed January 29, 1999, File
No. 1-14365).
4.B -- Indenture dated as of May 10, 1999, by and between the
Registrant and The Chase Manhattan Bank, as Trustee
(Exhibit 4.1 to El Paso Form 8-K dated May 10, 1999, File
No. 1-14365).
*4.C -- Fifth Supplemental Indenture dated as of February 28,
2001, by and between El Paso and The Chase Manhattan
Bank, as Trustee, including the form of Zero Coupon
Convertible Debenture due February 28, 2001.
*4.D -- Form of Purchase Contract Agreement between The Coastal
Corporation and The Bank of New York as Purchase Contract
Agent and First Supplement to the Purchase Agreement
dated as of January 29, 2001 among The Coastal
Corporation, El Paso and The Bank of New York, as
Purchase Contract Agent.
10.A -- $2,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A. and
ABN Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.A to El Paso's 2000 Third
Quarter 10-Q).
10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A., ABN
Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.B to El Paso's 2000 Third
Quarter 10-Q).
*10.B.1 -- $700,000,000 3-Month Revolving Credit Facility Agreement
dated as of December 21, 2000 among El Paso, the several
banks and other financial institutions, The Chase
Manhattan Bank, as administrative agent for the Lenders
and Chase Securities Inc. as lead arranger and book
manager.
+10.C -- Omnibus Compensation Plan dated January 1, 1992;
Amendment No. 1 effective as of April 1, 1998; Amendment
No. 2 effective as of August 1, 1998; Amendment No. 3
effective as of December 3, 1998; and Amendment No. 4
effective as of January 20, 1999 (Exhibit 10.C to El
Paso's 1998 10-K).
</TABLE>
<PAGE> 94
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.D -- 1995 Incentive Compensation Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.D to El
Paso's 1998 10-K).
+10.E -- 1995 Compensation Plan for Non-Employee Directors,
Amended and Restated effective as of August 1, 1998
(Exhibit 10.H to El Paso's 1998 Third Quarter 10-Q);
Amendment No. 1, effective March 9, 1999, (Exhibit 10.E.1
to El Paso's 1999 Second Quarter 10-Q) and Amendment No.
2, effective as of July 16, 1999 (Exhibit 10.E.2 to El
Paso's 1999 Second Quarter 10-Q).
+10.F -- Stock Option Plan for Non-Employee Directors, Amended and
Restated effective as of January 20, 1999 (Exhibit 10.F
to El Paso's 1998 10-K) and Amendment No. 1, effective as
of July 16, 1999 (Exhibit 10.F.1 to El Paso's 1999 Second
Quarter 10-Q).
+10.G -- 1995 Omnibus Compensation Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.J to El Paso's
1998 Third Quarter 10-Q); Amendment No. 1, effective as
of December 3, 1998; and Amendment No. 2, effective as of
January 20, 1999 (Exhibit 10.G.1 to El Paso's 1998 10-K).
+10.H -- Supplemental Benefits Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.H to El
Paso's 1998 10-K), and Amendment No. 1 effective as of
January 1, 2000 (Exhibit 10.H.1 to El Paso's 2000 Second
Quarter 10-Q).
+10.I -- Senior Executive Survivor Benefit Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.M to
El Paso's 1998 Third Quarter 10-Q).
+10.J -- Deferred Compensation Plan, Amended and Restated
effective as of December 3, 1998. (Exhibit 10.J to El
Paso's 1998 10-K), and Amendment No. 1 effective as of
January 1, 2000 (Exhibit 10.K.1 to El Paso's 2000 Second
Quarter 10-Q).
+10.K -- Key Executive Severance Protection Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.O to
El Paso's 1998 Third Quarter 10-Q).
+10.L -- Director Charitable Award Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.P to the El
Paso's 1998 Third Quarter 10-Q).
+10.M -- Strategic Stock Plan, Amended and Restated effective as
of December 31, 1999 (Exhibit 10.1 to El Paso's Form S-8
filed January 14, 2000).
+10.N -- Domestic Relocation Policy, effective November 1, 1996
(Exhibit 10.Q to EPNG's Form 10-K, filed March 20, 1998,
File No. 1-2700).
*+10.O -- Employment Agreement, Amended and Restated effective as
of February 1, 2001, between El Paso and William A. Wise.
+10.Q -- Promissory Note dated May 30, 1997, made by William A.
Wise to El Paso (Exhibit 10.R to EPNG's Form 10-Q, filed
May 15, 1998, File No. 1-2700 ("EPNG's 1998 First Quarter
10-Q"); Amendment to Promissory Note dated November 20,
1997 (Exhibit 10.R to EPNG's 1998 First Quarter 10-Q).
+10.R -- Executive Award Plan of Sonat Inc., amended and restated
effective as of July 23, 1998, as amended May 27, 1999
(Exhibit 10.R to El Paso's 1999 Third Quarter 10-Q);
Termination of the Executive Award Plan of Sonat Inc.
(Exhibit 10.K.1 to El Paso's 2000 Second Quarter 10-Q).
+10.S -- Letter Agreement dated February 22, 1991, between EPNG
and Britton White Jr. (Exhibit 10.V to the El Paso's 1998
Third Quarter 10-Q).
</TABLE>
<PAGE> 95
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.T -- El Paso Employee Stock Purchase Plan, effective as of
January 20, 1999 (Exhibit 10.1 to El Paso's Form S-8,
filed May 20, 1999, File No. 333-78949); Amendment No. 1,
effective as of May 24, 1999.
*+10.T.1 -- Amendment No. 2 to the El Paso Employee Stock Purchase
Plan effective as of October 1, 1999; Amendment No. 3 to
the Employee Stock Purchase Plan effective as of March
14, 2000 and Amendment No. 4 to the Employee Stock
Purchase Plan effective as of January 1, 2001.
+10.U -- Omnibus Plan for Management Employees Amended and
Restated effective as of December 3, 1999 (Exhibit 10.1
to El Paso's Form S-8 filed January 14, 2000, File No.
333-94719) and Amendment No. 1 effective as of December
1, 2000 (Exhibit 10.1 to El Paso's Form S-8 filed
December 18, 2000).
+10.V -- 1999 Omnibus Incentive Compensation Plan, dated January
20, 1999 (Exhibit 10.1 to El Paso's Form S-8 filed May
20, 1999).
*+10.W -- Employment Letter dated June 16, 1999, between El Paso
and Ralph Eads.
*+10.X -- Termination and Consulting Agreement dated October 25,
1999, between El Paso and Ronald L. Kuehn Jr.
*10.Y -- Form of Stock Pledge Agreement, dated February 1, 2001,
by and between El Paso and the named executives therein;
and Form of Promissory Note dated February 1, 2001, in
favor of El Paso by named executives therein; and listing
of certain executive participants.
*+10.Z -- Professional Services Agreement dated January 16, 2001 by
and between EL Paso and David A. Arledge.
*21 -- Subsidiaries of El Paso.
*23 -- Consent of Independent Accountants.
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.C
<SEQUENCE>2
<FILENAME>h82590ex4-c.txt
<DESCRIPTION>FIFTH SUPPLEMENTAL INDENTURE
<TEXT>
<PAGE> 1
EXHIBIT 4.C
EXECUTION COPY
================================================================================
FIFTH SUPPLEMENTAL INDENTURE
BETWEEN
EL PASO CORPORATION
AND
THE CHASE MANHATTAN BANK
AS TRUSTEE
---------
DATED AS OF
FEBRUARY 28, 2001
TO INDENTURE DATED AS OF MAY 10, 1999
---------
ZERO COUPON CONVERTIBLE DEBENTURES DUE FEBRUARY 28, 2021
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
<S> <C> <C>
ARTICLE I THE 2021 DEBENTURES........................................................2
Section 101 Designation of 2021 Debentures; Establishment of Form...........2
Section 102 Transfer and Exchange...........................................3
Section 103 Amount..........................................................8
Section 104 Accrual of Original Issue Discount; Interest....................8
Section 105 Additional Interest.............................................9
Section 106 Denominations...................................................9
Section 107 Place of Payment................................................9
Section 108 Redemption......................................................9
Section 109 Conversion......................................................9
Section 110 Maturity........................................................9
Section 111 Repurchase.....................................................10
Section 112 Covenants......................................................10
Section 113 Amount Due Upon Event of Default...............................10
Section 114 Discharge of Liability on 2021 Debentures......................10
Section 115 Other Terms of 2021 Debentures.................................10
ARTICLE II AMENDMENTS TO THE INDENTURE..............................................11
Section 201 Amendments Applicable Only to 2021 Debentures..................11
Section 202 Definitions....................................................11
Section 203 Definition of Outstanding......................................15
Section 204 Registration, Registration of Transfer and Exchange............15
Section 205 Mutilated, Destroyed, Lost and Stolen Securities...............15
Section 206 Payment of Interest; Interest Rights Preserved.................16
Section 207 Cancellation...................................................16
Section 208 Redemption.....................................................16
Section 209 Consolidation, Merger and Sale.................................18
Section 210 Defaults and Remedies..........................................19
Section 211 Collection of Indebtedness and Suits for Enforcement
by Trustee...................................................19
Section 212 Unconditional Right of Holders to Receive Principal, Premium
and Interest.................................................20
Section 213 Supplemental Indentures Without Consent of Holders.............20
Section 214 Supplemental Indenture with Consent of Holder..................20
Section 215 Maintenance of Office or Agency................................21
Section 216 Conversion, Tax Event, Repurchase..............................21
ARTICLE III MISCELLANEOUS PROVISIONS................................................49
Section 301 Integral Part..................................................49
Section 302 General Definitions............................................49
Section 303 Adoption, Ratification and Confirmation........................50
Section 304 Trust Indenture Act Controls...................................50
Section 305 Governing Law..................................................50
Section 306 Severability...................................................50
Section 307 Counterpart Originals..........................................50
Section 308 Successors.....................................................50
Section 309 Table of Contents, Headings, etc...............................50
Section 310 Benefit of Fifth Supplemental Indenture........................51
Section 311 Acceptance by Trustee..........................................51
</TABLE>
-i-
<PAGE> 3
THIS FIFTH SUPPLEMENTAL INDENTURE, dated as of February 28, 2001, is
between El Paso Corporation, (formerly known as El Paso Energy Corporation), a
Delaware corporation (the "Company"), and The Chase Manhattan Bank, as trustee
(the "Trustee").
RECITALS OF THE COMPANY
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture, dated as of May 10, 1999 (the "Original Indenture," as
supplemented by the First Supplemental Indenture, dated as of May 10, 1999, the
Second Supplemental Indenture, dated as of July 12, 1999, the Third Supplemental
Indenture, dated as of July 12, 1999, and the Fourth Supplemental Indenture,
dated as of May 31, 2000), (collectively and as further supplemented by this
Fifth Supplemental Indenture, dated as of February 28, 2001, the "Indenture"),
providing for the issuance from time to time of one or more series of the
Company's Securities; and
WHEREAS, Section 901(5) of the Original Indenture provides that the
Company and the Trustee may from time to time enter into one or more indentures
supplemental thereto to establish the form or terms of Securities of a new
series; and
WHEREAS, Section 901(3) of the Original Indenture permits the execution
of supplemental indentures without the consent of any Holders to add to the
covenants of the Company for the benefit of, and to add any additional Events of
Default with respect to, all or any series of Securities; and
WHEREAS, Section 901(6) of the Original Indenture permits the execution
of supplemental indentures without the consent of any Holders to make provisions
with respect to matters or questions arising under the Indenture, provided that
such provisions do not adversely affect the interests of the Holders of
Outstanding Securities in any material respect; and
WHEREAS, Sections 201 and 301 of the Original Indenture provide that
the Company may enter into supplemental indentures to establish the terms and
provisions of a series of Securities issued pursuant to the Indenture; and
WHEREAS, the Company desires to issue Zero Coupon Convertible
Debentures due February 28, 2021 (the "2021 Debentures"), a new series of
Security, the issuance of which was authorized by or pursuant to resolutions of
the Board of Directors of the Company; and
WHEREAS, the Company, pursuant to the foregoing authority, proposes in
and by this Fifth Supplemental Indenture to supplement and amend in certain
respects the Original Indenture insofar as it will apply only to the 2021
Debentures (and not to any other series) in certain respects; and
WHEREAS, all things necessary have been done to make the 2021
Debentures, when executed by the Company and authenticated and delivered
hereunder and duly issued by the Company, the valid obligations of the Company,
and to make this Fifth Supplemental Indenture a valid agreement of the Company,
in accordance with their and its terms.
<PAGE> 4
NOW THEREFORE:
In consideration of the premises provided for herein, the Company and
the Trustee mutually covenant and agree for the equal and proportionate benefit
of all Holders of the 2021 Debentures as follows:
ARTICLE I
THE 2021 DEBENTURES
Section 101 Designation of 2021 Debentures; Establishment of Form.
There shall be a series of Securities designated "Zero Coupon
Convertible Debentures due February 28, 2021" of the Company, and the form
thereof shall be substantially as set forth in Annex A hereto, which is
incorporated into and shall be deemed a part of this Fifth Supplemental
Indenture, in each case with such appropriate insertions, omissions,
substitutions and other variations as are required or permitted by the
Indenture, and may have such letters, numbers or other marks of identification
and such legends or endorsements placed thereon as may be required to comply
with the rules of any securities exchange or as may, consistently herewith, be
determined by the officers of the Company executing such 2021 Debentures, as
evidenced by their execution of the 2021 Debentures.
(a) Restricted Global Securities. All of the 2021 Debentures are
initially being offered and sold to Credit Suisse First Boston Corporation
("CSFB"), as initial purchaser ("Initial Purchaser") pursuant to the Purchase
Agreement, and offered and sold by CSFB to qualified institutional buyers as
defined in Rule 144A (collectively, "QIBs" or individually a "QIB") in reliance
on Rule 144A under the Securities Act and shall be issued initially in the form
of one or more Restricted Global Securities, which shall be deposited on behalf
of the purchasers of the 2021 Debentures represented thereby with the Trustee,
at its Corporate Trust Office, as Security Custodian for the depositary, The
Depository Trust Company ("DTC") (such depositary, or any successor thereto,
being hereinafter referred to as the "Depositary"), and registered in the name
of its nominee, Cede & Co., duly executed by the Company and authenticated by
the Trustee as hereinafter provided. The aggregate Principal Amount of a
Restricted Global Security may from time to time be increased or decreased by
adjustments made on the records of the Security Custodian as hereinafter
provided, subject in each case to compliance with the Applicable Procedures.
Until sold pursuant to Rule 144, pursuant to an effective registration statement
under the Securities Act or pursuant to any other available exemption (other
than Rule 144A) from the registration requirements of the Securities Act, the
Company agrees that if it is not subject to the requirements of Section 13 or
15(d) of the Exchange Act, the Company shall furnish to all Holders of the
Securities and prospective purchasers of same, promptly upon their request, the
information required to be delivered pursuant to Rule 144(d)(4) of the rules and
regulations promulgated under the Securities Act.
(b) Global Securities in General. Each Global Security shall represent
such of the outstanding 2021 Debentures as shall be specified therein and each
shall provide that it shall represent the aggregate amount of outstanding 2021
Debentures from time to time endorsed thereon and that the aggregate amount of
outstanding 2021 Debentures represented thereby may
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from time to time be reduced or increased, as appropriate, to reflect exchanges,
redemptions, purchases or conversions of such 2021 Debentures. Any endorsement
of a Global Security to reflect the amount of any increase or decrease in the
Principal Amount of Outstanding 2021 Debentures represented thereby shall be
made by the Security Custodian in accordance with the standing instructions and
procedures existing between the Depositary and the Security Custodian.
Members of, or participants in, the Depositary ("Agent Members") shall
have no rights under this Indenture with respect to any Global Security held on
their behalf by the Depositary or under the Global Security, and the Depositary
(including, for this purpose, its nominee) may be treated by the Company, the
Trustee and any agent of the Company or the Trustee as the absolute owner and
Holder of such Global Security for all purposes whatsoever. Notwithstanding the
foregoing, nothing herein shall (A) prevent the Company, the Trustee or any
agent of the Company or the Trustee from giving effect to any written
certification, proxy or other authorization furnished by the Depositary or (B)
impair, as between the Depositary and its Agent Members, the operation of
customary practices governing the exercise of the rights of a Holder of any 2021
Debenture.
(c) Certificated Securities. Certificated Securities shall be issued
only under the limited circumstances provided in Section 102(a)(1) hereof.
The Company initially appoints The Depository Trust Company to act as
Depositary with respect to the Global Securities.
The Company initially appoints the Trustee to act as Paying Agent,
Security Registrar and Conversion Agent with respect to the 2021 Debentures.
Section 102 Transfer and Exchange.
(a) Transfer and Exchange of Global Securities.
(1) Certificated Securities shall be issued in exchange for
interests in the Global Securities only if (x) the Depositary notifies
the Company that it is unwilling or unable to continue as depositary
for the Global Securities or if it at any time ceases to be a
"clearing agency" registered under the Exchange Act if so required by
applicable law or regulation and a successor depositary is not
appointed by the Company within 90 days, or (y) an Event of Default
has occurred and is continuing. In either case, the Company shall
execute, and the Trustee shall, upon receipt of a Company Order (which
the Company agrees to deliver promptly), authenticate and deliver
Certificated Securities in an aggregate Principal Amount equal to the
Principal Amount of such Global Securities in exchange therefor. Only
Restricted Certificated Securities shall be issued in exchange for
beneficial interests in Restricted Global Securities, and only
Unrestricted Certificated Securities shall be issued in exchange for
beneficial interests in Unrestricted Global Securities. Certificated
Securities issued in exchange for beneficial interests in Global
Securities shall be registered in such names and shall be in such
authorized denominations as the Depositary, pursuant to instructions
from its direct or indirect participants or otherwise, shall instruct
the Trustee. The Trustee shall deliver or cause to
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be delivered such Certificated Securities to the persons in whose
names such Securities are so registered. Such exchange shall be
effected in accordance with the Applicable Procedures. Nothing herein
shall require the Trustee to communicate directly with beneficial
owners, and the Trustee shall in connection with any transfers
hereunder be entitled to rely on instructions received through the
registered Holder.
(2) Notwithstanding any other provisions of this Indenture other
than the provisions set forth in Section 102(a)(1) hereof, a Global
Security may not be transferred as a whole except by the Depositary to
a nominee of the Depositary or by a nominee of the Depositary to the
Depositary or another nominee of the Depositary or by the Depositary
or any such nominee to a successor Depositary or a nominee of such
successor Depositary.
(b) Transfer and Exchange of Certificated Securities. When Certificated
Securities are presented by a Holder to an office or agency of the Company
maintained pursuant to Section 1002 of the Indenture for such purpose (a
"Registrar") with a request:
(1) to register the transfer of the Certificated Securities to a
person who will take delivery thereof in the form of Certificated
Securities only; or
(2) to exchange such Certificated Securities for an equal
Principal Amount of Certificated Securities of other authorized
denominations,
such Registrar shall register the transfer or make the exchange as requested;
provided, however, that the Certificated Securities presented or surrendered for
register of transfer or exchange:
(3) shall be duly endorsed or accompanied by a written instrument
of transfer in accordance with the fifth paragraph of Section 305 of
the Indenture; and
(4) in the case of a Restricted Certificated Security, such
request shall be accompanied by the following additional information
and documents, as applicable:
(A) if such Restricted Certificated Security is being
delivered to the Registrar by a Holder for registration in the
name of such Holder, without transfer, or such Restricted
Certificated Security is being transferred to the Company or a
Subsidiary of the Company, a certification to that effect from
such Holder (in substantially the form set forth in the Transfer
Certificate required pursuant to Section 102(e)(1) hereof); or
(B) if such Restricted Certificated Security is being
transferred to a person the Holder reasonably believes is a QIB
in accordance with Rule 144A or pursuant to an effective
registration statement under the Securities Act, a certification
to that effect from such Holder and the transferee (in
substantially the form set forth in the Transfer Certificate); or
(C) if such Restricted Certificated Security is being
transferred (i) pursuant to an exemption from the registration
requirements of the Securities Act in accordance with Rule 144,
(ii) pursuant to an exemption from the
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registration requirements of the Securities Act (other than
pursuant to Rule 144A or Rule 144) and as a result of which, in
the case of a Security transferred pursuant to this clause (ii),
such Security shall cease to be a "restricted security" within
the meaning of Rule 144, a certification to that effect from the
Holder or (iii) pursuant to an exemption from the registration
requirements of the Securities Act to a non-U.S. person in an
offshore transaction under Regulation S under the Securities Act,
a certification to that effect from the transferor (in
substantially the form set forth in the Transfer Certificate),
and, if the Company or such Registrar so requests, a customary
opinion of counsel, certificates and other information reasonably
acceptable to the Company and such Registrar to the effect that
such transfer is in compliance with the Securities Act.
(c) Transfer of a Beneficial Interest in a Restricted Global Security
for a Beneficial Interest in an Unrestricted Global Security. Any person having
a beneficial interest in a Restricted Global Security may upon request, subject
to the Applicable Procedures, transfer such beneficial interest to a person who
is required or permitted to take delivery thereof in the form of an Unrestricted
Global Security. Upon receipt by the Trustee of written instructions or such
other form of instructions and the following additional information and
documents, in each case in such form as is customary for the Depositary, from
the Depositary or its nominee on behalf of the person having such beneficial
interest in the Restricted Global Security (all of which may be submitted by
facsimile or electronically):
(1) if such beneficial interest is being transferred pursuant to
an effective registration statement under the Securities Act, a
certification to that effect from the transferor (in substantially the
form set forth in the Transfer Certificate); or
(2) if such beneficial interest is being transferred (i) pursuant
to an exemption from the registration requirements of the Securities
Act in accordance with Rule 144 or (ii) pursuant to an exemption from
the registration requirements of the Securities Act (other than
pursuant to Rule 144A or Rule 144) and as a result of which, in the
case of a Security transferred pursuant to this sub-clause (ii), such
Security shall cease to be a "restricted security" within the meaning
of Rule 144, a certification to that effect from the transferor (in
substantially the form set forth in the Transfer Certificate) and, if
the Company or the Trustee so requests, a customary opinion of
counsel, certificates and other information reasonably acceptable to
the Company and the Trustee to the effect that such transfer is in
compliance with the Securities Act,
the Trustee, as a Registrar and Security Custodian, shall reduce or cause to be
reduced the aggregate Principal Amount of the Restricted Global Security by the
appropriate Principal Amount and shall increase or cause to be increased the
aggregate Principal Amount of the Unrestricted Global Security by a like
Principal Amount. Such transfer shall otherwise be effected in accordance with
the Applicable Procedures. If no Unrestricted Global Security is then
outstanding, the Company shall execute and the Trustee shall, upon receipt of a
Company Order (which the Company agrees to deliver promptly), authenticate and
deliver an Unrestricted Global Security.
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(d) Transfers of Certificated Securities for Beneficial Interest in
Global Securities. If Certificated Securities are issued in exchange for
beneficial interests in Global Securities and, thereafter, the events or
conditions specified in Section 102(a)(1) hereof which required such exchange
shall have ceased to exist, the Company shall mail notice to the Trustee and to
the Holders stating that Holders may exchange Certificated Securities for
interests in Global Securities by complying with the procedures set forth herein
and briefly describing such procedures and the events or circumstances requiring
that such notice be given. Thereafter, if Certificated Securities are presented
by a Holder to a Registrar with a request:
(1) to register the transfer of such Certificated Securities to a
person who will take delivery thereof in the form of a beneficial
interest in a Global Security, which request shall specify whether
such Global Security will be a Restricted Global Security or an
Unrestricted Global Security; or
(2) to exchange such Certificated Securities for an equal
Principal Amount of beneficial interests in a Global Security, which
beneficial interests will be owned by the Holder transferring such
Certificated Securities (provided that in the case of such an
exchange, Restricted Certificated Securities may be exchanged only for
Restricted Global Securities and Unrestricted Certificated Securities
may be exchanged only for Unrestricted Global Securities),
the Registrar shall register the transfer or make the exchange as requested by
canceling such Certificated Security and causing, or directing the Security
Custodian to cause, the aggregate Principal Amount of the applicable Global
Security to be increased accordingly and, if no such Global Security is then
outstanding, the Company shall issue and the Trustee shall, upon receipt of a
Company Order (which the Company agrees to deliver promptly), authenticate and
deliver a new Global Security; provided, however, that the Certificated
Securities presented or surrendered for registration of transfer or exchange:
(3) shall be duly endorsed or accompanied by a written instrument
of transfer in accordance with the fifth paragraph of Section 305 of
the Indenture;
(4) in the case of a Restricted Certificated Security to be
transferred for a beneficial interest in an Unrestricted Global
Security, such request shall be accompanied by the following
additional information and documents, as applicable:
(A) if such Restricted Certificated Security is being
transferred pursuant to an effective registration statement under
the Securities Act, a certification to that effect from such
Holder (in substantially the form set forth in the Transfer
Certificate); or
(B) if such Restricted Certificated Security is being
transferred pursuant to (i) an exemption from the registration
requirements of the Securities Act in accordance with Rule 144 or
(ii) pursuant to an exemption from the registration requirements
of the Securities Act (other than pursuant to Rule 144A or Rule
144) and as a result of which, in the case of a Security
transferred pursuant to this clause (ii), such Security shall
cease to be a "restricted security"
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within the meaning of Rule 144, a certification to that effect
from such Holder, and, if the Company or the Registrar so
requests, a customary opinion of counsel, certificates and other
information reasonably acceptable to the Company and the Trustee
to the effect that such transfer is in compliance with the
Securities Act;
(5) in the case of a Restricted Certificated Security to be
transferred or exchanged for a beneficial interest in a Restricted Global
Security, such request shall be accompanied by a certification from such
Holder and, in the case of clause (i), the transferee (in substantially the
form set forth in the Transfer Certificate) to the effect that such
Restricted Certificated Security is being transferred to (i) a person the
Holder reasonably believes is a QIB (which, in the case of an exchange,
shall be such Holder) in accordance with Rule 144A or (ii) a non-U.S.
person in an offshore transaction under Regulation S under the Securities
Act; and
(6) in the case of an Unrestricted Certificated Security to be
transferred or exchanged for a beneficial interest in an Unrestricted
Global Security, such request need not be accompanied by any additional
information or documents.
(e) Legends.
(1) Except as permitted by the following paragraphs (2) and (3) of
this Section 102(e), each Global Security and Certificated Security (and
all Securities issued in exchange therefor or upon registration of transfer
or replacement thereof and any Common Stock issuable upon conversion
thereof) shall bear a legend in substantially the form called for by
footnote 2 to Annex A hereto (each a "Transfer Restricted Security") for so
long as such Security or Common Stock issuable upon conversion thereof is
required by this Indenture to bear such legend. Each Transfer Restricted
Security shall have attached thereto a certificate (a "Transfer
Certificate") in substantially the form called for by footnote 6 to Annex A
hereto.
(2) Upon any sale or transfer of a Transfer Restricted Security (x)
pursuant to Rule 144, (y) pursuant to an effective registration statement
under the Securities Act or (z) pursuant to any other available exemption
(other than Rule 144A) from the registration requirements of the Securities
Act and as a result of which, in the case of a Security transferred
pursuant to this clause (z), such Security shall cease to be a "restricted
security" within the meaning of Rule 144:
(A) in the case of any Restricted Certificated Security, any
Registrar shall permit the Holder thereof to exchange such Restricted
Certificated Security for an Unrestricted Certificated Security, or
(under the circumstances described in Section 102(d) hereof) to
transfer such Restricted Certificated Security to a transferee who
shall take such Security in the form of a beneficial interest in an
Unrestricted Global Security, and in each case shall rescind any
restriction on the transfer of such Security; provided, however, that
the Holder of such Restricted Certificated Security shall, in
connection with such exchange or transfer, comply with the other
applicable provisions of this Section 102; and
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(B) in the case of any beneficial interest in a Restricted Global
Security, the Trustee shall permit the beneficial owner thereof to
transfer such beneficial interest to a transferee who shall take such
interest in the form of a beneficial interest in an Unrestricted
Global Security and shall rescind any restriction on transfer of such
beneficial interest; provided, however, that such Unrestricted Global
Security shall continue to be subject to the provisions of Section
102(a)(2) hereof; and provided further, however, that the owner of
such beneficial interest shall, in connection with such transfer,
comply with the other applicable provisions of this Section 102.
(3) Upon the exchange, registration of transfer or replacement of
Securities not bearing the legend described in paragraph (1) of this
Section 102(e) above, the Company shall execute and the Trustee shall
authenticate and deliver Securities that do not bear such legend and which
do not have a Transfer Certificate attached thereto.
(f) Transfers to the Company. Nothing in this Indenture or in the
Securities shall prohibit the sale or other transfer of any Securities
(including beneficial interests in Global Securities) to the Company or any of
its Subsidiaries, which Securities shall thereupon be canceled in accordance
with Section 309 of the Indenture.
Section 103 Amount.
(a) The Trustee shall authenticate and deliver 2021 Debentures for
original issue in an aggregate Principal Amount of up to $1,766,500,000.00 upon
Company Order for the authentication and delivery of 2021 Debentures, without
any further action by the Company; provided, however, that if the Company sells
any Securities pursuant to the over-allotment option (the "Option") granted to
the Initial Purchaser pursuant to Section 3 of the Purchase Agreement, then the
Trustee shall authenticate and deliver Securities for original issue in an
aggregate Principal Amount of up to $1,766,500,000.00 plus up to an additional
aggregate Principal Amount of up to $441,625,000.00 of Securities sold pursuant
to the Option upon a Company Order. The aggregate Principal Amount of 2021
Debentures that may be authenticated and delivered under the Indenture may not
exceed the amount set forth in the foregoing sentence, except for 2021
Debentures authenticated and delivered (1) upon registration of transfer of, or
in exchange for, or in lieu of, other 2021 Debentures pursuant to Sections 204,
304, 305, 306, 906 and 1107, of the Indenture and Sections 1402, 1511 and 1604
hereof or (2) upon any reopening effected in accordance with the fourth
paragraph of Section 301 of the Indenture.
(b) The Company may not issue new 2021 Debentures to replace 2021
Debentures that it has paid or delivered to the Trustee for cancellation or that
any Holder has converted pursuant to Article FOURTEEN hereof.
Section 104 Accrual of Original Issue Discount; Interest.
The 2021 Debentures shall be Original Issue Discount Securities.
Original Issue Discount shall accrue with respect to the 2021 Debentures at the
rate set forth under the caption "Interest" in the 2021 Debentures, commencing
on the Issue Date of the 2021 Debentures. Except (a) as provided under the
caption "Tax Event" in the 2021 Debentures and in Article
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SEVENTEEN hereof and (b) for Additional Interest that may become payable as
contemplated in Section 105 hereof, there shall be no periodic payments of
interest on the 2021 Debentures.
Section 105 Additional Interest.
Additional Interest with respect to the 2021 Debentures shall be
payable in accordance with the provisions and in the amounts set forth in the
Section 5 of the Registration Rights Agreement.
Section 106 Denominations.
The 2021 Debentures shall be in fully registered form without coupons
in denominations of $1,000 of Principal Amount or any integral multiple thereof.
Section 107 Place of Payment.
The Place of Payment for the 2021 Debentures and the place or places
where the 2021 Debentures may be surrendered for registration of transfer,
exchange, repurchase, redemption or conversion and where notices may be given to
the Company in respect of the 2021 Debentures is at the office or agency of the
Trustee in New York, New York; provided, however, that payment of interest may
be made at the option of the Company by check mailed to the address of the
Person entitled thereto as such address shall appear in the Security Register
(as defined in the Indenture). Payments in respect of the 2021 Debentures
evidenced by a Global Security shall be made by transfer of immediately
available funds to the accounts specified by the Holder of the Global Security.
Section 108 Redemption.
(a) There shall be no sinking fund for the retirement of the 2021
Debentures.
(b) The Company, at its option, may redeem the 2021 Debentures in
accordance with the provisions of and at the Redemption Prices set forth under
the captions "Optional Redemption" and "Notice of Redemption" in the 2021
Debentures and in accordance with the provisions of the Indenture, including,
without limitation, Article ELEVEN.
Section 109 Conversion.
The 2021 Debentures shall be convertible in accordance with the
provisions and at the Conversion Rate set forth under the caption "Conversion"
in the 2021 Debentures and in accordance with the provisions of the Indenture,
including, without limitation, Article FOURTEEN hereof.
Section 110 Maturity.
The date on which the principal of the 2021 Debentures matures and is
payable, unless accelerated or required to be repurchased pursuant to the
Indenture, shall be February 28, 2021.
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Section 111 Repurchase.
(a) The 2021 Debentures shall be repurchased by the Company in
accordance with the provisions and at the Purchase Prices set forth under the
caption "Repurchase by the Company at the Option of the Holder" in the 2021
Debentures and in accordance with the provisions of the Indenture, including,
without limitation, Article FIFTEEN hereof.
(b) The 2021 Debentures shall be repurchased by the Company in
accordance with the provisions of and at the Change in Control Purchase Prices
set forth under the caption "Purchase of Securities at Option of Holder Upon a
Change in Control" in the 2021 Debentures and in accordance with the provisions
of the Indenture, including, without limitation, Article SIXTEEN hereof.
Section 112 Covenants.
The 2021 Debentures shall benefit from each of the covenants set forth
in Article TEN of the Indenture, including, without limitation, Sections 1006
("Limitations on Liens") and 1007 ("Limitations on Sale-Leaseback Transactions")
of the Indenture, and the related definitions set forth in Section 101 of the
Indenture.
Section 113 Amount Due Upon Event of Default.
The portion of the Principal Amount of each 2021 Debenture that shall
become due pursuant to Section 502 of the Indenture in the circumstances
specified therein upon an Event of Default shall be the Issue Price plus accrued
Original Issue Discount on such 2021 Debentures (or, if the 2021 Debentures have
been converted to interest bearing 2021 Debentures pursuant to Section 1701, the
Restated Principal Amount and all accrued and unpaid interest thereon from the
later of the date of conversion and the date on which interest was last paid or
duly provided for).
Section 114 Discharge of Liability on 2021 Debentures.
The 2021 Debentures may be discharged by the Company in accordance with
the provisions of Article THIRTEEN of the Indenture.
Section 115 Other Terms of 2021 Debentures.
Without limiting the foregoing provisions of this Article I, the terms
of the 2021 Debentures shall be as set forth in the form of the 2021 Debentures
set forth in Annex A hereto and as provided in the Indenture.
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ARTICLE II
AMENDMENTS TO THE INDENTURE
Section 201 Amendments Applicable Only to 2021 Debentures.
The amendments contained herein shall apply to the 2021 Debentures only
and not to any other series of Security issued under the Indenture and any
covenants provided herein are expressly being included solely for the benefit of
the 2021 Debentures and not for the benefit of any other series of Securities
issued under the Indenture. The amendments contained herein shall be effective
for so long as any 2021 Debentures remain Outstanding.
Section 202 Definitions.
Section 101 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by inserting or
restating, as the case may be, in their appropriate alphabetical position, the
following definitions:
"Additional Interest" shall have the meaning set forth in Section 5(a)
of the Registration Rights Agreement.
"Agent Members" has the meaning specified in Section 101(b) hereof.
"Applicable Procedures" means, with respect to any transfer or exchange
of beneficial ownership interests in a Global Security, the rules and procedures
of the Depositary that are applicable to such transfer or exchange.
"Beneficial Owner" has the meaning specified in Section 1601(a) hereof.
"Certificated Security" means a Security that is in substantially the
form attached hereto as Annex A and that does not include the information or the
schedule called for by footnotes 1, 4 and 5 thereof.
"Change in Control" has the meaning specified in Section 1601(a)
hereof.
"Change in Control Purchase Date" has the meaning specified in Section
1601(a) hereof.
"Change in Control Purchase Notice" has the meaning specified in
Section 1601(c) hereof.
"Change in Control Purchase Price" has the meaning specified in Section
1601(a) hereof.
"Common Stock" means any stock of any class of the Company (including,
without limitation, the Company's common stock, par value $3.00 per share) which
has no preference in respect of dividends or of amounts payable in the event of
any voluntary or involuntary liquidation, dissolution or winding up of the
Company and which is not subject to redemption by the Company. References herein
or in the 2021 Debentures to a number of shares of Common
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Stock shall include a reference to a corresponding number of preferred share
purchase rights issued under Rights Agreement.
"Company Notice Date" has the meaning specified in Section 1503 hereof.
"Conversion Agent" shall be the person designated as such in Section
101(c) hereof and, with respect to the 2021 Debentures, shall have the duties
and responsibilities specified in Article FOURTEEN hereof. The Company may
appoint such other Person(s) from time to time to serve as a Conversion Agent,
such appointment to be effected by notice delivered by the Company to the
Trustee.
"Conversion Date" has the meaning specified in Section 1402 hereof.
"Conversion Rate" has the meaning specified in Section 1401 hereof.
"CSFB" has the meaning specified in Section 101(a) hereof.
"Depositary" has the meaning specified in Section 101(a) hereof.
"Determination Date" has the meaning specified in Section 1406(d)(1)
hereof.
"DTC" has the meaning specified in Section 101 hereof.
"Expiration Date" has the meaning specified in Section 1406(d)(2)
hereof.
"Expiration Time" has the meaning specified in Section 1406(d)(2)
hereof.
"Global Security" means a permanent Global Security that is in
substantially the form attached hereto as Annex A and that includes the
information and schedule called for by footnotes 1, 4 and 5 thereof and which is
deposited with the Depositary or the Security Custodian and registered in the
name of the Depositary or its nominee.
"Group" has the meaning specified in Section 1601(a) hereof.
"Indenture" has the meaning specified in the recitals.
"Initial Purchaser" has the meaning specified in Section 101(a) hereof.
"Issue Date" of any 2021 Debenture means the date on which the 2021
Debenture was originally issued or deemed issued as set forth on the face of the
2021 Debenture.
"Issue Price" of any 2021 Debenture means, in connection with the
original issuance of such 2021 Debenture, the original initial issue price at
which the 2021 Debenture is sold as set forth on the face of the 2021 Debenture.
"Market Price" has the meaning specified in Section 1504 hereof.
"non-electing share" has the meaning specified in Section 1411 hereof.
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"NYSE" has the meaning specified in Section 1406(e) hereof.
"Nasdaq" has the meaning set forth in Section 1406(e) hereof.
"Option Exercise Date" has the meaning specified in Section 1701
hereof.
"Original Issue Discount" of any 2021 Debenture means the difference
between the Issue Price and the Principal Amount of the 2021 Debenture as set
forth on the face of the 2021 Debenture.
"Permitted Amount" has the meaning specified in Section 1406(d)(1) or
1406(d)(2), as the case may be.
"Principal Amount" of a 2021 Debenture means the principal amount due
at the Stated Maturity of the 2021 Debentures as set forth on the face of the
2021 Debenture.
"Purchase Agreement" means the Purchase Agreement, dated as of February
22, 2001, between the Company and Credit Suisse First Boston Corporation.
"Purchased Shares" has the meaning specified in Section 1406(d)(2)
hereof.
"QIB" has the meaning specified in Section 101 hereof.
"Registration Rights Agreement" means the Registration Rights
Agreement, dated as of February 22, 2001, between the Company and Credit Suisse
First Boston Corporation.
"Regulation S" means Regulation S of the rules and regulations
promulgated under the Securities Act or any successor to such Regulation.
"Repurchase Date" has the meaning specified in Section 1501 hereof.
"Repurchase Notice" has the meaning specified in Section 1501 hereof.
"Repurchase Price" has the meaning specified in Section 1501 hereof.
"Restated Principal Amount" has the meaning specified in Section 1701
hereof.
"Restricted Certificated Security" means a Certificated Security which
is a Transfer Restricted Security.
"Restricted Global Security" means a Global Security that is a Transfer
Restricted Security.
"Rights Agreement" means the Amended and Restated Preferred Share
Purchase Rights Agreement, dated as of January 20, 1999, between the Company and
BankBoston, N.A., as rights agent, as same may be amended, modified or restated
while any of the 2021 Debentures remain outstanding.
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"Rule 144" means Rule 144 of the rules and regulations promulgated
under the Securities Act or any successor to such Rule.
"Rule 144A" means Rule 144A of the rules and regulations promulgated
under the Securities Act or any successor to such Rule.
"Sale Price" has the meaning specified in Section 1504 hereof.
"Securities" means any securities authenticated and delivered under the
Indenture, as the same may be amended or supplemented, including 2021
Debentures.
"Securities Act" means the Securities Act of 1933, as amended, or any
successor statute.
"Tax Event" means that the Company shall have received an opinion from
independent tax counsel experienced in such matters to the effect that, on or
after February 28, 2001, as a result of (a) any amendment to, or change
(including any announced prospective change) in, the laws (or any regulations
thereunder) of the United States or any political subdivision or taxing
authority thereof or therein or (b) any amendment to, or change in, an
interpretation or application of such laws or regulations by any legislative
body, court, governmental agency or regulatory authority, in each case, which
amendment or change is enacted, promulgated, issued or announced or which
interpretation is issued or announced or which action is taken, on or after
February 28, 2001, there is more than an insubstantial risk that interest
(including Original Issue Discount) payable on the 2021 Debentures either (i)
would not be deductible on a current accrual basis or (ii) would not be
deductible under any other method, in either case, in whole or in part, by the
Company (by reason of deferral, disallowance or otherwise) for United States
Federal income tax purposes.
"Tax Event Date" has the meaning specified in Section 1701 hereof.
"tender offer" has the meaning specified in Section 1406(d)(3) hereof.
"Trading Day" means a day during (i) which trading in securities
generally occurs on the NYSE or, if the Common Stock is not listed for trading
on the NYSE, on the principal other national or regional securities exchange on
which the Common Stock is then listed for trading or, if the Common Stock is not
listed for trading on a national or regional securities exchange, on the Nasdaq
or, if the Common Stock is not quoted on the Nasdaq, on the other principal
market on which the Common Stock is then traded and (ii) trading in the Common
Stock is not then suspended on the NYSE or such principal national or regional
securities exchange, Nasdaq or other principal market, as the case may be, on
which the Common Stock is then traded.
"Transfer Certificate" has the meaning specified in Section 102(e)(1)
hereof.
"Transfer Restricted Securities" has the meaning specified in Section
102(e)(1) hereof.
"Trigger Event" has the meaning specified in Section 1406(c) hereof.
"Triggering Distribution" has the meaning specified in Section
1406(d)(1) hereof.
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"2021 Debentures" has the meaning specified in the recitals.
"Unrestricted Certificated Security" means a Certificated Security
which is not a Transfer Restricted Security.
"Unrestricted Global Security" means a Global Security which is not a
Transfer Restricted Security.
Section 203 Definition of Outstanding.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by (a) deleting "and" at the end
of clause (3) of the definition of the term "Outstanding" in Section 101 of the
Original Indenture, (b) deleting the period and inserting "; and" at the end of
clause (4) of the definition of the term "Outstanding" in Section 101 of the
Original Indenture and (c) inserting the following as clause (5) of the
definition of the term "Outstanding" in Section 101 of the Original Indenture:
(5) 2021 Debentures that have been converted into Common Stock in
accordance with Section 1402 hereof.
Section 204 Registration, Registration of Transfer and Exchange.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by replacing the seventh paragraph
of Section 305 of the Original Indenture with the following paragraph:
The Company shall not be required (i) to issue, register the transfer
of or exchange the 2021 Debentures during a period beginning at the
opening of business 15 days before the day of the mailing of a notice
of redemption of 2021 Debentures selected for redemption and ending at
the close of business on the day of such mailing, (ii) to register the
transfer of or exchange any 2021 Debenture so selected for redemption
in whole or in part, except the unredeemed portion of any Security
being redeemed in part, or (iii) to exchange or register a transfer of
any 2021 Debenture or portions thereof in respect of which a Change in
Control Purchase Notice or Repurchase Notice has been delivered and not
withdrawn by the Holder thereof (except, in the case of the purchase of
a 2021 Debenture in part, the portion not to be purchased or which has
been surrendered for conversion).
Section 205 Mutilated, Destroyed, Lost and Stolen Securities.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by replacing the third paragraph
of Section 306 of the Original Indenture with the following paragraph:
If any such mutilated, destroyed, lost or stolen Security constitutes a
2021 Debenture that has or is about to become due and payable, or is
about to be purchased by the Company on a Repurchase Date pursuant to
Article FIFTEEN,
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or purchased by the Company upon a Change in Control pursuant to
Article SIXTEEN, the Company in its discretion may, instead of issuing
a new Security, pay such Security.
Section 206 Payment of Interest; Interest Rights Preserved.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by inserting the following
paragraph as the second paragraph of Section 307 of the Original Indenture:
If the Company exercises its option pursuant to Section 1701, then in
the case of any 2021 Debenture or portion thereof which is surrendered
for conversion after the close of business on the Regular Record Date
immediately preceding any Interest Payment Date and prior to the
opening of business on such next succeeding Interest Payment Date
(unless such 2021 Debenture or portion thereof which is being
surrendered for conversion has been called for redemption on a
Redemption Date within such period), interest whose Stated Maturity is
on such Interest Payment Date shall be payable on such Interest Payment
Date notwithstanding such conversion, and such interest (whether or not
punctually paid or duly provided for) shall be paid to the Person in
whose name that 2021 Debenture (or one or more Predecessor Securities)
is registered at the close of business on such Regular Record Date;
provided, however, that such payment of interest shall be subject to
the payment to the Company by the Holder of such 2021 Debenture or
portion thereof surrendered for conversion (such payment to accompany
such surrender) of an amount equal to the amount of such interest, in
accordance with Section 1402. Except as otherwise provided in the
immediately preceding sentence, in the case of any 2021 Debenture which
is converted, interest whose Stated Maturity is after the date of
conversion of such 2021 Debenture shall not be payable.
Section 207 Cancellation.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by inserting "conversion," after
"redemption," in the first sentence of Section 309 of the Original Indenture.
Section 208 Redemption.
(a) Article ELEVEN of the Original Indenture is hereby amended, subject
to Section 201 hereof and with respect to the 2021 Debentures only, by (1)
replacing "30" in Section 1104 with "15" and (2) deleting and "at the end of
clause (5) of the second paragraph of Section 1104, deleting the period at the
end of clause (6) of such second paragraph and inserting ", and" in its place
and inserting the following as clause (7) of such second paragraph:
(7) the Conversion Rate and the last date on which 2021
Debentures may be surrendered for conversion prior to redemption.
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(b) Article ELEVEN of the Original Indenture is hereby amended, subject
to Section 201 hereof and with respect to the 2021 Debentures only, by inserting
the following as Section 1108:
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Section 1108 Conversion Arrangement on Call for Redemption.
In connection with 2021 Debentures, the Company may arrange for the
purchase and conversion of any 2021 Debentures called for redemption by
an agreement with one or more investment bankers or other purchasers to
purchase such 2021 Debentures by paying to a Paying Agent (other than
the Company or any of its Affiliates) in trust for the Holders, on or
before 11:00 a.m. New York City time on the Redemption Date, an amount
that, together with any amounts deposited with such Paying Agent by the
Company for the redemption of such 2021 Debentures, is not less than
the Redemption Price of such 2021 Debentures. Notwithstanding anything
to the contrary contained in this Article ELEVEN, the obligation of the
Company to pay the Redemption Price of such 2021 Debentures, including
interest, if any, shall be deemed to be satisfied and discharged to the
extent such amount is so paid by such purchasers; provided, however,
that nothing in this Section 1108 shall relieve the Company of its
obligation to pay the Redemption Price on 2021 Debentures called for
redemption. If such an agreement is entered into, any 2021 Debentures
called for redemption and not surrendered for conversion by the Holders
thereof prior to the relevant Redemption Date may, at the option of the
Company upon written notice to the Trustee, be deemed, to the fullest
extent permitted by law, acquired by such purchasers from such Holders
and (notwithstanding anything to the contrary contained in Article
ELEVEN) surrendered by such purchasers for conversion, all as of 11:00
a.m. New York City time on the Redemption Date, subject to payment of
the above amount as aforesaid. The Paying Agent shall hold and pay to
the Holders whose 2021 Debentures are selected for redemption any such
amount paid to it for purchase in the same manner as it would money
deposited with it by the Company for the redemption of 2021 Debentures.
Without the Paying Agent's prior written consent, no arrangement
between the Company and such purchasers for the purchase and conversion
of any 2021 Debentures shall increase or otherwise affect any of the
powers, duties, responsibilities or obligations of the Paying Agent as
set forth in this Indenture, and the Company agrees to indemnify the
Paying Agent from, and hold it harmless against, any loss, liability or
expense arising out of or in connection with any such arrangement for
the purchase and conversion of any 2021 Debentures between the Company
and such purchasers, including, without limitation, the costs and
expenses incurred by the Paying Agent in the defense of any claim or
liability reasonably incurred without negligence or bad faith on its
part arising out of or in connection with the exercise or performance
of any of its powers, duties, responsibilities or obligations under
this Indenture, in accordance with the indemnity provisions applicable
to the Trustee set forth herein.
Section 209 Consolidation, Merger and Sale.
Section 801 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by replacing
clause (1) of such Section 801 with the following:
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(1) (A) in the case of a merger, the Company is the surviving
entity, or (B) the Person formed by such consolidation or into which
the Company is merged or the Person which acquires by sale or transfer,
or which leases, the properties and assets of the Company as, or
substantially as, an entirety shall expressly assume, by an indenture
supplemental hereto, executed and delivered to the Trustee, in form
reasonably satisfactory to the Trustee, the due and punctual payment of
the principal of and any premium and interest on, and Additional
Interest with respect to, all the Securities and the performance or
observance of every covenant and condition of this Indenture on the
part of the Company to be performed or observed and shall have
expressly provided for conversion rights in accordance with Section
1411.
Section 210 Defaults and Remedies.
Section 501 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by deleting
subsections (1) and (2), and inserting instead the following as new subsections
(1) and (2) thereof:
(1) the Company defaults in the payment of any interest upon
any 2021 Debenture, when it becomes due and payable, after conversion
of the 2021 Debentures to interest bearing debentures pursuant to
Section 1701, or in any payment of Additional Interest when it becomes
due and payable, and the continuance of any such default for a period
of 30 days; or
(2) the Company defaults in the payment of the Principal
Amount (or, if the 2021 Debentures have been converted to
interest-bearing 2021 Debentures pursuant to Section 1701, the Restated
Principal Amount), the Issue Price plus accrued Original Issue
Discount, the Redemption Price, the Repurchase Price or the Change in
Control Purchase Price of any 2021 Debenture when the same becomes due
and payable; or
Section 211 Collection of Indebtedness and Suits for Enforcement by Trustee.
Section 503 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by deleting
subsections (1) and (2) of the first paragraph, and inserting instead the
following as new subsections (1) and (2) thereof:
(1) the Company defaults in the payment of any interest upon
any 2021 Debentures, when it becomes due and payable, after conversion
of the 2021 Debentures to interest bearing debentures pursuant to
Section 1701, or in any payment of Additional Interest when it becomes
due and payable, and the continuance of any such default for a period
of 30 days, or
(2) the Company defaults in the payment of the Principal
Amount (or, if the 2021 Debentures have been converted to
interest-bearing 2021 Debentures pursuant to Section 1701, the Restated
Principal Amount), the Issue Price plus accrued Original Issue
Discount, the Redemption Price, the Repurchase Price or
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the Change in Control Purchase Price of any 2021 Debentures when the
same becomes due and payable,
Section 212 Unconditional Right of Holders to Receive Principal, Premium and
Interest.
Section 508 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by replacing
that Section with the following:
SECTION 508 Rights of Holders to Receive Payment.
Notwithstanding any other provision in this Indenture, the right of any
Holder of a Security to receive payment of the principal of and
(subject to Sections 307 and 1701) interest on such Security on or
after the respective due dates expressed in such Security (or in the
case of redemption, to receive the Redemption Price on the Redemption
Date, in the case of a repurchase, to receive the Repurchase Price on
the Repurchase Date, or in the case of a Change in Control, to receive
the Change in Control Purchase Price on the Change in Control Purchase
Date), or to institute suit for the enforcement of any such payment on
or after such respective dates, is absolute and unconditional and shall
not be impaired without the consent of the Holder.
Section 213 Supplemental Indentures Without Consent of Holders.
Section 901 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by deleting
"or" at the end of clause (7) of Section 901, by deleting the period and
inserting "; or" at the end of clause (8) and by inserting the following
paragraph as clause (9) of Section 901:
(9) to make provision with respect to the conversion rights, if
any, to Holders of 2021 Debentures pursuant to the requirements of
Article FOURTEEN hereof.
Section 214 Supplemental Indenture with Consent of Holder.
Section 902 of the Original Indenture is hereby amended, subject to
Section 201 hereof and with respect to the 2021 Debentures only, by deleting
"or" at the end of clause (3) of Section 902, by deleting the period and
inserting "; or" at the end of clause (4) of Section 902 and by inserting the
following as clause (5) of Section 902:
(5) adversely affect the right to convert any 2021 Debenture as
provided in Article FOURTEEN, or adversely affect the right to require
the Company to repurchase the 2021 Debentures as provided in Article
FIFTEEN or Article SIXTEEN.
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Section 215 Maintenance of Office or Agency.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by inserting "or conversion" after
"payment" in the first sentence of Section 1002 of the Original Indenture.
Section 216 Conversion, Tax Event, Repurchase.
The Original Indenture is hereby amended, subject to Section 201 hereof
and with respect to the 2021 Debentures only, by adding the following Articles
FOURTEEN, FIFTEEN, SIXTEEN and SEVENTEEN to the Original Indenture:
ARTICLE FOURTEEN
CONVERSION
Section 1401 Conversion Privilege.
(a) The 2021 Debentures shall be convertible in accordance
with their terms and in accordance with this Article FOURTEEN.
(b) A Holder of a 2021 Debenture may convert the Principal
Amount of such 2021 Debenture (or any portion thereof equal to a
Principal Amount of $1,000 or any integral multiple of a Principal
Amount of $1,000 in excess thereof) into Common Stock, at any time
prior to the close of business on the date specified in the 2021
Debentures, at the Conversion Rate then in effect. In case a 2021
Debenture or portion thereof is called for redemption pursuant to
Article ELEVEN, such conversion right shall terminate at the close of
business on the Business Day immediately preceding the Redemption Date
for such 2021 Debenture or such earlier date as the Holder presents
such 2021 Debenture for redemption (unless the Company shall default in
making the redemption payment when due, in which case the conversion
right shall terminate at the close of business on the date such default
is cured and such 2021 Debenture is redeemed). The number of shares of
Common Stock issuable upon conversion of a 2021 Debenture per $1,000 of
Principal Amount thereof (the "Conversion Rate") shall be that number
set forth under "Conversion" in the 2021 Debentures, subject to
adjustment as herein set forth. Provisions of this Indenture that apply
to conversion of all of a 2021 Debenture also apply to conversion of a
portion of a 2021 Debenture.
(c) A 2021 Debenture in respect of which a Holder has
delivered a Repurchase Notice or Change in Control Purchase Notice
exercising the option of such Holder to require the Company to purchase
such 2021 Debenture, may be converted only if such notice of exercise
is withdrawn in accordance with the terms of this Indenture. A Holder
of 2021 Debentures is not entitled to any rights of a holder of Common
Stock until such Holder has converted its 2021 Debentures to Common
Stock, and only to the extent such 2021 Debentures are
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deemed to have been converted into Common Stock pursuant to this
Article FOURTEEN.
SECTION 1402 Conversion Procedure.
To convert a 2021 Debenture, a Holder must (a) complete and manually
sign the conversion notice on the back of the 2021 Debenture and
deliver such notice to a Conversion Agent, (b) surrender the 2021
Debenture to a Conversion Agent, (c) furnish appropriate endorsements
and transfer documents if required by the Security Registrar or a
Conversion Agent, and (d) pay any transfer or similar tax, if required.
The date on which the Holder satisfies all of those requirements is the
"Conversion Date." As soon as practicable after the Conversion Date,
the Company shall deliver to the Holder through a Conversion Agent a
certificate for the number of whole shares of Common Stock issuable
upon the conversion and cash in lieu of any fractional shares pursuant
to Section 1403. Anything herein to the contrary notwithstanding, in
the case of Global Securities, conversion notices may be delivered and
such 2021 Debentures may be surrendered for conversion in accordance
with the applicable procedures of the Depositary as in effect from time
to time. The Person in whose name the Common Stock certificate is
registered shall be deemed to be a stockholder of record on the
Conversion Date; provided, however, that no surrender of a 2021
Debenture on any date when the stock transfer books of the Company
shall be closed shall be effective to constitute the Person or Persons
entitled to receive the shares of Common Stock upon such conversion as
the record holder or holders of such shares of Common Stock on such
date, but such surrender shall be effective to constitute the Person or
Persons entitled to receive such shares of Common Stock as the record
holder or holders thereof for all purposes at the close of business on
the next succeeding day on which such stock transfer books are open;
provided further, however, that such conversion shall be at the
Conversion Rate in effect on the date that such 2021 Debenture shall
have been surrendered for conversion, as if the stock transfer books of
the Company had not been closed. Upon conversion of a 2021 Debenture,
such Person shall no longer be a Holder of the 2021 Debenture so
converted.
No payment or adjustment will be made for dividends on, or other
distributions with respect to, any Common Stock except as provided in
this Article FOURTEEN. On conversion of a 2021 Debenture, that portion
of accrued Original Issue Discount (and unpaid interest, if the Company
has exercised its option provided for in Section 1701 hereof)
attributable to the period from the Issue Date (or, in the case of
interest, if the Company has exercised the option provided for in
Section 1701 hereof, the later of (x) the Option Exercise Date and (y)
the date on which interest was last paid or duly provided for) of the
2021 Debenture through the Conversion Date with respect to the
converted 2021 Debenture shall not be cancelled, extinguished or
forfeited, but rather shall be deemed to be paid in full to the Holder
thereof through delivery of the Common Stock (together with the cash
payment, if any, in lieu of fractional shares) in exchange for the 2021
Debenture being converted pursuant to the provisions
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hereof; and the fair market value of such shares of Common Stock
(together with any such cash payment in lieu of fractional shares)
shall be treated as issued, to the extent thereof, first in exchange
for Original Issue Discount (and unpaid interest, if the Company has
exercised its option provided for in Section 1701 hereof) accrued
through the Conversion Date, and the balance, if any, of such fair
market value of such Common Stock (and any such cash payment) shall be
treated as issued in exchange for the Issue Price (or Restated
Principal Amount, if the Company has exercised its option provided for
in Section 1701) of the 2021 Debenture being converted pursuant to the
provisions hereof. Each whole share of Common Stock issued upon
conversion of any 2021 Debenture shall be accompanied by a preferre
share purchase right issued under the Rights Agreement, if the Rights
Agreement is then in effect notwithstanding the occurrence of any
event that, under the terms of the Rights Agreements, results in the
separation of rights from the Common Stock.
If a Holder converts more than one 2021 Debenture at the same time, the
number of shares of Common Stock issuable upon the conversion shall be
based on the aggregate Principal Amount of 2021 Debentures so
converted.
Upon surrender of a 2021 Debenture that is converted in part, the
Company shall execute, and the Trustee shall authenticate and deliver
to the Holder, a new 2021 Debenture equal in Principal Amount to the
Principal Amount of the unconverted portion of the 2021 Debenture
surrendered.
If the Company has exercised its option under Section 1701, 2021
Debentures or portions thereof surrendered for conversion during the
period from the close of business on any Regular Record Date
immediately preceding any Interest Payment Date to the opening of
business on such Interest Payment Date shall (unless such 2021
Debentures or portions thereof have been called for redemption on a
Redemption Date within such period) be accompanied by payment to the
Company or its order, in New York Clearing House funds or other funds
acceptable to the Company, of an amount equal to the interest payable
on such Interest Payment Date on the principal amount of 2021
Debentures or portions thereof being surrendered for conversion.
SECTION 1403 Fractional Shares.
The Company will not issue fractional shares of Common Stock upon
conversion of 2021 Debentures. In lieu of such fractional shares, the
Company will pay an amount in cash based upon the closing price
(determined as provided in Section 1406(e)) of the Common Stock on the
Trading Day immediately prior to the Conversion Date.
SECTION 1404 Taxes on Conversion.
If a Holder converts a 2021 Debenture, the Company shall pay any
documentary, stamp or similar issue or transfer tax due on the issue of
shares of Common Stock
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upon such conversion. However, the Holder shall pay any such tax which
is due because the Holder requests the shares to be issued in a name
other than the Holder's name. The Conversion Agent may refuse to
deliver the certificate representing the Common Stock being issued in
a name other than the Holder's name until the Conversion Agent
receives a sum sufficient to pay any tax which will be due because the
shares are to be issued in a name other than the Holder's name.
Nothing herein shall preclude any tax withholding required by law or
regulation.
SECTION 1405 Company to Provide Common Stock.
The Company shall, prior to issuance of any 2021 Debentures under this
Indenture, and from time to time as may be necessary, reserve, out of
its authorized but unissued Common Stock, a sufficient number of shares
of Common Stock to permit the conversion of all 2021 Debentures
Outstanding into shares of Common Stock. All shares of Common Stock
delivered upon conversion of the 2021 Debentures shall be duly
authorized, validly issued, fully paid and nonassessable and shall be
free from preemptive rights and free of any Lien or adverse claim.
The Company will endeavor promptly to comply with all federal and state
securities laws regulating the registration of the offer, issuance and
delivery of shares of Common Stock to a converting Holder upon
conversion of 2021 Debentures, if any, and will list or cause to have
quoted such shares of Common Stock on each national securities exchange
or on the Nasdaq National Market or other over-the-counter market or
such other market on which the shares of Common Stock are then listed
or quoted.
SECTION 1406 Adjustment of Conversion Rate.
The Conversion Rate shall be adjusted from time to time by the Company
as follows:
(a) If the Company shall (i) pay a dividend on its Common
Stock in shares of Common Stock, (ii) make a distribution on its Common
Stock in shares of Common Stock, (iii) subdivide its outstanding Common
Stock into a greater number of shares, or (iv) combine its outstanding
Common Stock into a smaller number of shares, the Conversion Rate in
effect immediately prior thereto shall be adjusted so that the Holder
of any 2021 Debenture thereafter surrendered for conversion shall be
entitled to receive that number of shares of Common Stock which it
would have owned had such 2021 Debenture been converted immediately
prior to the happening of such event. An adjustment made pursuant to
this subsection (a) shall become effective immediately after the record
date in the case of a dividend or distribution and shall become
effective immediately after the effective date in the case of
subdivision or combination.
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(b) If the Company shall issue rights or warrants to all or
substantially all holders of its Common Stock entitling them (for a
period commencing no earlier than the record date described below and
expiring not more than 60 days after such record date) to subscribe for
or purchase shares of Common Stock (or securities convertible into
Common Stock) at a price per share (or having a conversion price per
share) less than the current market price per share of Common Stock (as
determined in accordance with Section 1406(e)) on the record date for
the determination of stockholders entitled to receive such rights or
warrants, the Conversion Rate in effect immediately prior thereto shall
be adjusted so that the same shall equal the rate determined by
multiplying the Conversion Rate in effect immediately prior to such
record date by a fraction, of which the numerator shall be the number
of shares of Common Stock outstanding on such record date plus the
number of additional shares of Common Stock offered (or into which the
convertible securities so offered are convertible), and of which the
denominator shall be the number of shares of Common Stock outstanding
on such record date plus the number of shares which the aggregate
offering price of the total number of shares of Common Stock so offered
(or the aggregate conversion price of the convertible securities so
offered, which shall be determined by multiplying the number of shares
of Common Stock issuable upon conversion of such convertible securities
by the conversion price per share of Common Stock pursuant to the terms
of such convertible securities) would purchase at the current market
price per share (as determined in accordance with Section 1406(e)) of
Common Stock on such record date. Such adjustment shall be made
successively whenever any such rights or warrants are issued, and shall
become effective immediately after such record date. If at the end of
the period during which such rights or warrants are exercisable not all
rights or warrants shall have been exercised, the adjusted Conversion
Rate shall be immediately readjusted to what it would have been based
upon the number of additional shares of Common Stock actually issued
(or the number of shares of Common Stock issuable upon conversion of
convertible securities actually issued).
(c) If the Company shall (by dividend or otherwise) distribute
to all or substantially all holders of its Common Stock any shares of
capital stock (other than dividends or distributions of Common Stock on
Common Stock to which Section 1406(a) applies) of the Company,
evidences of indebtedness or other assets (including securities of any
Person other than the Company, but excluding all-cash distributions or
any distribution of rights or warrants referred to in 1406(b), any of
the foregoing in respect of which an adjustment would be made pursuant
to this Section 1406(c) and referred to as the "Described Securities"),
then in each such case (unless the Company elects to reserve Described
Securities for distribution to Holders of 2021 Debentures upon
conversion of same so that any such Holder would receive upon such
conversion, in addition to the shares of Common Stock (and cash in lieu
of fractional shares, if any) to which such Holder is entitled, the
amount and kind of Described Securities that such Holder would have
received if such Holder had converted its 2021 Debenture(s) into Common
Stock immediately prior to the record date for distribution of the
Described Securities) the Conversion Rate shall be adjusted so that the
same shall equal the
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rate determined by multiplying the current Conversion Rate by a
fraction, of which the numerator shall be the current market price per
share (as determined in accordance with Section 1406(e)) of the Common
Stock on the record date referred to below, and of which the
denominator shall be the current market price per share (as determined
in accordance with Section 1406(e)) of the Common Stock on such record
date less the fair market value on such record date (as determined by
the Board of Directors, whose determination shall be conclusive
evidence absent manifest error of such fair market value and which
shall be evidenced by an Officer's Certificate delivered to the
Trustee) of the portion of the Described Securities so distributed or
of such rights or warrants applicable to one share of Common Stock
(determined on the basis of the number of shares of Common Stock
outstanding on the record date); provided, however, that if the then
fair market value (as so determined) of the portion of the Described
Securities so distributed applicable to one share of Common Stock is
equal to or greater than the current market price (determined as
aforesaid) of the Common Stock on the record date referred to below,
in lieu of the foregoing adjustment, adequate provision shall be made
so that each Holder of 2021 Debentures shall have the right to receive
upon conversion the amount of Described Securities such Holder would
have received had such Holder converted each 2021 Debenture on such
Record Date. Such adjustment shall be made successively whenever any
such distribution is made and shall become effective immediately after
the record date for the determination of stockholders entitled to
receive such distribution.
If the Rights Agreement expires or is terminated and, while any of the
2021 Debentures remain Outstanding, the Company implements another
shareholder rights plan, such rights plan shall provide, subject to
customary exceptions and limitations, that in lieu of making an
adjustment of the Conversion Rate pursuant to this Section 1406(c) in
respect of rights distributed under such other shareholder rights plan,
upon conversion of the 2021 Debentures the Holders will receive, in
addition to the Common Stock issuable upon such conversion, the rights
issued under such rights plan (notwithstanding the occurrence of an
event causing such rights to separate from the Common Stock at or prior
to the time of conversion). Any distribution of rights or warrants
pursuant to a shareholder rights plan complying with the requirements
set forth in the immediately preceding sentence of this paragraph shall
not constitute a distribution of rights or warrants for which an
adjustment is to be made pursuant to this Section 1406(c).
Rights or warrants distributed after the date hereof by the Company to
all holders of Common Stock entitling the holders thereof to subscribe
for or purchase shares of the Company's capital stock (either initially
or under certain circumstances), which rights or warrants, until the
occurrence of a specified event or events ("Trigger Event"): (i) are
deemed to be transferred with such shares of Common Stock; (ii) are not
exercisable; and (iii) are also issued in respect of future issuances
of Common Stock, shall be deemed not to have been distributed for
purposes of this Section 1406(c) (and no adjustment to the Conversion
Rate under this Section 1406(c) will be required) until the occurrence
of the earliest Trigger Event. If such right or warrant is subject to
subsequent events, upon the
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occurrence of which such right or warrant shall become exercisable to
purchase different securities, evidences of indebtedness or other
assets or entitle the holder to purchase a different number or amount
of the foregoing or to purchase any of the foregoing at a different
purchase price, then the occurrence of each such event shall be deemed
to be the date of issuance and record date with respect to a new right
or warrant (and a termination or expiration of the existing right or
warrant without exercise by the holder thereof). In addition, if (1)
any distribution (or deemed distribution) of rights or warrants, or
any Trigger Event or other event (of the type described in the
preceding sentence) with respect thereto, resulted in an adjustment to
the Conversion Rate under this Section 1406(c) and (2)(A) all such
rights or warrants shall thereafter have been redeemed or repurchased
without exercise by any holders thereof, then the Conversion Rate
shall be readjusted upon such final redemption or repurchase to give
effect to such distribution or Trigger Event, as the case may be, as
though it were a cash distribution, equal to the per share redemption
or repurchase price received by a holder of Common Stock with respect
to such rights or warrants (assuming such holder had retained such
rights or warrants), made to all holders of Common Stock as of the
date of such redemption or repurchase, or (2) all of such rights or
warrants shall thereafter have expired or been terminated without
exercise, the Conversion Rate shall be readjusted as if such rights
and warrants had never been issued.
(d) (1) If the Company shall, by dividend or otherwise, at any
time distribute (a "Triggering Distribution") to all or substantially
all holders of its Common Stock all-cash distributions in an aggregate
amount that, together with the aggregate sum of (A) any cash and the
fair market value (as determined by the Board of Directors, whose
determination shall be conclusive evidence thereof and which shall be
evidenced by an Officer's Certificate delivered to the Trustee) of any
other consideration payable in respect of any tender offer (other than
an odd-lot offer) by the Company or a Subsidiary of the Company for
Common Stock consummated within the 12 months preceding the date of
payment of the Triggering Distribution and in respect of which no
Conversion Rate adjustment pursuant to this Section 1406 has been made
and (B) all other cash distributions to all or substantially all
holders of its Common Stock made within the 12 months preceding the
date of payment of the Triggering Distribution and in respect of which
no Conversion Rate adjustment pursuant to this Section 1406 has been
made, exceeds an amount equal to 12.5% of the product (the amount of
such product, the "Permitted Amount") of (I) the current market price
per share of Common Stock (as determined in accordance with Section
1406(e)) on the Business Day (the "Determination Date") immediately
preceding the day on which such Triggering Distribution is declared by
the Company multiplied by (III) the number of shares of Common Stock
outstanding on the Determination Date (excluding shares held in the
treasury of the Company), then, immediately prior to the opening of
business on the day following the date on which the Triggering
Distribution is paid, the Conversion Rate shall be increased so that
the same shall equal the rate determined by multiplying such Conversion
Rate in effect immediately prior to the Determination Date by a
fraction, of which the numerator shall be such current market price per
share of Common Stock (as determined in accordance with Section
1406(e)) on the Determination Date, and of which the denominator shall
be the current market price per share of Common Stock (as
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determined in accordance with Section 1406(e)) on the Determination
Date less the sum of the aggregate amount of cash and the aggregate
fair market value (determined as aforesaid) of any such other
consideration so distributed, paid or payable within such 12 months
(including, without limitation, the Triggering Distribution)
applicable to one share of Common Stock (determined on the basis of
the number of shares of Common Stock outstanding on the Determination
Date) (such amount, the "Adjustment Amount"); provided, however, that
if the Adjustment Amount is equal to or greater than the current
market price (determined in accordance with Section 1406(e)) of the
Common Stock on the Determination Date, in lieu of the foregoing
adjustment to the Conversion Rate, adequate provision shall be made so
that each Holder of 2021 Debentures shall have the right to receive
upon conversion the amount of cash such Holder would have received had
such Holder converted each 2021 Debenture on the record date for such
distribution.
(2) If any tender offer (other than an odd-lot offer) made by
the Company or any of its Subsidiaries for Common Stock shall expire
and such tender offer (as amended upon the expiration thereof) shall
involve the payment of aggregate consideration in an amount (determined
as the sum of the aggregate amount of cash consideration and the
aggregate fair market value (as determined by the Board of Directors,
whose determination shall be conclusive evidence thereof and which
shall be evidenced by an Officer's Certificate delivered to the Trustee
thereof ) of any other consideration) that, together with the aggregate
sum of (A) any cash and the fair market value (as determined by the
Board of Directors, whose determination shall be conclusive evidence
thereof and which shall be evidenced by an Officer's Certificate
delivered to the Trustee) of any other consideration payable in respect
of any other tender offers (other than an odd-lot offer(s)) by the
Company or any Subsidiary of the Company for Common Stock consummated
within the 12 months preceding the Expiration Date (as defined below)
and in respect of which no Conversion Rate adjustment pursuant to this
Section 1406 has been made and (B) all cash distributions to all or
substantially all holders of its Common Stock made within the 12 months
preceding the Expiration Date and in respect of which no Conversion
Rate adjustment pursuant to this Section 1406 has been made, exceeds an
amount equal to 12.5% of the product (the amount of such product, the
"Permitted Amount") of the current market price per share of Common
Stock (as determined in accordance with Section 1406(e)) as of the last
date (the "Expiration Date") tenders could have been made pursuant to
such tender offer (as it may be amended) (the last time at which such
tenders could have been made on the Expiration Date is hereinafter
sometimes called the "Expiration Time") multiplied by the number of
shares of Common Stock outstanding (including tendered shares but
excluding any shares held in the treasury of the Company) at the
Expiration Time, then, immediately prior to the opening of business on
the day after the Expiration Date, the Conversion Rate shall be
increased so that the same shall equal the rate determined by
multiplying the Conversion Rate in effect immediately prior to the
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close of business on the Expiration Date by a fraction, of which the
numerator shall be the sum of (x) the aggregate consideration
(determined as aforesaid) payable to stockholders based on the
acceptance (up to any maximum specified in the terms of the tender
offer) of all shares validly tendered and not withdrawn as of the
Expiration Time (the shares deemed so accepted, up to any such maximum,
being referred to as the "Purchased Shares") and (y) the product of the
number of shares of Common Stock outstanding (excluding any Purchased
Shares and any shares held in the treasury of the Company) at the
Expiration Time and the current market price per share of Common Stock
(as determined in accordance with Section 1406(e)) on the Trading Day
next succeeding the Expiration Date, and of which the denominator shall
be the product of the number of shares of Common Stock outstanding
(including tendered shares but excluding any shares held in the
treasury of the Company) at the Expiration Time multiplied by the
current market price per share of Common Stock (as determined in
accordance with Section 1406(e)) on the Trading Day next succeeding the
Expiration Date, such increase to become effective immediately prior to
the opening of business on the day following the Expiration Date. If
the Company is obligated to purchase shares pursuant to any such tender
offer, but the Company is permanently prevented by applicable law from
effecting any or all such purchases or any or all such purchases are
rescinded, the Conversion Rate shall again be adjusted to be the
Conversion Rate which would have been in effect based upon the number
of shares actually purchased. If the application of this Section
1406(d)(2) to any tender offer would result in a decrease in the
Conversion Rate, no adjustment shall be made for such tender offer
under this Section 1406(d)(2).
(3) For purposes of this Section 1406(d), the term "tender
offer" shall mean and include both tender offers and exchange offers,
all references to "purchases" of shares in tender offers (and all
similar references) shall mean and include both the purchase of shares
in tender offers and the acquisition of shares pursuant to exchange
offers, and all references to "tendered shares" (and all similar
references) shall mean and include shares tendered in both tender
offers and exchange offers.
(e) For the purpose of any computation under Sections 1406(b),
1406(c) and 1406(d), the current market price per share of Common Stock
on any date shall be deemed to be the average of the daily closing
prices for the 30 consecutive Trading Days commencing 45 Trading Days
before (i) the Determination Date or the Expiration Date, as the case
may be, with respect to distributions or tender offers under Section
1406(d) or (ii) the record date with respect to distributions,
issuances or other events requiring such computation under Section
1406(b) or Section 1406(c). The closing price for each day shall be the
last reported sales price (regular way) or, in case no such reported
sale takes place on such date, the average of the reported closing bid
and asked prices in either case on the New York Stock Exchange (the
"NYSE") or, if the Common Stock is not listed or admitted to trading on
the NYSE, on the principal national securities exchange on which the
Common Stock is listed or admitted to trading or, if not listed or
admitted to trading on any national securities exchange, the last
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reported sales price of the Common Stock as quoted on Nasdaq (the term
"Nasdaq" shall include, without limitation, the Nasdaq National Market)
or, if no reported sales takes place, the average of the closing bid
and asked prices as quoted on Nasdaq or any comparable system or, if
the Common Stock is not quoted on Nasdaq or any comparable system, the
closing sales price or, in case no reported sale takes place, the
average of the closing bid and asked prices, as furnished by any two
members of the National Association of Securities Dealers, Inc.
selected from time to time by the Company for that purpose. If no such
prices are available, the current market price per share shall be the
fair value of a share of Common Stock as determined by the Board of
Directors (which shall be evidenced by an Officer's Certificate
delivered to the Trustee).
(f) In any case in which this Section 1406 shall require that
an adjustment be made following a record date or a Determination Date
or Expiration Date, as the case may be, established for purposes of
this Section 1406, the Company may elect to defer (but only until five
Business Days following the filing by the Company with the Trustee of
the certificate described in Section 1409) issuing to the Holder of any
2021 Debenture converted after such record date or Determination Date
or Expiration Date the shares of Common Stock and other capital stock
of the Company issuable upon such conversion over and above the shares
of Common Stock and other capital stock of the Company issuable upon
such conversion only on the basis of the Conversion Rate prior to
adjustment; and, in lieu of the shares the issuance of which is so
deferred, the Company shall issue or cause its transfer agents to issue
due bills or other appropriate evidence prepared by the Company of the
right to receive such shares. If any distribution in respect of which
an adjustment to the Conversion Rate is required to be made as of the
record date or Determination Date or Expiration Date therefor is not
thereafter made or paid by the Company for any reason, the Conversion
Rate shall be readjusted to the Conversion Rate that would then be in
effect if such record date had not been fixed or such effective date or
Determination Date or Expiration Date had not occurred.
SECTION 1407 No Adjustment.
No adjustment in the Conversion Rate shall be required unless the
adjustment would require an increase or decrease of at least 1% in the
Conversion Rate as last adjusted; provided, however, that any
adjustments which by reason of this Section 1407 are not required to be
made shall be carried forward and taken into account in any subsequent
adjustment. All calculations under this Article FOURTEEN shall be made
to the nearest cent or to the nearest 1/1000th of a share, as the case
may be.
No adjustment need be made for issuances of Common Stock pursuant to
(a) any Company plan for reinvestment of dividends or interest or (b)
any Company employee or director benefit or compensation plan, or for a
change in the par value or a change to no par value of the Common
Stock.
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To the extent that the 2021 Debentures become convertible into the
right to receive cash, no adjustment need be made thereafter as to the
cash. Interest will not accrue on the cash.
SECTION 1408 Adjustment for Tax Purposes.
The Company shall be entitled to make such adjustments in the
Conversion Rate, in addition to those required by Section 1406, as it
in its discretion shall determine to be advisable in order that any
stock dividends, subdivisions of shares, distributions of rights to
purchase stock or securities or distributions of securities convertible
into or exchangeable for stock hereafter made by the Company to its
stockholders shall not be taxable.
SECTION 1409 Notice of Adjustment.
Whenever th